Entergy Texas, Inc. v. Public Utility Commission of Texas, Office of Public Utility Counsel, and State of Texas Agencies and Institutions of Higher Education ( 2015 )

ACCEPTED
03-14-00706-CV
5038192
THIRD COURT OF APPEALS
AUSTIN, TEXAS
4/27/2015 10:27:46 AM
JEFFREY D. KYLE
CLERK
No. 03-14-00706-CV
IN THE FILED IN
3rd COURT OF APPEALS
THIRD DISTRICT COURT OF APPEALS AUSTIN, TEXAS
AT AUSTIN, TEXAS 4/27/2015 10:27:46 AM
JEFFREY D. KYLE
ENTERGY TEXAS, INC., Clerk
Appellant,
v.
PUBLIC UTILITY COMMISSION OF TEXAS, ET AL.,
Appellees.
Appeal from the 345th Judicial District Court, Travis County, Texas
The Honorable Amy Clark Meachum, Judge Presiding
________________________________________________________________
APPELLANT’S REPLY BRIEF
_________________________________________________________________
John F. Williams
State Bar No. 21554100
jwilliams@dwmrlaw.com
Marnie A. McCormick
State Bar No. 00794264
mmccormick@dwmrlaw.com
DUGGINS WREN MANN & ROMERO, LLP
600 Congress Ave., Ste. 1900 (78701)
P. O. Box 1149
Austin, Texas 78767-1149
(512) 744-9300
(512) 744-9399 fax
ATTORNEYS FOR APPELLANT
ENTERGY TEXAS, INC.
ORAL ARGUMENT REQUESTED
April 2015
TABLE OF CONTENTS
TABLE OF CONTENTS ........................................................................................... i
INDEX OF AUTHORITIES.................................................................................... iii
STATEMENT OF FACTS ........................................................................................1
SUMMARY OF ARGUMENT .................................................................................1
ARGUMENT AND AUTHORITIES ........................................................................3
I.  Discretion alone does not justify the Commission’s decision.........................3
II.  The Court may not sustain the Commission’s decision upon the theory
that ETI’s total rate case expenses were “too high” or that ETI
wantonly incurred expenses.............................................................................6
A.  The Commission did not find that ETI’s expenses were
excessive or that ETI files rate cases too frequently. ............................6
B.  The Court cannot sustain the Commission’s decision upon an
unarticulated factual theory. ................................................................10
III.  The Commission’s disallowance of ETI’s costs of litigating the
incentive compensation issue is arbitrary and capricious and an abuse
of discretion. ..................................................................................................12
A.  The Commission’s finding that ETI made an unreasonable
argument in the underlying rate case is arbitrary and capricious........12
B.  Regardless, the Commission’s decision is reversibly wrong on
procedural grounds. .............................................................................16
1.  The Commission changed its past practice without
explanation or advance notice...................................................16
2.  Additionally, the Commission effectively and improperly
adopted a new rule in this contested case. ................................21
IV.  The Commission further erred in quantifying its disallowance of
ETI’s expenses of seeking to include financially-based incentive
compensation in rates. ...................................................................................24
i
V.  The Commission’s disallowance of depreciation expense associated
with ESI’s efforts in the rate case is not supported by any evidence
and is arbitrary and capricious. ......................................................................27
CONCLUSION AND PRAYER .............................................................................31
CERTIFICATE OF COMPLIANCE .......................................................................32
CERTIFICATE OF SERVICE ................................................................................33
APPENDICES .........................................................................................................34
ii
INDEX OF AUTHORITIES
Cases
Bowman Transportation, Inc. v. Arkansas-Best Freight System, Inc.,
419 U.S. 281, 95 S. Ct. 438, 42 L. Ed. 2d 447 (1974) ............................................15
CenterPoint Energy Entex v. Railroad Comm’n of Tex.,
213 S.W.3d 364 (Tex. App. – Austin 2006, no pet.)...........................................27
Citizens to Preserve Overton Park v. Volpe,
401 U.S. 402, 91 S. Ct. 814, 28 L. Ed. 2d 136 (1971) ............................................14
City of El Paso v. El Paso Elec. Co.,
851 S.W.2d 896 (Tex. App. – Austin 1993, writ denied) ............................. 11, 28
City of El Paso v. Public Util. Comm’n of Tex.,
883 S.W.2d 179 (Tex. 1994) ..................................................................................4
City of El Paso v. Public Util. Comm’n of Tex.,
916 SW.2d 515 (Tex. App. – Austin 1995, writ dism’d by agr.)...........................5
City of Port Neches v. Railroad Comm’n of Tex.,
212 S.W.3d 565 (Tex. App. – Austin 2006, no pet.) .............................................5
Continental Imports, Ltd. v. Brunke,
No. 03-10-00719-CV, 2011 WL 6938489 *5
(Tex. App. – Austin Dec. 30, 2011, pet. denied) .......................................... 11, 28
Downer v. Aquamarine Operators, Inc.,
701 S.W.2d 238 (Tex. 1985) ..................................................................................3
Entergy Gulf States, Inc. v. Public Util. Comm’n of Tex.,
173 S.W.3d 199 (Tex. App. – Austin 2005, pet. denied) ............................. 23, 24
Flores v. Employees Ret. Sys.,
74 S.W.3d 532 (Tex. App. – Austin 2002, pet. denied) .........................................4
Goeke v. Houston Lighting & Power Co.,
797 S.W.2d 12 (Tex. 1990) ..................................................................................11
Hendee v. Dewhurst,
228 S.W.3d 354 (Tex. App. -- Austin 2007, pet. denied) ....................................17
Industrial Utils. Serv. Co. v. Texas Natural Resources Conservation
Comm’n,
947 S.W.2d 712 (Tex. App. – Austin 1997, no writ) .................................... 20, 21
Lewis v. Metropolitan Savings & Loan Association,
550 S.W.2d 11 (Tex. 1977) ..................................................................................14
iii
McHaney v. Texas Comm’n on Environmental Quality,
No. 03-13-00280-CV, 2015 WL 869197 at *8 (Tex. App. – Austin
Feb. 27, 2015, no pet. h.) ......................................................................................22
Morgan Drive Away, Inc. v. Railroad Comm'n of Tex.,
498 S.W.2d 147 (Tex. 1973) ......................................................................... 11, 28
Office of Pub. Util. Counsel v. Public Util. Comm'n,
878 S.W.2d 598 (Tex. 1994) ................................................................................17
Oncor Elec. Delivery Co. v. Public Util. Comm’n of Tex.,
406 S.W.3d 253 (Tex. App. – Austin 2013, no pet.)................................ 4, 17, 19
Pioneer Natural Resources USA, Inc. v. Public Util. Comm’n of Tex.,
303 S.W.3d 363 (Tex. App. – Austin 2009, no pet.) ...................................... 5, 26
Professional Mobile Home Transport v. Railroad Comm’n,
733 S.W.2d 892 (Tex. App. – Austin 1987, writ ref’d n.r.e.) ....................... 12, 28
Railroad Commission of Texas v. Lone Star Gas Co.,
611 S.W.2d 908 (Tex. Civ. App. – Austin 1981, writ ref’d n.r.e.) ......................15
Starr County v. Starr Indus. Services, Inc.,
584 S.W.2d 352 (Tex. App. -- Austin 1979, writ ref’d n.r.e.) ...................... 14, 15
State of Texas’ Agencies & Institutions of Higher Learning v. Public Util.
Comm’n of Tex.,
450 S.W.3d 615 (Tex. App. – Austin 2014, pet. filed) ........................................13
Suburban Util. Corp. v. Public Util. Comm'n,
652 S.W.2d 358 (Tex.1983) ...................................................................................5
Texas Bd. of Pharmacy v. Witcher,
447 S.W.3d 520 (Tex. App. – Austin 2014, pet. requested) ..................................4
Texas Health Facilities Comm’n v. Charter Medical-Dallas, Inc.,
665 S.W.2d 446 (Tex. 1984) ........................................................................... 4, 10
Texas Medical Association v. Mathews,
408 F. Supp. 303 (W.D. Tex. 1976) ......................................................................15
Vista Medical Center Hosp. v. Texas Mut. Ins. Co.,
416 S.W.3d 11 (Tex. App. – Austin 2013, no pet.)....................................... 10, 27
Statutes
Tex. Gov’t Code Ann. § 2001.141 .................................................................... 10, 27
Tex. Gov’t Code Ann. § 2001.174.............................................................................3
iv
Tex. Util. Code Ann. § 36.051 ........................................................................ 5, 9, 27
Tex. Util. Code Ann. § 36.058 .................................................................................30
Tex. Util. Code Ann. § 36.061 .................................................................... 3, 5, 6, 27
Tex. Util. Code Ann. § 36.203 ...................................................................................9
Other Authorities
5 B. Mezines, J. Stein and J. Gruff, Administrative Law § 51.03 (1979) ...............15
Rules
Tex. R. Civ. Evid. 201 .............................................................................................17
Administrative Cases
Application of AEP Texas Central Co. for Authority to Change Rates,
Docket No. 28840 .................................................................................... 17, 25, 26
Application of AEP Texas Central Co. for Authority to Change Rates,
Docket No. 33309 .................................................................................................17
Application of CenterPoint Energy Houston Electric, LLC for Authority
Change Rates, Docket No. 38339 ........................................................................18
Application of Entergy Gulf States, Inc. for Authority to Change Rates and
to Reconcile Fuel Costs, Docket No. 34800 ....................................... 9, 10, 16, 18
Application of Entergy Texas, Inc. for Authority to Change Rates and
Reconcile Fuel Costs, Docket No. 37744 ........................................... 9, 10, 16, 18
Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile
Fuel Costs, and Obtain Deferred Accounting Treatment,
Docket No. 39896 ......................................................................................... passim
Application of Oncor Electric Delivery Co. LLC for Authority to Change
Rates, Docket No. 35717 ......................................................................................18
Application of Southwestern Electric Power Co. for Authority to Change
Rates and Reconcile Fuel Costs, Docket No. 40443............................................18
Proceeding to Consider Rate Case Expenses Severed from Docket No.
28840 (Application of AEP Texas Central Company for Authority to
Change Rates), Docket No. 31433 .......................................................................25
v
STATEMENT OF FACTS
Entergy Texas, Inc. (“ETI”) does not dispute the statements of fact
submitted by the Public Utility Commission of Texas (“PUCT” or “Commission”),
Office of Public Utility Counsel (“OPUC”), and State Agencies, save in a few
respects. Specifically, ETI disputes the Attorney General’s argumentative
characterization of ETI’s request concerning financially-based incentive
compensation in the underlying rate case, and of the way financially-based
incentive compensation has been treated in past PUCT dockets. ETI also disputes
the suggestion of OPUC and the Attorney General that the Commission found
ETI’s rate case expenses to be “excessive.” ETI discusses these factual
inaccuracies more fully below.
SUMMARY OF ARGUMENT
The Commission’s disallowance of over $522,000 for ETI’s effort to recover
incentive compensation expense is arbitrary and capricious for several reasons.
The contours of the incentive compensation issue have never been defined, ETI’s
argument in the rate case was not materially different from what ETI and other
utilities have argued in the past, and ETI actually prevailed on the issue in part. In
light of these facts, the Commission’s characterization of ETI’s advocacy as
unreasonable is itself unreasonable.
1
More important, the Commission has consistently allowed utilities,
including ETI, to recover the expenses of seeking incentive compensation, even
when the utilities have been unsuccessful. The Commission has never before said
it is unreasonable to incur expense to litigate the incentive compensation issue or
any other “long shot” issue. The Commission’s abrupt policy change, without
even an acknowledgement of its historical treatment of advocacy costs, at the end
of this case, after ETI had already incurred its costs, is arbitrary and capricious and
an abuse of discretion.
This abuse is further manifest in the Commission’s quantification of the
disallowance. The Commission employed a “proxy” for the amount of expense
ETI incurred to litigate the incentive compensation issue, faulting ETI for failing to
track all of its expenses by issue. But again, the Commission has never before
disallowed the entire expense of litigating a single issue in a rate case, certainly not
the incentive compensation issue. That is why utilities have not recorded their
expenses by issue. If the Commission wanted to impose these new standards, it
could and should have done so on a prospective basis. The Commission’s decision
to impose the new standards at the end of this case, contrary to the way the agency
has historically handled the issue, should be reversed.
So should the Commission’s disallowance of over $207,000 in depreciation
expense associated with ESI’s efforts on the rate case. The Commission said only
2
that this expense was “unreasonable,” without identifying any fact underlying that
ultimate finding. Moreover, there is abundant and undisputed record evidence that
ESI’s costs were reasonable, necessary, and fairly charged to ETI and its other
affiliates. None of the Attorney General’s arguments presents a legitimate basis
upon which to affirm the Commission’s decision, and it should be reversed.
ARGUMENT AND AUTHORITIES
Two themes run throughout appellees’ briefs. ETI will address those first,
and then turn to specific issues.
I. Discretion alone does not justify the Commission’s decision.
Appellees attempt to justify the Commission’s decision principally by
asserting that the Commission has discretion in awarding rate case expenses under
Public Utility Regulatory Act (“PURA”) section 36.061(b)(2). See Tex. Util. Code
Ann. § 36.061(b)(2). The Commission does have some measure of discretion, but
that alone cannot justify its decision here. The Commission must adhere to
applicable “guiding” principles in exercising its discretion. Tex. Gov’t Code Ann.
§ 2001.174(2)(F); Downer v. Aquamarine Operators, Inc., 701 S.W.2d 238, 241-
42 (Tex. 1985).
One of the fundamental principles of administrative law is that an agency is
bound to make decisions based upon a full consideration of the evidence and a
serious appraisal of the facts. E.g., Texas Health Facilities Comm’n v. Charter
3
Medical-Dallas, Inc., 665 S.W.2d 446, 452 (Tex. 1984). Another is that an agency
is not absolutely bound to follow its decisions in previous cases in the same way a
court must follow controlling precedent. E.g., Oncor Elec. Delivery Co. v. Public
Util. Comm’n of Tex., 406 S.W.3d 253, 267 (Tex. App. – Austin 2013, no pet.)
(citing Flores v. Employees Ret. Sys., 74 S.W.3d 532, 544-45 (Tex. App. – Austin
2002, pet. denied)). Another guiding principle is that parties to contested cases are
entitled to advance notice of what is expected of them in the administrative
process. E.g., Oncor Elec. Delivery Co., 406 S.W.3d at 268-69; Flores, 74 S.W.3d
at 545. A related rule is that an agency is bound to impose a new policy upon
regulated entities via the formal rulemaking process unless the issue is of first
impression, flows from an amended statute or rule, or cannot be adequately
captured within the bounds of a general rule because the problem is so specialized
in nature. E.g., City of El Paso v. Public Util. Comm’n of Tex., 883 S.W.2d 179,
188-89 (Tex. 1994); Texas Bd. of Pharmacy v. Witcher, 447 S.W.3d 520, 534 (Tex.
App. – Austin 2014, pet. requested).
In addition to these basic principles applicable to all administrative cases,
PURA includes principles that specifically pertain to the Commission’s decisions
on rate case expense recovery. Appellees cite cases that correctly observe that
4
PURA section 36.061(b)(2) affords the agency some discretion in determining
what expenses should be allowed.1 However, as this Court recently noted:
Although section 36.061(b)(2) gives the Commission the discretion to
disallow improper expenses, this discretion is tempered by section
36.051’s mandate that the utility must be allowed to recover its
operating expenses and a reasonable return on invested capital ... If
the expense can be shown to be actual, necessary and reasonable it
should be allowed.
Oncor Elec. Delivery Co., 406 S.W.3d at 264 (citing Suburban Util. Corp. v.
Public Util. Comm'n, 652 S.W.2d 358, 362–63 (Tex.1983)). In other words, the
Commission does not have the discretion to disallow rate case expenses that are
reasonably incurred.2 Appellees’ repeated suggestion that the Commission’s
discretion effectively insulates its decision from meaningful review is flat wrong.
1
See Tex. Util. Code Ann. § 36.061(b)(2), cited in City of El Paso v. Public Util. Comm’n of
Tex., 916 SW.2d 515, 522 (Tex. App. – Austin 1995, writ dism’d by agr.), Pioneer Natural
Resources USA, Inc. v. Public Util. Comm’n of Tex., 303 S.W.3d 363, 377 (Tex. App. – Austin
2009, no pet.), & Oncor Elec. Delivery Co. LLC v. Public Util. Comm’n, 406 S.W.3d 253, 264
(Tex. App. – Austin 2013, no pet.).
2
The testimony of OPUC’s witness Nathan Benedict ignores the impact of PURA section 36.051
on rate case expense recovery. See AR Part II, Binder 3, OPUC Exh. 1 (Direct Testimony of N.
Benedict at 4). So do appellee’s briefs. OPUC cites City of Port Neches v. Railroad Comm’n of
Tex., 212 S.W.3d 565 (Tex. App. – Austin 2006, no pet.) for the proposition that the agency may
disallow reasonable expenses. See OPUC’s Brief at 16. That case, discussing rate case expense
recovery under the Gas Utilities Regulatory Act, does not say reasonable rate case expenses may
be disallowed. It says even though a particular underlying cost of service is determined to be
reasonable, the utility’s expense of seeking recovery of that cost is not “automatically” or “as a
matter of law” deemed reasonable. City of Port Neches, 212 S.W.3d at 581. In other words, the
reasonableness of a utility’s rate case expenses is a fact question separate from the
reasonableness of a utility’s underlying cost of service. City of Port Neches undermines the
Commission’s decision here, where the Commission made the “impermissible leap” that the
reasonableness of an underlying cost of service automatically controls the reasonableness of
related rate case expenses.
5
This case implicates all of the principles set forth above. The Commission
does not avoid their application simply because it has some discretion in applying
PURA section 36.061(b)(2).
II. The Court may not sustain the Commission’s decision upon the theory
that ETI’s total rate case expenses were “too high” or that ETI
wantonly incurred expenses.
Appellees also contend that the Commission’s decision was based upon a
finding that ETI’s total expense for prosecuting Docket No. 39896 was “excessive”
or “unusually high.” The Commission’s order, though, confirms that this was not
the basis of the disallowance ETI challenges here.
A. The Commission did not find that ETI’s expenses were
excessive or that ETI files rate cases too frequently.
The Administrative Law Judge (“ALJ”), in the proposal for decision
(“PFD”) that was adopted by the Commission, recognized that Docket No. 39896
was complex and labor intensive. He noted that ETI presented 39 witnesses, who
discussed hundreds of categories of costs, and that while ETI used the services of
12 attorneys, the other parties and Staff were represented by a total of 15
attorneys.3
3
AR Part I, Binder 2, Item 32 (PFD at 17); AR Part I, Binder 2, Item 55 (Final Order at 1)
(adopting PFD).
6
Though the ALJ and Commission found that the expenses of the case were
“high,” they did not find that the expenses were too high.4 Nor did they reduce
ETI’s expense recovery based upon any finding or conclusion that the total was
unreasonable. Rather, the ALJ and Commission expressly rejected OPUC’s and
State Agencies’ theories that ETI’s expenses should be reduced on bases other than
an “issue-specific” approach.5
In support of their arguments that ETI’s total expenses were unreasonable,
State Agencies and OPUC criticized many categories of ETI’s costs. The ALJ
discussed and expressly rejected most of those criticisms, finding that:
 State Agencies’ challenge to ETI witness Gerald Tucker’s testimony
was “overly simplistic”;6
 State Agencies’ proposal to disallow the expenses of a “lessons
learned” memo would encourage inefficiency;7
 State Agencies’ challenge of miscellaneous internal rate case expenses
should be rejected because ETI proved “in great detail” that they were
reasonable;8
 ETI had “the better argument” on OPUC’s challenge to expenses
associated with the Calpine-Carville purchased power agreement;9
4
AR Part I, Binder 2, Item 32 (PFD at FOF 17); AR Part I, Binder 2, Item 55 (Final Order at
FOF 17).
5
AR Part I, Binder 2, Item 32 (PFD at 31-32); AR Part I, Binder 2, Item 55 (Final Order at 2).
6
AR Part I, Binder 2, Item 32 (PFD at 9).
7
Id. at 10-11.
8
Id. at 13.
9
Id. at 14-15.
7
 he was “unswayed” by State Agencies’ criticism of ETI’s expert’s
review of outside legal fees; the external “legal costs involved do not
appear to be inordinate”;10
 meal, courier, and taxi expenses were a reasonable part of prosecuting
the laborious rate case;11
 State Agencies’ identification of “relatively few errors” in
categorizing meal expenses does not lead to doubt about the overall
accuracy of ETI’s accounting;12 and
 State Agencies’ challenge to airfare and lodging expense was “vague”
and “unproven”.13
The Commission adopted the ALJ’s resolution of all these issues.14 The
Commission also refused to accept the ALJ’s recommendation that another
category of expense, associated with ETI’s advocacy concerning transmission
equalization costs, should be disallowed.15
The Commission ultimately disallowed only a few discrete categories of
expense, for reasons specific to those categories.16 Regarding the category at issue
here, the Commission gave only one reason for the disallowance: “for Entergy
attempting to recover financially-based incentive compensation in base rates.”17 It
10
Id. at 17.
11
Id. at 18-19.
12
Id. at 19.
13
Id. at 21.
14
AR Part I, Binder 2, Item 55 (Final Order at 1).
15
Id. at 3.
16
Id. at 2-3 & FOF 18.
17
Id. at 2.
8
is incorrect to suggest in this appeal that the Commission disallowed any expenses
on the basis that the grand total was unreasonably high.
It is also incorrect to suggest that the Commission disallowed any expenses
based on the purported “frequency” of ETI’s recent rate cases. There is no legal or
factual support for the parties’ intimation that ETI files rate cases with
unreasonable frequency. The frequency of rate cases is cost-driven.18 PURA
guarantees an electric utility rates that afford it a reasonable opportunity to recover
a reasonable return on its investment, and to recover its reasonable and necessary
expenses. Tex. Util. Code Ann. § 36.051. Expenses, which change over time, are
largely recovered through base rates.19 The only Commission-approved way for an
electric utility to capture changes in its overall level of base-rate expense is to file a
rate case.
In the previous ETI rate cases mentioned in appellees’ briefs, the
Commission granted ETI substantial base-rate increases and expressly found that
the increases were just and reasonable. See Application of Entergy Gulf States,
Inc. for Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800
(Mar. 16, 2009, Order at FOFs 24 & 45 & COL 7); Application of Entergy Texas,
Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744
18
AR Part II, Binder 3, ETI Exh. 7 (Considine Rebuttal at 5).
19
Some categories of expense, like fuel expenses, are recovered through other methods. Tex.
Util. Code Ann. § 36.203. Those categories of expense are not at issue in this case.
9
(Dec. 13, 2010, Order at FOFs 16 & 35 & COL 7). Any suggestion that ETI was
unjustified in pursuing those increases is, therefore, unfounded. So is any
suggestion that it was unfair for ratepayers to pay the expenses of pursuing those
cost increases. The Commission expressly found that the expenses of pursuing
those rate cases were just and reasonable. See Docket No. 34800, supra (Feb. 5,
2009, Order at FOF 27 & 45 & COL 7); Docket No. 37744, supra (Dec. 13, 2010,
Order at FOFs 18 & 43 & COL 7). In any event, ETI’s pursuit of its statutorily-
guaranteed opportunity to recover its costs in the past has no bearing on this case.
The Commission did not make any finding that it does.
Simply put, the parties invite the Court to affirm the Commission’s
disallowance of expenses by relying on contested factual theories that the
Commission did not accept or rely on. The Court should not accept the invitation.
B. The Court cannot sustain the Commission’s decision upon
an unarticulated factual theory.
An agency is required to make findings on any factual theory underlying its
decision. Tex. Gov’t Code Ann. § 2001.141(b) & (d). Those findings must
provide a logical link between the facts and the agency’s application of a statutory
standard. E.g., Vista Medical Center Hosp. v. Texas Mut. Ins. Co., 416 S.W.3d 11,
26 (Tex. App. – Austin 2013, no pet.) (citing Texas Health Facilities Comm'n v.
Charter Med.-Dallas, Inc., 665 S.W.2d 446, 453 (Tex.1984)). The purpose of this
requirement is to inform the parties and the courts of the basis for the agency's
10
decision so that the parties may intelligently prepare an appeal and so that the
courts may properly exercise their function of review. E.g., Goeke v. Houston
Lighting & Power Co., 797 S.W.2d 12, 15 (Tex. 1990). It is ironic, then, that
OPUC faults ETI for failing to challenge the Commission’s observation that ETI’s
expenses were “high.”20 ETI did not challenge that finding because there is no
indication in the Commission’s order that the observation was a basis for any
disallowance.
Because the Commission did not articulate that the two disallowances at
issue here were based upon a conclusion that ETI’s expenses were “excessive,” the
Commission’s order cannot be sustained on this theory. The Court is precluded
from affirming the Commission’s order on a factual theory that the Commission
did not rely upon in the order itself. E.g., Morgan Drive Away, Inc. v. Railroad
Comm'n of Tex., 498 S.W.2d 147, 152 (Tex. 1973) (“We may consider only what
was written by the [agency] in its order, and we must measure its statutory
sufficiency by what it says,” and “findings of basic [underlying] facts cannot be
presumed from findings of a conclusional nature.”); Continental Imports, Ltd. v.
Brunke, No. 03-10-00719-CV, 2011 WL 6938489 *5 (Tex. App. – Austin Dec. 30,
2011, pet. denied) (not designated for publication) (citing City of El Paso v. El
Paso Elec. Co., 851 S.W.2d 896, 899–900 (Tex. App. – Austin 1993, writ denied);
20
See OPUC’s Brief at 16.
11
Professional Mobile Home Transport v. Railroad Comm’n, 733 S.W.2d 892, 903–
04 (Tex. App. – Austin 1987, writ ref’d n.r.e.)).
III. The Commission’s disallowance of ETI’s costs of litigating the incentive
compensation issue is arbitrary and capricious and an abuse of
discretion.
A. The Commission’s finding that ETI made an unreasonable
argument in the underlying rate case is arbitrary and
capricious.
In its order, the Commission said it was unreasonable for ETI to advocate
recovery of financially-based incentive compensation in rates because, “[t]he
Commission has repeatedly ruled that a utility cannot recover the cost of
financially-based incentive compensation because financial measures are of more
immediate benefit to shareholders and financial measures are not necessary or
reasonable to provide utility services.”21 As ETI acknowledged in its initial brief,
it is true that the Commission has in the past referred to a perceived dichotomy
between “financial” and “operational” measures as a basis for incentive
compensation. But the Commission has not clearly or consistently explained how
to determine whether a given incentive program benefits customers versus
shareholders such that it is or is not recoverable. The Commission concedes, and
this Court has observed, that whether a particular incentive program benefits
customers enough to be recoverable in rates is a fact issue to be determined on a
21
AR Part I, Binder 2, Item 55 (Final Order at 2).
12
case-by-case basis.22 See State of Texas’ Agencies & Institutions of Higher
Learning v. Public Util. Comm’n of Tex., 450 S.W.3d 615, 660-61 (Tex. App. –
Austin 2014, pet. filed). And as evidenced in Appendix C to ETI’s initial brief, the
Commission has not treated materially-similar incentive programs consistently
over time. In fact, the Commission was persuaded in part by some of ETI’s
testimony in this case, and allowed ETI to recover some $1 million in cost-control
incentives that another utility was unable to recover in the past.23 Contrary to
appellees’ rhetoric, ETI’s advocacy in this case was not “futile,” “fruitless,” or
“unsuccessful.” In light of these circumstances, it makes no sense to characterize
ETI’s advocacy as “overly-aggressive” or “unreasonable.”
In an attempt to avoid this conclusion, the Attorney General sets up a straw
man. The Attorney General contends that the Commission did not fault ETI for
arguing about which incentives should be considered recoverable under what it
terms the “two bucket” policy. According to the Attorney General, the
Commission faulted ETI for something else -- arguing to eliminate the distinction
between the “buckets.” First, and most important, the Commission did not say
anything like that. Second, the two “arguments” the Attorney General attempts to
distinguish are shades of the same thing. Whether a particular incentive program
22
E.g., PUCT’s Brief at 5.
23
Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and
Obtain Deferred Accounting Treatment, Docket No. 39896 (Final Order at 4-5) (allowing
recovery of incentive compensation programs tied to “cost control” measures).
13
falls in one bucket or another is not just a matter of superficial labeling. It requires
the fact-finder to decide whether a given program “more immediately” benefits
shareholders or ratepayers. ETI’s position was that its incentive compensation
programs at issue in this case benefit customers substantially and meaningfully and
should be recovered.24 That is the same thing as arguing that ETI’s programs fall
in the bucket that is recoverable from customers. The Attorney General’s “bucket”
argument does not hold water.
OPUC suggests this case presents a simple question of evidentiary
sufficiency. It does not. An agency decision may pass the “substantial evidence”
test and still be invalid for arbitrariness. Starr County v. Starr Indus. Services,
Inc., 584 S.W.2d 352, 355 (Tex. App. -- Austin 1979, writ ref’d n.r.e.) (citing
Lewis v. Metropolitan Savings & Loan Association, 550 S.W.2d 11, 13-14 & 16
(Tex. 1977)). In determining whether an agency has acted arbitrarily or
capriciously, a court must decide whether the agency order was based on a
consideration of all relevant factors. Starr County, 584 S.W.2d at 355-56 (citing
Citizens to Preserve Overton Park v. Volpe, 401 U.S. 402, 91 S. Ct. 814, 28
L. Ed. 2d 136 (1971)). There must appear a rational connection between the facts
and the decision of the agency. Starr County, 584 S.W.2d at 356 (citing Bowman
24
Id., ETI Exh. 36 (Gardner Direct at 29-33 of 77); ETI Exh. 50 (Gardner Rebuttal at 2-10 of
18); ETI Exh. 15 (Hartzell Direct at 3-31 of 31); ETI Exh. 53 (Hartzell Rebuttal at 2-15 of 15);
PFD at 166-176.
14
Transportation, Inc. v. Arkansas-Best Freight System, Inc., 419 U.S. 281, 95 S. Ct.
438, 42 L. Ed. 2d 447 (1974); 5 B. Mezines, J. Stein and J. Gruff, Administrative
Law § 51.03, at 51-33 (1979)). Stated differently, the reviewing court must
remand “. . . if it concludes that the agency has not actually taken a hard look at the
salient problems and has not genuinely engaged in reasoned decision-making.”
Starr County, 584 S.W.2d at 356 (citing Texas Medical Association v. Mathews,
408 F. Supp. 303, 305 (W.D. Tex. 1976)).
The testimony of OPUC’s witness Nathan Benedict does not reasonably
support the Commission’s decision in this case. Mr. Benedict generally testified
that the Commission excluded financially-based incentive compensation from
ETI’s rates set in Docket No. 39896.25 But he did not acknowledge that, in the
same docket, the Commission allowed recovery of costs it had previously
disallowed because they were supposedly “financially-based” incentives. And
contrary to OPUC’s suggestion,26 the Commission may not use its own
“experience” to fill in evidentiary gaps. Railroad Commission of Texas v. Lone
Star Gas Co., 611 S.W.2d 908, 911 (Tex. Civ. App. – Austin 1981, writ ref’d
n.r.e.). The Commission’s characterization of ETI’s argument in the rate case is
not reasonable in light of the record or its past decisions.
25
AR Part II, Binder 3, OPUC Exh. 1 (Benedict Direct at 8).
26
OPUC’s Brief at 14.
15
B. Regardless, the Commission’s decision is reversibly wrong
on procedural grounds.
Even if the appellees’ characterization of ETI’s advocacy on this issue were
in line with the facts, the Commission’s decision to disallow the expenses of the
advocacy was arbitrary and an abuse of discretion.
1. The Commission changed its past practice without
explanation or advance notice.
As ETI explained in its initial brief, though many utilities have sought to
include incentive compensation in rates, the Commission has never before
disallowed the cost of making unsuccessful incentive compensation arguments. In
fact, the Commission has expressly determined that other utilities’ rate case
expenses were reasonable, necessary, and recoverable from ratepayers, even in
cases where the utilities made unsuccessful arguments on incentive compensation.
See Appendix D to ETI’s Appellant’s Brief. The Commission has also allowed
ETI and its predecessor to recover rate case expenses in dockets where ETI made
similarly unsuccessful requests in the past. See Docket No. 34800, supra (Mar. 16,
2009, Order at FOF 27); Docket No. 37744, supra (Dec. 13, 2010, Order at FOF
18). The Commission cannot point to any case where it has disallowed the
16
expenses of making unsuccessful arguments about incentive compensation, or for
making some other argument the Commission deems a “long shot.”27
The Commission contends its decision in this case is not a departure from its
earlier decisions because ETI’s request in this case was different from requests in
previous cases. That is not so. In every one of these past cases, a utility proposed
to recover incentive costs that were “financially based.” For example:
 In Docket No. 28840, AEP sought to recover its entire test-year
level of incentive compensation expense, even though only
34% of it was set through “operational” measures. Application
of AEP Texas Central Co. for Authority to Change Rates,
Docket No. 28840 (Aug. 15, 2005, Final Order at FOFs 165-
67);
 In Docket No. 33309, part of the incentive compensation AEP
sought to include in rates was “related to financial incentives.”
Application of AEP Texas Central Co. for Authority to Change
Rates, Docket No. 33309 (Mar. 4, 2008, Order on Rehearing at
FOF 82);
 In Docket No. 34800, ETI’s predecessor unsuccessfully sought
to include in rates its incentive compensation costs that were
“financially-related,” arguing even those costs meaningfully
27
OPUC argues that this Court may not consider orders from previous Commission dockets
because they are not part of the administrative record in this case. See OPUC’s Brief at 19. This
Court rejected that same argument in Oncor. See Oncor Elec. Delivery Co. LLC v. Public Util.
Comm’n of Tex., 406 S.W.3d 253, 267 (Tex. App. – Austin 2013, no pet.). This Court
specifically acknowledged it may consider how the Commission has treated other utilities to
determine whether a particular policy is new in a given case. Id. at 267. The Court can take
judicial notice of agency decisions like these, which are publicly available and the authenticity of
which is readily verifiable. See Office of Pub. Util. Counsel v. Public Util. Comm'n, 878 S.W.2d
598, 600 (Tex. 1994) (holding that court of appeals must take judicial notice of agency's
published order if asked to do so) (citing Tex. R. Civ. Evid. 201(b)(2)); Hendee v. Dewhurst, 228
S.W.3d 354, 377 n.30 (Tex. App. -- Austin 2007, pet. denied) (likening agency decisions to court
decisions with regard to judicial notice).
17
benefited customers. See Application of Entergy Gulf States,
Inc. for Authority to Change Rates and to Reconcile Fuel Costs,
Docket No. 34800, ETI Exh. 72 (Direct Testimony of J.
Hartzell, PhD, on Remand);28
 In Docket No. 35717, Oncor sought to recover its entire test-
year level of incentive compensation expense, even though
about 25% of it was “related to financial measures.” See
Application of Oncor Electric Delivery Co. LLC for Authority
to Change Rates, Docket No. 35717 (Nov. 30, 2009, Order on
Rehearing at FOFs 91-93);
 In Docket No. 37744, ETI sought to include in rates its
incentive compensation costs that were “financially-based,”
arguing even those costs meaningfully benefited customers.
See Application of Entergy Texas, Inc. for Authority to Change
Rates and Reconcile Fuel Costs, Docket No. 37744, ETI Exh.
14 (Direct Testimony of J. Hartzell, PhD);29
 In Docket No. 38339, CenterPoint sought to include in rates
both its short-term and long-term incentive compensation plans,
but the Commission included only the former in rates, finding it
was “directly tied to metrics such as customer service and
safety.” See Application of CenterPoint Energy Houston
Electric, LLC for Authority Change Rates, Docket No. 38339
(Jun. 23, 2011, Order on Rehearing at FOFs 81-83); and
 In Docket No. 40443, Southwestern Electric Power Company
sought to recover its roughly $10.7 million test-year level of
incentive compensation, even though roughly half of it was tied
to “financial measures.” See Application of Southwestern
Electric Power Co. for Authority to Change Rates and
Reconcile Fuel Costs, Docket No. 40443 (Mar. 6, 2014, Order
on Rehearing at 13 & FOFs 214-220).
28
See Appendix A.
29
See Appendix B.
18
There is no material distinction between ETI’s request in this case and the utility
proposals made in previous cases.
OPUC argues that the Commission’s past decisions did not establish
“policy” because they were “not contested.”30 But again, the Commission
expressly found in each of these past cases that it was reasonable for the utility to
recover its expenses, and never carved out costs of making unsuccessful arguments
about incentive compensation. The fact that parties may have agreed with these
decisions does not undermine them. If anything, it bolsters them.
To be clear, ETI does not contend that the Commission can never change its
policy on a given issue. But when it does, the Commission must give advance
notice that it is considering a policy change, and articulate a reason if a change is
made. The Attorney General does not even suggest that the Commission met these
requirements in this case.31 The Commission’s failure in each of these respects is
reversible error, just like it was in Oncor Elec. Delivery Co., 406 S.W.3d 253.
Appellees’ attempts to distinguish Oncor are not persuasive. First, this
Court in Oncor reversed the Commission’s decision because the Commission did
not explain its departure from a past practice. The same thing happened in this
case – the Commission had always acted one way under a given set of facts, and
then took the opposite path on the same set of facts. Second, another basis for this
30
OPUC’s Brief at 20.
31
See PUCT’s Brief at 33.
19
Court’s reversal of the Commission’s decision in Oncor was that the Commission
departed from its past practice when it was too late for the utility to do anything
about it. The same thing happened in this case. The administrative process at
issue began when Docket No. 39896 was filed. At that time, the Commission had
given no indication whatsoever that it would not continue to allow recovery of
otherwise reasonable expenses related to litigating incentive compensation. The
opportunity to file rebuttal testimony in the severed expense docket did not
adequately protect ETI’s interests. By the time the new standard was proposed and
vetted in the severed expense docket, ETI had already incurred the very costs
proposed to be disallowed. The fact that ETI had the opportunity to file rebuttal
testimony in the expense docket does not mean ETI had proper notice of the
Commission’s new policy at the critical time, before ETI incurred the costs at
issue.
All the appellees cite Industrial Utils. Serv. Co. v. Texas Natural Resources
Conservation Comm’n, 947 S.W.2d 712, 718 (Tex. App. – Austin 1997, no writ) as
support for the Commission’s decision. But that case proves ETI’s point. In
Industrial Utils. Serv. Co., the utility sought a rate increase, asked the agency to
deny it, and then sought to recover its expenses of prosecuting the rate case. This
Court upheld the agency’s denial of the expenses. This case is quite different.
Here, ETI sought and received a rate increase, based in part upon ETI’s successful
20
request to recover what have historically been deemed to be financially-based
incentive compensation. It is not, therefore, unreasonable for ETI to seek the
expenses of making that request. Moreover, the agency in Industrial Utils. Serv.
Co. did not have a historical practice of allowing recovery of expenses for making
unwanted rate proposals. Here, in contrast, the Commission has consistently
allowed recovery of expenses for making even unsuccessful incentive
compensation arguments. The Commission has never disallowed the expenses of
seeking to include financially-based incentive compensation in rates. Industrial
Utils. Serv. Co. is simply inapposite to this case.
2. Additionally, the Commission effectively and
improperly adopted a new rule in this contested case.
The Commission’s imposition of a new policy in this case also constitutes
improper ad hoc adjudication. Appellees contend the agency did not craft a “rule”
of general applicability in this case, but only applied the statutory principle that a
utility may not recover “unreasonable” expenses.32 State Agencies also contend
the scope of the Commission’s decision is not clear, so it cannot be a “rule.”33 But
regardless of whether the Commission meant it is unreasonable to take any “long
shot” position or just to seek recovery of financially-based incentive compensation,
it is clear the Commission intended to apply its new allocation of risk to the
32
E.g., PUCT’s Brief at 35; OPUC’s Brief at 25-26; State Agencies’ Brief at 17 & 19.
33
State Agencies’ Brief at 17.
21
industry going forward. The Commission did not in its order identify any facts
peculiar to this case that suggest the new policy applies only to this case. The
Commission broadly declared that it is “unreasonable” to incur expense to litigate
the recoverability of financially-based incentive compensation. And the
Commission based its conclusion solely upon something the Commission
characterized as “well-established policy” – not facts.34
Again, Chairman Nelson confirmed at an open meeting that the Commission
was in this case setting a “new policy.”35 She even observed, on the record, that
the subject is more properly addressed in a rulemaking.36 Appellees contend this
statement somehow implies the opposite. They cite this Court’s recent decision in
McHaney v. Texas Comm’n on Environmental Quality, No. 03-13-00280-CV, 2015
WL 869197 at *8 (Tex. App. – Austin Feb. 27, 2015, no pet. h.). In McHaney, this
Court considered a TCEQ Commissioner’s statement that “if there is a need for
clarity in our rules, I would encourage our staff to look at that and see if we need to
go through the rulemaking or provide some other guidance.” McHaney, 2015 WL
869197 at *8 (emphasis in original). The Court viewed that statement as support
for the conclusion that the agency did not intend to impose a “rule” in the contested
case at issue. Chairman Nelson, however, did not suggest that the Commission
34
AR Part I, Binder 2, Item 55 (Final Order at 2).
35
See April 11, 2013 Transcript at 7:25-8:14.
36
Id.
22
was following established policy or merely question whether the Commission’s
rules reflect the policy clearly enough. Chairman Nelson unequivocally
acknowledged that the PUCT was adopting a “new policy” in this case, and
recognized that new agency policy should be adopted through the formal
rulemaking process.
The Attorney General and State Agencies also argue that the agency’s
formal adoption of a rule after this case indicates that the Commission was not
adopting a rule in this case.37 That is a non-sequitur. The fact that the agency
ultimately followed the formal rulemaking process does not shed any light on what
the agency intended earlier, in this case. The Commission declared for the first
time in this case that it is “unreasonable” to propose to recover what in the past has
been deemed “financially-based” incentive compensation, and that it is
“unreasonable” to incur expenses for such a proposal. It was improper to impose
these new policies outside the context of a formal rulemaking because none of the
justifications for ad hoc adjudication apply.
State Agencies cite Entergy Gulf States, Inc. v. Public Util. Comm’n of Tex.,
173 S.W.3d 199, 212 (Tex. App. – Austin 2005, pet. denied) as support for the
Commission’s action. That case recognizes that an agency may engage in ad hoc
adjudication when it “may not have had sufficient experience with a particular
37
See PUCT’s Brief at 38; State Agencies’ Brief at 23.
23
problem to warrant rigidifying its tentative judgment into a hard and fast rule.”
Entergy Gulf States, 173 S.W.3d at 212. But the Commission has had plenty of
experience considering the expenses of advocacy related to incentive compensation
issues, as discussed above. If the Commission wanted to change its policy going
forward, it was bound to do so in the context of a formal rulemaking.
IV. The Commission further erred in quantifying its disallowance of ETI’s
expenses of seeking to include financially-based incentive compensation
in rates.
The Commission used a “proxy” to measure the disallowance discussed
above. Specifically, the Commission determined the percentage of ETI’s
requested rate increase that was attributable to its unsuccessful incentive
compensation argument, and then disallowed that same percentage of ETI’s rate
case expenses.
The Commission has never done that before. The Commission’s sole
justification for using a proxy is that ETI did not track all of its expenses by issue
over the life of the rate case. But utilities have not tracked their rate case expenses
by issue because the Commission has never before imposed a disallowance for
litigating an issue. Indeed, the Commission has repeatedly allowed utilities to
recover the expense of making the very same argument ETI made here. It is the
Commission’s after-the-fact change in policy, not a failing of ETI’s, that caused
24
the difficulty in measuring the actual expenses of litigating a particular issue in this
case.
The problem with the Commission’s “proxy” approach is that it does not
logically approximate the actual amount of costs ETI incurred to litigate the
incentive compensation issue. Instead, the Commission’s proxy method is keyed
to the value of the litigated issue. State Agencies argue that there is a logical
correlation between the value of a litigated issue and the amount of money a utility
spends to litigate it. There is not. It is true that the raw, maximum value of a
litigation position might represent an upper limit on the expenses that may
reasonably be incurred to pursue it. But that is where any correlation stops. It may
cost relatively little to pursue even a high-dollar-value litigation position. The
value of the position simply does not inform what it actually costs to litigate.
Contrary to the Commission’s argument, the agency’s use of a proxy in this
case does not resemble the way the agency quantified a disallowance in Docket
No. 28840. There, the Commission disallowed half of the expenses associated
with a witness’s testimony — specifically, the expenses of Dr. Goodfriend’s
testimony on quality-of-service issues.38 Dr. Goodfriend’s testimony was 117
38
See Application of AEP Texas Central Co. for Authority to Change Rates, Docket No. 28840
(Jul. 2, 2004, PFD at 125); Proceeding to Consider Rate Case Expenses Severed from Docket
No. 28840 (Application of AEP Texas Central Company for Authority to Change Rates), Docket
No. 31433 (Mar. 3, 2006, Final Order at FOF 29).
25
pages long. Roughly 60 pages of it concerned the quality-of-service issue.39 The
disallowance of half the cost of the testimony almost exactly correlates with the
portion of the testimony the Commission found was flawed. That is, the
Commission disallowed the actual expenses of unreasonable testimony in Docket
No. 28840, not some unrelated amount of money based upon the value of the
position the witness was advocating.
State Agencies and OPUC point to the Pioneer Natural Resources case as
support for the Commission’s use of a proxy to measure a disallowance.40 The
Commission did not use a proxy, or “infer” anything, to quantify the disallowance
in that case. In Pioneer, the Commission limited the utility to recovering only 35%
of the cost of a computer system because only 70% of the system served the utility,
and because only half the system was operational in the test year. The 35%
multiplier was, as this Court noted, simply the mathematical product of the 70%
and 50% components (i.e., 70% x 50% = 35%). Pioneer Natural Resources, 303
S.W.3d at 369. The Commission’s quantification of the expense it deemed
unreasonable in Pioneer contrasts sharply with what the Commission did here.
Here, the Commission did not quantify the actual expenses of making an argument.
The Commission quantified something else, based upon the value of the argument.
The Commission imposed its new policy at the end of the case, after the expenses
39
Id. (Direct Testimony of S. Goodfriend at 11-71 of 117).
40
See State Agencies’ Brief at 27 (citing Pioneer Natural Res., 303 S.W.3d at 369).
26
had already been incurred and tracked according to historically accepted practices,
when it was too late for ETI to do anything about it.
V. The Commission’s disallowance of depreciation expense associated with
ESI’s efforts in the rate case is not supported by any evidence and is
arbitrary and capricious.
As ETI explained in its initial brief, the Commission disallowed over
$207,000 of depreciation expense associated with assets ESI employees used in
their work on the rate case. The Commission in its order said only that this
expense was “not reasonable.”41 That is an “ultimate” finding of fact, stated in
statutory language. See Tex. Util. Code Ann. §§ 36.051(rates must permit utility to
recover “reasonable” and necessary operating expenses) & 36.061(b)(2)
(contemplating recovery of “reasonable” rate case expenses). The Commission
was bound to, but did not, make any underlying finding of fact supporting this
ultimate finding. See Tex. Gov’t Code Ann. § 2001.141(d). The Court may not
presume findings of underlying facts. E.g., Vista Medical Center Hosp., 416
S.W.3d at 26. The Commission’s decision is reversible for this reason alone.
CenterPoint Energy Entex v. Railroad Comm’n of Tex., 213 S.W.3d 364, 373 (Tex.
App. – Austin 2006, no pet.) (reversing agency’s disallowance of expense as
“unreasonable” because agency failed to make underlying findings permitting
court to review reasonableness of its decision).
41
AR Part 1, Binder 2, Item 55 (Final Order at FOF 18(a)).
27
Assuming arguendo the Commission could escape that flaw in its decision,
the only basis the ALJ articulated for his decision on this issue was rank
speculation that ETI might not incur depreciation expense if it had hired an
unaffiliated company to do the same work.42 This speculation is not supported by
any evidence in the record, and it is directly contrary to the Commission’s
treatment of test-year ESI depreciation expense in the underlying rate case.
In response, the Attorney General now says Entergy did not explain what
assets were being depreciated. This was not a stated reason for the disallowance in
the Commission’s order or the ALJ’s PFD. The order cannot be sustained on this
basis. Morgan Drive Away, Inc., 498 S.W.2d at 152; Continental Imports, Ltd.,
2011 WL 6938489 *5 (citing City of El Paso, 851 S.W.2d at 899–900);
Professional Mobile Home Transport, 733 S.W.2d at 903–04.
More important, this detail is in the record. As noted by ETI’s witness
Michael Considine in this case, Company witness Stephanie Tumminello
explained (in the rate case) the process by which depreciation costs were billed to
ETI.43 Ms. Tumminello explained what ESI assets were being depreciated.44 Her
testimony was part of the record officially noticed in this case.45
42
AR Part I, Binder 2, item 32 (PFD at 12); AR Part I, Binder 2, Item 55 (Final Order at 1).
43
AR Part II, Binder 3, ETI Exh. 6 (Oct. 25, 2012, Considine Supp. Direct at 4).
44
See Docket No. 39896, supra, ETI Exh. 41 (Tumminello Direct at 79).
45
AR Part III, Vol. A (Transcript of Hearing on Merits at 16).
28
The Attorney General argues that Ms. Tumminello’s testimony pertained
only to test-year expenses and not expense incurred while ESI was working on the
rate case. The Attorney General ignores that Ms. Tumminello’s testimony was
filed with ETI’s application in Docket No. 39896, which included both requests for
a base-rate increase and recovery of rate case expenses.46 Ms. Tumminello did
sponsor schedules and testify about test-year ESI depreciation expense. But her
testimony was not limited to test-year processes or expenses. Her explanation of
what assets ESI depreciates, how the expense is recorded by project, why the
expense is necessary, and how it is billed and allocated to operating companies like
ETI addresses the company’s practices generally.47 And Ms. Tumminello
confirmed, based upon a survey she conducted, that ESI’s costs are in line with
those of peer service companies and do not include any profit or markup.48 Ms.
Tumminello’s testimony that control processes ensure depreciation costs billed to
ETI are no higher than the costs billed to other affiliates is equally unqualified.49 A
PricewaterhouseCoopers opinion letter further confirms that ESI has established
processes generally to ensure that it bills only actual costs, and that its charges to
46
See Docket No. 39896, supra, (Application) & ETI Exh. 8_ (Considine Direct at 18).
47
See Docket No. 39896, supra, ETI Exh. 41 (Tumminello Direct at 79-86 & SBT-26 (list of
depreciable assets by account number)).
48
Id. at 82-84.
49
Id. at 84-85 & Tumminello Direct Exh. SBT-15 (Attachment 8, “Affiliate Billing Process
Controls”).
29
ETI are no higher than costs billed to other affiliates.50 Mr. Considine’s testimony
in the severed expense docket echoes these conclusions multiple times.51
The Attorney General further muses that the depreciation expense for ESI’s
work in the rate case might contain depreciation on aircraft. But again, Ms.
Tumminello testified generally that ESI aircraft depreciation expense is “included
as a component of total flight costs of ESI aircraft” and not included in general
depreciation.52 The spreadsheet Mr. Considine sponsored in the expense docket,
showing expenses charged to ETI for ESI’s services in the rate case, does not
include any “flight” or “aircraft” costs.53 This argument is specious.
The Attorney General now contends ETI’s evidence does not meet the
standards for affiliate expenses set out in Docket No. 16705 and PURA section
36.058. See Tex. Util. Code Ann. § 36.058(c). This argument is incredible, given
that the Commission expressly found in this case that “Entergy met the
requirements in PURA § 36.058 regarding payments to its affiliates for its rate-
case expenses.”54 Clearly, the “heightened affiliate standard” was not the basis for
the Commission’s disallowance of ESI depreciation expense.
50
Id. at Tumminello Direct Exh. WP SBT-4.
51
AR Part II, Binder 3, ETI Exh. 4 (Considine Supp. Direct at 3-4 of 5); AR Part II, Binder 3,
ETI Exh. 5 (Considine Supp. Direct at 3-5 of 6); AR Part II, Binder 3, ETI Exh. 6 (Considine
Supp. Direct at 3-5 of 5); AR Part II, Binder 3, ETI Exh. 7 (Considine Rebuttal at 9-11 of 11).
52
See Docket No. 39896, supra, ETI Exh. 41 (Tumminello Direct at 83-84).
53
AR Part II, Binder 3, ETI Exh. 7 (Considine Rebuttal at Exh. MPC-R-1).
54
Order at 3, FOF 19, & COL 11.
30
Because the Commission’s disallowance of this expense is not supported by
any evidence in the record, and because it cannot reasonably be reconciled with its
treatment of analogous expense in the rate case, the decision must be reversed.
CONCLUSION AND PRAYER
For the foregoing reasons, Entergy Texas, Inc. respectfully requests the
relief it requested in its appellant’s brief.
Respectfully submitted,
DUGGINS WREN MANN & ROMERO, LLP
By: /s/ Marnie A. McCormick
John F. Williams
State Bar No. 21554100
jwilliams@dwmrlaw.com
Marnie A. McCormick
State Bar No. 00794264
mmccormick@dwmrlaw.com
P. O. Box 1149
Austin, Texas 78767-1149
(512) 744-9300
(512) 744-9399 fax
ATTORNEYS FOR APPELLANT
ENTERGY TEXAS, INC.
31
CERTIFICATE OF COMPLIANCE
I certify that this document contains 7,474 words in the portions of the
document that are subject to the word limits of Texas Rule of Appellate Procedure
9.4(i), as measured by the undersigned’s word-processing software.
/s/ Marnie A. McCormick
Marnie A. McCormick
32
CERTIFICATE OF SERVICE
As required by Texas Rule of Appellate Procedure 9.5, I certify that on the
27th day of April, 2015, the foregoing document was electronically filed with the
Clerk of the Court using the electronic case filing system of the Court, and that a
true and correct copy was served on the following lead counsel for all parties listed
below via electronic service:
Elizabeth R. B. Sterling
Environmental Protection Division
Office of the Attorney General
P. O. Box 12548 (MC 066)
Austin TX 78711-2548
Counsel for Appellee Public Utility Commission of Texas
Rex D. VanMiddlesworth
Benjamin Hallmark
Thompson Knight LLP
98 San Jacinto Blvd., Ste. 1900
Austin TX 78701
Counsel for Appellee Texas Industrial Energy Consumers
Katherine H. Farrell
Administrative Law Division
Office of the Attorney General
P. O. Box 12548 (MC018-12)
Austin TX 78711-2548
Counsel for Appellee State Agencies
Ross Henderson
Office of Public Utility Counsel
1701 N. Congress Ave., Ste. 9-180
P. O. Box 12397
Austin TX 78711-2397
Counsel for Appellee Office of Public Utility Counsel
/s/ Marnie A. McCormick
Marnie A. McCormick
33
APPENDICES
A. Direct Testimony of Dr. J. Hartzell on Remand in PUCT Docket No. 34800
B. Direct Testimony of Dr. J. Hartzell in PUCT Docket No. 37744
34
APPENDIX A
Direct Testimony of Dr. J. Hartzell on Remand
in PUCT Docket No. 34800
SOAR Docket No. XXX-XX-XXXX
PUC Docket No. 34800
EGSI - 2007 Rate Case
EGSI Remand Ex. No. 72
DOCKET NO. ~
APPLICATION OF ENTERGY § PUBLIC UTILITY COMMISSION
GULF STATES, INC. FOR §
AUTHORITY TO CHANGE RATES §
AND TO RECONCILE FUEL COSTS . § OF TEXAS
DIRECT TESTIMONY
OF
JAY C. HARTZELL
ON BEHALF OF
ENTERGY GULF STATES, INC.
SEPTEMBER 2007
2007 Texas Rate Case 10. I
DOCKET N O . - - - -
ENTERGY GULF STATES. INC.
DIRECT TESTIMONY OF JAY C. HARTZELL
2007 TEXAS RATE CASE -
TABLE OF CONTENTS
Page
I. Witness Identification and Qualifications 1
II. Purpose and Organization of Testimony 2
Ill. Financlal·Based Incentive Compensation as a Tool for Improving
Consumer Welfare 4
A. The Positive Effect of Incentive Compensation on Utility
Customer Weffare 4
B. The Reasons for Providing Financial·Based Incentive
Compensation 10
EXHIBIT
Exhibit JCH· 1 Resume
2007 Texas Rate Case J().2
Entergy Gulf States, Inc. Page1of19
Direct Testimony of Jay C. Hartzea
2JXJ7 Texas Rate Case
1 I. WITNESS IDENTIFICATION AND QUALIFICATIONS
2 Q. PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS
3 ADDRESS.
4 A. I am Jay C. Hartzell. I am an Associate Professor of Finance at the
5 Mccombs School of Business at the University of Texas at Austin. My
6 work address is Department of Finance, T:he University of Texas at Austin,
7 1 University Station B6600, Austin, Texas, 78712.
8
9 Q. FOR WHOM ARE YOU TESTIFYING?
10 A. I am testifying on behalf of Entergy Gulf States, Inc. ("£GSI").
11
( 12 Q. PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND
13 PROFESSIONAL EXPERIENCE.
14 A. I provide my complete resume in my Exhibit JCH-1. In brief, I obtained a
15 Bachelor of Science degree (cum laude) from Trinity University in May
16 1991, with majors in Business Administration and Economics. After
17 graduating, I went to work as a consuhant for Hewitt Associates, in The
16 Woodlands, Texas. Hewitt is a -consulting firm that specializes in benefits
19 and compensation. While there, I specialized in the area of defined
20 contribution plans. I left Hewitt lo go to graduate school at the University
21 of Texas at Austin in 1993. I completed my PhD in finance there in May
22 1998. Upon graduating, I took a job as an Assistant Professor of Finance
23 at New York University's Stem School of Business, where I worked
2.007 Texas Rate Case W.-3
Entergy Gulf States, Inc. Page2of 19
Direct Testimony of Jay C. Hartzell
2007 Texas Rate Case
1 until 2001. At that time, the University of Texas at Austin hired me as an
2 Assistant Professor at the McCombs School of Business .("McCombs
3 Schooi-), where I have work~ since. I was promoted to the rank of
4 Associate Professor (with tenure), effective in the fall 2006. I also now
5 serve as the Director of the Real Estate Finance and Investment Center at
6 the McCombs School.
7
8 a. WHAT ARE YOUR MAIN AREAS OF RESEARCH?
9 A. My primary research interest is in the area of corporate governance. This
10 area encompasses several topics, including executive compensation, the
11 role of institutional investors, mergers and acquisitions, and boards of
12 directors. I have also written papers in the area of real estate finance, with
13 many of these also focusing on the areas of corporate governance, using
14 data from that industry.
15
16 II. PURPOSE ANO ORGANIZATION OF TESTIMONY
17 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
18 A. EGSI has asked me to comment on the use of financial-based goals in a
19 company's incentive compensation plans, and how those goals affect
20 consumer welfare. I first address the factors specific to the utility industry
21 that support the conclusion that the presence of financial-based goals in
22 an incentive compensation plan is consistent with consumers' interssts. I
23 then tum to the broader topic of how an incentive <:e>mpensation plan
2007 Texas Rate Case J()..4
Entergy Gulf States, Inc. Page3of 19
Direct Testimony of Jay C. Hartzell
2001 Texas Rate-case
1 including financial measures provides incentives to a firm's employees to
2 take actions that improve customer welfare.
3
4 a. WHY ARE YOU OUALlflED TO ADDRESS THESE SUBJECTS AND TO
5 PROVIDE THIS TESTIMONY?
6 A. In addition to my formal training as a student, I have studied and
7 conducted research on corporate governance, including executive
8 compensation, for more than 10 years, starting with work in graduate
9 school, including my dissertation. Since that time, I have written nine
1O papers on corporate governance topics, plus my dissertation. Six of those
11 have been published in peer-reviewed academic journals, including the
( 12 top such journals in the field of finance. I have presented and discussed
13 papers on corporate governance (including compensation) at the major
14 conferences in the field. I have also taught related topics to PhD students,
15 as part of a PhD class in empirical corporate finance.
16
17 Q. DO YOU SPONSOR ANY EXHIBIT?
18 A. Yes. My exhibit is listed in the table of contents to this testimony.
2007 Texas Rate Case 10..S
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Direct Testimony Qf Jay C. Hartzell
2007 Texas Rate Case
1 Ill. FINANCIAL-BASED INCENTIVE COMPENSATION AS A TOOL FOR
2 IMPROVING CONSUMER WELFARE
3 Q. WHAT IS YOUR UNDERSTANDING OF THE COMMISSION'S
4 RATEMAKING TREATMENT OF A UTILITY'S INCENTIVE
5 COMPENSATION EXPENSES?
6 A. It is my understanding that in recent cases, the Public Utility Commission
7 has had a policy of excluding from base rates compensation that is based
8 on the firm's financial measures, but has allowed compensation that is
9 based on operational measures such as quality of service, reliability,
10 public safety, cost control, power plant performance, reduction of
11 absenteeism, and cost containment.
12
13 Q. WHAT ISSUES REGARDING INCENTIVE COMPENSATION WILL YOU
14 ADDRESS?
15 A. I will comment on the coexistence of these two types of incentives
16 (financial-based and operational-based), and the role of financial-based
17 incentives in ultimately contributing to customer welfare.
18
19 A. The Positive Effect of Incentive Comoensation on
20 Utility Customer Welfare
21 a. IS THERE A LINK BETWEEN CUSTOMER WELFARE AND A FIRM'S
22 FINANCIAL PERFORMANCE?
23 A. Yes. Satisfied customers clear1y experience greater customer welfare, all
24 else equal, as they are happy with the products they consume. This is
2007 Texas Rate Case 10-6
Entergy Gulf States, Inc. Page5of 19
Direct Testimony of Jaye. Hartzell
2007 Texas Rate Case
1 true not only for customers in unregulated industries, but also for
2 customers in regulated industrieS. For example, customers who
3 experience fewer power outages will suffer less disutility from being
4 without power, but will also spend less time and expend fewer resources
5 compensating for outages, or complaining about the service they have
6 received.
7 In addition to benefiting eustomers, greater satisfaction tends to
8 benefrt the firm, as well. Satisfied customers are likely to buy more of the
9 firm's products, which leads to higher revenues and profits, and a higher
10 stock price, all else equal. Satisfied customers are also more likely to be
11 retained as customers, and customer retention helps the firm's profitability
( 12 via higher net revenues than they would have .experienced without such
13 satisfaction. Companies with better reputations for customer satisfaction
14 are also more likely to attract new customers who can leam of firms'
15 reputations prior to making their purchasing decisions. At the same time,
16 because improved customer satisfaction tends to lead to improved
17 financial performance, the prospect for improved financial results can play
18 a positive role in motivating mana~rs to improve customer welfare.
19 Although regulated utility -companies do not deal with the same type
20 of competitive dynamics faced by unregulated companies, the general
21 concepts r~ated to customer satisfaction still apply. For example,
22 potential industrial customers and other large users face choices when
23 they decide where to locate a new facility (a factory, a campus, etc.) or
2007 Texas Rate Case
Entergy Gulf states, Inc. Page6of 19
Oirec:t T eslimony of Jay C. HartzeU
2007 Texas Rate Case
1 whether to expand a current facility or instead build a new one, or whether
2 to produce their own power rather than rely on the local utility company.
3 Holding the rates they are offered constant, if the customer has a facility in
4 a location with an electricity provider who provides good service, then the
5 customer's satisfaction with that service would make the customer more
6 likely to expand that facility, and would make the customer less likely to
7 look for alternative locations or to self-generate, all else equal. A
8 customer that is more likely to expand in the current location rathe~ than
9 l~k elsewhere would in tum benefit -the financial performance of the
10 customer's current utility company. -
11 This conceptual link between customer welfare and financial
12 performance also applies to residential utilify customers. Residential
13 customers can choose, for example, between gas (including propane)
14 appliances and electrical appliances. The more satisfied they are with
15 their electrical service provider, the more likely they are to ~oose
16 electrical appliances (all else equal). This customer behavior in response
17 . to good service again leads to better financial performance for the electric
18 utility.
19
20 Q. WHY WOULD TODAY'S FINANCIAL HEALTH OF THE FIRM
21 POSITIVELY AFFECT FUTURE CUSTOMER WELFARE?
2007 Texas Rate Case 10-8
Entergy Gulf States, Inc. Page7of 19
Direct Testimony of Jay C. Hartzell
2007 Texas Rate Case
1 A. I can see at least five channels through which a more financially
2 successful company will be associated with greater customer welfare both
3 now, and in the future.
4 First, companies that are financially healthy will be able to raise
5 capital at lower cost. Put another way, companies that are less healthy
6 financially and therefore are more likely to enter into financial distress
7 (including bankruptcy) will face higher costs of capital. These higher costs
8 of capital will in tum lead to higher rates for customers and lower customer
9 welfare. This channel is straightforward: as a .company gets closer to
10 distress, the expected costs of distress increase, and lenders (including
11 bondholders) charge more for their loans to the firm. Because the cost of
12 debt is one of the key components of the cost of capital, these higher
13 borrowing costs lead to a higher oven1ll cost of capital. In addition, if 1he
14 higher costs of capital are large enough, this effectively limits the less
15 healthy finn's acce5s to funds, implying that financially healthy firms have
16 broader access to capital than their less healthy oountefparts. This cost of
17 capital effect is especially relevant to the utility industry given the
18 industry's reliance on large capital spending projeGts and use of debt
19 capital.
20 Second, in an industry where prices that finns can chatge are
21 regulated, if managers have incentives to increase fmancial performance,
22 then this will lead them to focus on cutting oosts. By linking managers'
23 pay to stock price, for example, managers will, among other goals, attempt
2007 Texas Rare Case J().9
Entergy Gulf States, Inc. Page8of 19
Direct Testimony of Jay C. HartzeQ
2001 Texas Rate case
1 to increase stock price by operating mere efficiently. This improved
2 efficiency will lead to a lower cost basis in the future than what one would
3 have observed without such incentives, which will in tum lead to lower
4 future prices for customers (compared to .what would likely have been
5 charged otherwise) and increased customer welfare.
6 Third, the utility industry is characterized by high fixed costs of
7 production and economies of scale. This cost structure implies that larger
8 firms can operate at lower marginal costs (all else equal). Thus, as higher
9 customer service or satisfaction leads to greater customer attraction and
1O retention, these in tum lead to growth in the customer base and revenues.
11 The magnitude of these effects may be smaller for a regulated utility than
12 for a firm in an ~nregulated industry, but I see no reason why the effects
13 would not still be present and go in the same direction. Such growth in
14 reven.ues is associated with greater financial perfonnance, but the
15 Increase in size allows the firm to produce more cheaply due to the large
16 fixed costs in the industry and economies of scale. These cost savings
17 again materialize in lower future rates for customers (compared to what
18 they would have been without the growth in the1irtn's operations).
19 Fourth, managers who care about the financial performance of the
20 company are more likely to make better investment decisions. The stock
21 market, via analysts who follow the firm's behavior and traders who act
22 based on their beliefs about the firm's prospects, acts as a monitor of a
23 wide range of managerial actions, including investment decisions. Stock-
2007 Texas Rate Case 10-10
Entergy Gulf States, Inc. , Pege9of 19
Direct Testimony of Jay~. Hartz.en
2007 Texas Rate'Case
1 price based incentives can help discipline managers, and constrain ihem
2 from investing in ways that might not benefit the finn.
3 Fifth, companies that are less healthy financially - or, to put it
4 another way, closer to financial distress - will likely experience greater
5 costs, which will in tum be passed on to customers. This is because
6 stakeholders who have relationships with the company will demand more
7 favorable terms from the firm in order to compensate them for the greater
8 risk of dealing with a less healthy a>mpany. For example, consider a
9 supplier who sells machinery to a utility company that is not financialty
10 healthy (or is believed to be near distress). Such a supplier will likely
11 demand higher prices from the utility before committing to any sort of
( 12 investment in a relationship with the utility, In order to oompensate for the
13 risk that the revenues from the relationship may cease to exist before the
14 supplier can recoup its costs. These effects are predicted to be stronger
15 where firm-specific investments are required - such as customized
16 machinery - or, the relationship is expected to nave a longer tenn. In
17 addition, suppliers to less healthy finns (firms that are nearer distress) are
18 likely to provide less attractive terms of trade --for example, requiring <:ash
19 payment rather than accepting trade credit. 8oth of these - higher prices
20 or worse trade and mK:lit terms - wHI materialize as higher costs for the
21 utility, which will in turn likely be passed on to customers via higher .priGes
22 for energy. SimUar arguments can be made for other stakeholders <>f the
23 firm, such as employees of the firm. Employees of firms that a~ mor-e
2007 Texas Rate Case 1-0-1]
Entergy Gulf States, Inc. Page 10of 19
Direct Testimony of Jay C. Hartzell
2007 Texas Rate Case ·
1 likely to become financially distressed will likely demand higher wages in
2 order to compensate them for the risks they face in working for such a
3 company. Absent a StJfftcient wage differential, financially distressed firms
4 are likely to lose skilled and talented employees and to find it difftcUlt to
5 attract good new ones, further exacerbating these firms' situations.
6 In summary, by providing managers with incentive compensation
7 that is based in part on the financial performance of the firm, managers
8 have incentives to keep the firm financially healthy. A utility's financial
9 health is very likely to benefit customers via lower oosts than otherwise
10 would be experienced, which in tum lead to lower rates than otherwise
11 would be the case. These lower costs occur because of (I) a lower cost of
12 capital; (ii) more efficient operations; (iii) greater scale of production;
13 (iv) better investment decisions by managers; and {v) better prices and/or
14 terms from stakeholders, such as suppliers and employees.
15
16 B. The Reasons for Providing Financial-Based Incentive Compensation
17 Q. WHAT TOPICS DO YOU DISCUSS IN THIS SUBSECTION OF YOUR
18 TESTIMONY?
19 A. I explain how incentive compensation is used as an effective tool in
20 aligning the interests of a firm's employees and its stakeholders, including
21 the firm's customers and shareholders. I also discuss how this improved
22 incentive alignment motivates a firm's employees to take actions that tend
23 to ultimately benefit the firm-including customers and shareholders.
2007 Texas Rate Case 10~12
Entergy-Gulf States, Inc. Page11of19
Direct Testimony of Jay C. Hartzel
2007 Texas Rate C8se
1 a. WHAT IS THE BASIC UNDERLYING THEORY OF INCENTIVE
2 COMPENSATION AS IT APPLIES TO A PUBLICLY·TRADED
3 COMPANY?
4 A. The traditional paradigm of incentive-based compensation centers around
5 the role of incentive pay in solving a •moral hazard• problem, where the
6 principals involved cannot observe the actions of an agent who acts on
7 their behalf. This agent is expected to act in a way that maximizes his or
8 her personal welfare, which is not necessarily the same set of actions that
9 would maximize the welfare of the principals. This potential conflict of
10 interest, tenned an agency problem, gives rise to a role for incentive
11 compensation. Because the principats cannot observe or write eontraots
12 based on the ager.it's actions (because it is assumed that those actions
13 cannot be observed or legally verified), incentives are put in place such
14 that the agent is more likely to benefit when they take the oourse of action
15 that is desired by the principals. SpecificaUy, the agent receives higher
16 pay when he or she takes actions that benefit the principals.
17 Understanding this, the agent is mor.e likely to take those actions desired
18 by the principal - put forth more effort, -pick better projects, or shirk less,
19 tor example.
20 The typical view in finance is from the .perspective of the
21 sharehotders: shareholders are the principals and owners of the finn, and
22 they hire managers to act as agents on their behalf. Incentive pay has a
23 role in tt)at it provides for greater compensation to managers when there
2007 Texas Rate Case 10-13
Entergy Guff Slates, Inc. Page12of19
Direct Testlmony of Jay C. Hartzetl
2007 Texas Rate Case
1 are indications that they took actions that benefited shareholders. One of
2 the most fundamental and accepted theoretical results from the principal-
3 agent academic literature is that an agenfs pay should be linked to a
4 particular performance measure (such as stock price, accounting profits.
5 or a score based on customer satisfaction) if that measure provides an
6 additional informative signal of the manager's actions.
7 If a principal (such as the Commission) has a goal of maximizing
8 customer welfare. then the same principal·agent theory still applies. In
9 this context, pay should optimally be related to any performance measure
10 that contains marginally useful information about whether managers acted
11 in a way that Is consistent with maximizing customer welfare. In other
12 words. even if the goal is to maximize customer welfare, pay should also
13 be related to financial performance so long as the financial perfonnance
14 measures contain some additional information about customer welfare.
15
16 Q. HOW CAN INCENTIVES BASED ON FINANCIAL MEASURES IMPROVE
17 MANAGERS' FOCUS ON CURRENT AND FUTURE CUSTOMER
18 SERVICE?
19 A In the extreme, this most basic principal-agent theory is developed in a
20 one-period setting, without regard to future periods. In this set.up, the
21 manager acts, outcomes are realized at the end of the period (depending
22 in part on those actions). and the manager receives his or her pay.
2007 Texas Rate Case 10-14
Entergy Gulf States, Inc. Page13of 19
Direct Tatimony of Jfl'f C. Hartzell
2007 Texas Rate Case
1 A more realistic setting would allow for multiple periods, where both
2 managers and principals would have to consider not only their immediate
3 actions, but also their expected Mure actions, and trade-offs between
4 what they choose to do today versus what they may receive in the future.
5 This more realistic setting leads to another common problem or incentive
6 conflict between managers and principals: these parties having differing
7 time horizons. Typically, managers are expected to have a shorter..term
8 focus than otherwise would be optimal. As a result of their possibly
9 shorter time horizons, managers may make decisions that focus solely on
10 the short term at the expense of the long-term. Incentive compensation
11 tied to measures that look both to the short-tenn (such as the current
12 year's earnings) and long-term {such as stock price) is an accepted
13 solution to extend the managers' time horizons. and to balance short-term
14 and long-tenn perspectives, in decision-making and execution.
15
16 a. DOES EXTENDING THE MANAGERS' TIME HORIZONS HAVE A
17 POSITIVE EFFECT ON EXPECTED CONSUMER WELFARE?
18 A. Yes. In the context of maximizing -customer welfare. the horizon of the
19 manager is an important issue. To the extent the Commission wishes to
20 maintain and .enhaooe -customer welfare not only in the short-run, but also
21 in the future, financial measures like stock price performance play a useful
22 role in an incentive oompensation structure in order to aocomplish this
23 objective.
'2007 T-exas Rate Case 10-15
Entergy Gulf States, Inc. Page14fof 19
Direct Testimony of Jay C. Hartzell
2007 Texas Rate Case
1 In addition to providing incentives for managers to optimize their
2 decisions in the current year. a financial-based incentive plan can provide
3 this perspective by capitalizing the long-term benefits of managers'
4 decisions. In other words, via incentives based .on financial perfonnance
5 measures such as stock Priee. the expected long-term impact of
6 managers' decisions has immediate impad on financial perfonnance
7 measures, thereby affecting managers' pay and incentives. Stock prices
8 are based on the present value of the firm's expected future cash flows.
9 So, by making a manager's compensation depend on stock price. one ties
10 the manager's wealth to expected future cash flows. This makes him ~
11 her more willing to make decisions that produce long-term benefits for the
12 firm, even if it is at the cost of short.term cash flows or profits.
13
14 a. HOW DO FINANCIAL-BASED INCENTIVES EXTEND THE MANAGERS'
15 TIME HORIZONS TO THE BENEFIT OF CONSUMER WELFARE?
16 A. To see how incentive pay affects customer welfare over multiple years,
17 first take an extreme hypothetical example where managers are only
18 compensated based on this year's customer welfare. This could create an
19 incentive for the manager to make deeisions that would sacrifice the future
20 of the finn (and its customers) for the benefit of the Immediate welfare of
21 customers. The manager might •over·lnvest" in immediate customer
22 service, weakening the finn's future financial position and its ability to
23 provide high-quality. low cost service in the future. With limited resources,
2007 Texas Rate Case 10~16
Entergy Guff States, Inc. Page 15of 19
Direct T.estimony of Jay C. HartzeM
2007 Texas Ratecase
1 the firm might decide to pay for this •over-investmenr In immediate
2 customer service by taking money from long-tenn maintenance spending
3 or capital investment that would produce long-term efficiency or
4 productivity gains.
5 But, by linking a manager's pay at least in part to the financial
6 health of the firm, one forces the manager to think about more than just
7 the short term, and to consider future years and the future performance of
8 the firm when they decide on a course of action. If the manager over-
9 invested in immediate customer welfare, then it would weaken the firm's
10 financial position and potentially, consumers' future welfare. Conversely,
11 by weighing not only immediate customer welfare, but also financial
( 12 measures like stock price that are related to the firm's short- and long.term
13 viability, the manager has the incentive to position the firm to provide
14 higher levels of customer welfare in the future.
15
16 a. WHY SHOULD THERE BE A POSITIVE RELATION BETWEEN
17 CUSTOMER WELFARE AND FINANCIAL PERFORMANCE?
18 A. Back to the basic theory, then, financial measures should be part of the
19 manager's a>mpensation structure if one wants to maximize customer
20 welfare so long as those financial measures are related to {or are signals
21 of) customer welfare. This is plausible and r.easonable for several
22 reasons. First, customer welfare is difflcult to measure oompletely, so it is
23 unlikely that objective customer-based measures that one <:an use in a
2007 T-exas Rate Case 10-17
Entergy Gulf States, Inc. Page16of19
Direct Testimony of Jay C. Hartzell
2001 Texas Rate case
1 compensation structure will fully capture what is trying to be measured.
2 Then, so long as the firm's f11ancial performance is poaitively correlated
3 with customer welfare, in this period or in the future, financial performance
4 should optimally enter the compensation structure with positive weight
5 (meaning that the manager receives greater compensation when the
6 financial performance of the firm is greater). The accepted literature on
7 compensation theory Is clear that less-noisy (I.e ., more accurate) signals
8 of managers' actions are preferred over noisier (less accurate) signals, but
9 even noisy signals of managers' actions should be included in the optimal
10 compensation contract. Thus, so long as a financial measure such as
11 stock price is correlated with customer welfare (beyond what the
12 operational measures can explain), then it should enter the compensation
13 structure of the manager. The more accurate it is as a signal, the greater
14 weight (or bigger role) it should receive.
15
16 a. ARE THESE FINANCIAL THEORIES SUPPORTED BY EMPIRICAL
17 EVIDENCE?
18 A. Yes. There are multiple empirical studies published in peer-reviewed
19 academic joumals that report evidence consistent with these hypotheses.
20
21 a. HOW DO THESE EMPIRICAL STUDIES SUPPORT THESE
22 HYPOTHESES?
2007 Texas Rate Case 10-18
Entergy Gulf States, Inc. Page 17of 19
Direct T.estlmony of Jay C. Hartzell
2007 Texas 'Rate·Case
1 A. There is a wealth of existing empirical evidence that is supportive of these
2 theories. First, published papers have shown that customer satisfaction
3 measures are positively correlated with firms' financial perfonnance. In
4 other woros, firms with higher customer satisfaction scores tend to have
5 better financial performance, not worse. This fact from the -data is
6 consistent with the arguments above that more-satisfied customers are
7 expected to result in higher profits and belier overall financial
8 performance. This finding also suggests that financial measures -can play
9 a positive role in motivating managers to improve customer welfare. This
10 result of a positive relation between financial performance and customer
11 satisfaction is inconsistent with the idea that managers tend to maximize
( 12 financial performance to the detriment of customers, which should help
13 alleviate some fears that contracts incorporating financial-performance
14 incentives will lead managers to diminish their customers' welfar:e for the
15 sake of greater financial performance and higher compensation. In the
16 data, financial success tends to be associated with gr.eater wstomer
17 satisfaction, not iess.
16 There is also evidence that higher wstOmer satisfaction scores are
19 associated with higher market values across firms. This empirical result is
20 consistent with the widely-held notion that the s1ock market is a
21 mechanism by which the long-term benefits of customer welfare are
22 capitalized into a present value measure. This 1esult that higher customer
23 satisfaction scores are associated with higher market values has been
2007 Texas Rate Case 10-19
Entergy Gulf States, Inc. Page18of19
Direct Testlmony of Jay C. Hartzell
2007 Texas Rate Case
1 shown for a broad set of companies in general. and also for the utility
2 industry in particular.
3 Empirical evidence also suggests that these relations between
4 customer satisfaction and financial petformance change as customer
5 satisfaction becomes very high. This change is consistent with the idea
6 that there are diminishing (financial) returns to improving customer
7 satisfaction. implying that it becomes more and more expensive to keep
8 improving customer satisfaction. Such an increasing cost of customer
9 satisfaction is consistent with the notion discussed earlier that providing
1O managers with incentive compensation that is only based on this pe~'s
11 customer welfare measures might lead managers to over-invest in current
12 customer welfare to the detriment of the long-tenn financial health of the
13 firm, potentially endangering future customer welfare, as well. As also
14 discussed earlier, including measures such as stock price in the
15 compensation structure of managers can help provide incentives for
16 managers to not only consider the immediate welfare of customers, but to
17 also weigh future years' customer welfare and the fenancial health of the
18 company when they make decisions while running the firm.
19 The evidence on firms in or near financial distress is also consistent
20 with the opinions presented earlier that firms that are more likely to enter
21 into financial distress are more likely to encounter significant costs of
22 distress, which could materialize in the form of higher future costs for
23 customers and lower future customer welfare {compared to the <:0sts that
2007 Texas Rale Case 10-20
Entergy Gulf States, Inc. Page 19of 19
Direct Testimony of Jay C. Hartz.eH
2007 Texas Rate Case
1 would have been realized without the firm in distress). There is evidence
2 that finns with more debt (relative to their equity) suffer more when their
3 industries do not do well. Heavily indebted firms tend to invest less and
4 lose more sales in industry downturns when compafed to their less-
5 indebted industry counterparts, which would be expected to lead to higher
6 average costs in industries with economies of scale, such as the utility
7 industry. In addition, it has been shown that these finns with more debt
8 tend to be penalized by customers and suppliers, again leading to greater
9 costs than what one would have experienced without such distress.
10 .
11 Q. CAN YOU DRAW ANY CONCLUSIONS BASED UPON THESE
( 12 COMMONLY ACCEPTED ECONOMIC AND FINANCIAL PRINCIPLES?
13 A. Yes. These theoretical arguments are intuitive and based on sound,
14 commonly accepted economic and financial principals Thus, it is possible
15 to draw conclusions based upon the ·application of logic to fundamental
16 finance principles. In my opinion, the existing empirical evidence is
17 supportive of the conclusion that incentive compensation siructures that
18 include financial-based performance measures-tend to benefit oonsumers.
19
20 Q. DOES THIS CONCLUDE YOUR PREFILED DIRECT TESTIMONY?
21 A. Yes.
UIJ7 Texas Rate Case 10-21
APPENDIX B
Direct Testimony of Dr. J. Hartzell
in PUCT Docket No. 37744
SOAH Docket No. 473~10-1962
PUC Docket No. 37744
ETI Exhibit No. 14
DOCKET NO. - - -
(
APPLICATION OF ENTERGY § PUBLIC UTILITY COMMISSION
TEXAS, INC. FOR AUTHORITY §
TO CHANGE RATES AND § OF TEXAS
RECONCILE FUEL COSTS §
DIRECT TESTIMONY
OF
JAY C. HARTZELL, PHO.
ON BEHALF OF
ENTERGY TEXAS, INC.
DECEMBER 2009
2009 ETI Rate Case 4-357
ENTERGY TEXAS, INC.
(
DIRECT TESTIMONY OF JAY C. HARTZELL, PHO.
2009 RATE CASE
TABLE OF CONTENTS
I. Background and Introduction 1
II. Overview of the Issues Surrounding Incentive Compensation 3
Ill. The False Dichotomy Between Compensation Tied to "Financial"
Measures and Compensation Tied to "Operational" Measures; and
the Benefits of Cost Control, Profitability, and Stock Price Measures 8
IV. Costs to Customers of Discouraging the Use of Incentive
Compensation That is Linked to Cost Control, Profitability and
Stock Prices 18
V. Response to Common Arguments Against Incentive Compensation
Linked to Cost Control, Profitability and Stock Prices from the
Customers' Perspective 23
VI. Empirical Evidence Supporting Testimony 25
VI I. Conclusion 28
EXHIBITS
EXHIBIT JCH-1 Curriculum Vitae of Jay C. Hartzell
2009 ETI Rate Case 4-358
Entergy Texas, Inc. Page 1 of 28
Direct Testimony of Jay C. Hartzell, PhD.
2009 Rate Case
1 I. BACKGROUND AND INTRODUCTION
2 Q. PLEASE STATE YOUR NAME, TITLE, AND BUSINESS ADDRESS.
3 A. My name is Jay C. Hartzell. I am an Associate Professor of Finance at the
4 Mccombs School of Business at the University of Texas at Austin. My
5 business address is Department of Finance, The University of Texas at
6 Austin, 1 University Station 86600, Austin, Texas 78712.
7
8 Q. ON WHOSE BEHALF ARE YOU TESTIFYING?
9 A. I am testifying on behalf of Entergy Texas, Inc. ("ETI" or the "Company"}.
10
11 Q. PLEASE STATE YOUR EDUCATION, PROFESSIONAL AND WORK
12 EXPERIENCE.
13 A. I obtained a Bachelor of Science degree (cum laude) from Trinity
14 University in May 1991, with majors in Business Administration and
15 Economics. After graduating, I went to work as a consultant for Hewitt
16 Associates, in The Woodlands, Texas. Hewitt is a consulting firm that
17 specializes in benefits and compensation. While there, I specialized in the
18 area of defined contribution plans. I left Hewitt to go to graduate school at
19 the University of Texas at Austin in 1993. l completed my PhD in finance
20 there in May 1998. Upon graduating, I took a job as an Assistant
21 Professor of Finance at New York University's Stern School of Business,
22 where I worked until 2001. At that time, the University of Texas at Austin
I
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23 hired me as an Assistant Professor at the Mccombs School of Business
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1 ("Mccombs School ), where I have worked since. I was promoted to the
2 rank of Associate Professor (with tenure), effective in the fall 2006.
3 Beginning in the fall of 2008, I was given the title of Allied Bancshares
4 Centennial Fellow. I also now serve as the Executive Director of the Real
5 Estate Finance and Investment Center at the Mccombs School. My
6 current curriculum vitae is attached as Exhibit JCH-1.
7
8 Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE A REGULATORY
9 COMMISSION?
10 A. Yes. I have submitted written testimony on incentive compensation issues
11 and testified on behalf of the Company before the Public Utility
12 Commission of Texas ("Commission" or "PUCT") in PUCT Docket No.
13 34800, and on behalf of Entergy Louisiana, LLC before the Louisiana
14 Public Service Commission on incentive compensation issues in Docket
15 No. U-20925. I have also submitted written testimony on behalf of Entergy
16 Arkansas, Inc. before the Arkansas Public Service Commission on
17 incentive compensation issues in Docket No. 09-084-U.
18
19 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
20 A. The purpose of my testimony is to discuss the extent to which incentive
21 compensation - including compensation based on dollar-based measures
22 such as cost control, profitability, and stock prices - is linked to and
23 benefits customers' interests for companies such as ETI.
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1 11. OVERVIEW OF THE ISSUES SURROUNDING INCENTIVE
2 COMPENSATION
3 Q. WHAT FORMS OF INCENTIVE COMPENSATION DO YOU FOCUS ON
4 IN YOUR TESTIMONY?
5 A. The focus of my testimony is on incentive compensation that is linked to
6 cost control measures (for operating costs and capital expenditures),
7 profitability measures (including earnings and operating cash flow), and
8 stock prices. Compensation that is linked to these sorts of measures - for
9 companies generally and for ETI in particular - include annual incentive
10 plans, long-term incentive plans, restricted stock grants, and stock option
11 grants. The compensation could come in the form of cash (as in annual
12 incentive plans), stock or stock-based units (as in ETl's long-term
13 incentive plan, or "L TIP"), or options.
14
15 Q. WHAT IS YOUR UNDERSTANDING OF HOW COMPENSATION BASED
16 ON COST CONTROLS, PROFITABILITY AND STOCK PRICES HAS
17 BEEN CHARACTERIZED IN RECENT PUCT RATE DECISIONS?
18 A. In such cases, compensation that is linked to cost controls, profitability
19 and stock prices as discussed in the previous question has commonly
20 been referred to as incentive compensation that is based on "financial
21 measures." This category of incentives has been distinguished from
22 incentive compensation that is based on measures that are not
23 denominated in dollars, such as customer satisfaction, reliability, and
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1 safety metrics, which has commonly been categorized as incentive
2 compensation based on "operational measures." As I discuss later in my
3 testimony, I view this as a false dichotomy for the purposes of assessing
4 whether customers benefit from a particular form of incentive
5 compensation.
6
7 Q WHY DO FIRMS USE INCENTIVE COMPENSATION IN GENERAL, AND
8 COMPENSATION BASED ON COST CONTROLS, PROFITABILITY AND
9 STOCK PRICES MORE SPECIFICALLY?
10 A. Incentive compensation is a prevalent tool used to attract, motivate, and
11 retain the .qualified and talented employees needed to ensure that a
12 business can continue to operate successfully. To understand why it is so
13 widely used, it is first useful to draw a distinction between the level and
14 form of compensation. The level of compensation can be thought of as
15 the total dollar value of compensation received by an employee from all
16 sources, including salary, cash incentive-based pay, the value of
17 long-term incentives such as stock performance units and options granted
18 (albeit typically applicable to a much smaller group of employees), and the
19 value of benefits. In order to attract and retain employees, this level
20 needs to be in line with the labor market for a particular type of employee,
21 whether it is an engineer, a maintenance worker, or a chief executive
22 officer. Otherwise, all things equal, that same employee will take a job
23 with a company that is offering the more attractive level of pay and
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1 benefits. Company witness Kevin G. Gardner discusses the overall
2 reasonableness of ETl's level of compensation in his direct testimony.
3
4 Q. HOW DOES THE FORM OF COMPENSATION DIFFER FROM THE
5 LEVEL OF COMPENSATION?
6 A. The form of compensation can be thought of as the split of total
7 compensation across these components - for example, how much is paid
8 via salary versus annual incentive-based compensation. Holding the total
9 level of compensation fixed at the proper market level, the form of
10 compensation is important because it can help motivate employees to
11 engage in behaviors that positively impact the operational efficiency of the
12 firm, or positively affect its cost structure. At the same time, the form of
13 compensation is important to attract and retain certain types of employees
14 that offer a skill set or a particular talent that is important to the company's
15 operations. For example, if a compensation plan provides for incentive
16 payments if goals are met - such as controlling costs at some level - then
17 according to basic economic theory, employees will be motivated to work
18 harder toward those goals. More subtly, such incentive pay will tend to
19 attract and retain employees who believe that they are especially good at
20 controlling costs because they will expect higher compensation under
21 such a plan. This implies that a firm seeking to manage costs will find it
22 valuable to institute such an incentive compensation plan as part of the
(
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1 design of the form of compensation, while keeping the level of
2 compensation at a competitive market-based amount.
3
4 Q. WHAT IS YOUR UNDERSTANDING OF THE COMMISSION'S
5 PREVIOUS VIEW ON ALLOWING THE RECOVERY OF INCENTIVE
6 COMPENSATION EXPENSE THROUGH RATES?
7 A. My understanding of the Commission's recent rulings on this issue is that
8 the Commission has distinguished between compensation tied to what it
9 has termed operational measures and compensation tied to what it has
10 termed financial measures. Generally, the Commission has not allowed
11 for the recovery of incentive compensation tied to financial measures
12 through rates, but has allowed for the recovery of incentive compensation
13 tied to operational measures. The core rationale for this distinction has
14 been that it has not been sufficiently demonstrated that incentive
15 compensation linked to financial measures is in the public interest or of
16 direct benefit to customers. The decisions in those previous cases,
17 however, do not reflect a review or consideration of the relevant literature
18 or other matters I discuss below, all of which support a conclusion that
19 allowing utilities to use incentive pay based on cost control, profitability,
20 and stock prices is properly viewed as in the public interest and is
21 expected to be of direct benefit to customers.
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1 Q. HOW WOULD YOU SUMMARIZE YOUR OPINION ON THE ISSUE OF
2 WHETHER INCENTIVE COMPENSATION BASED ON COST
3 CONTROLS, PROFITABILITY, AND STOCK PRICES BENEFITS
4 CUSTOMERS?
5 A. In my opinion, a well-designed compensation plan that includes incentive
6 compensation tied to cost controls, profitability, and stock prices would
7 tend to provide greater benefit to customers than an otherwise similar
8 compensation plan that did not include any such incentive compensation.
9 I discuss the details below, but the overarching basis for my opinion is as
10 stated above: incentive compensation based on cost control, profitability,
11 and stock prices helps companies attract, motivate, and retain talented
12 employees, and by doing so, both customers and shareholders directly
13 benefit. Moreover, if ETl's inc~ntive compensation were only based on
14 non-dollar-based measures such as safety and reliability, customers
15 would tend to be worse off, because such a plan would not provide
16 employees with incentives to look after the financial health of the
17 Company. The important point is that customers and shareholders both
18 benefit from well-designed, balanced compensation plans that provide
19 employees with the appropriate level of compensation and that include
20 incentives based on cost control, profitability, stock prices, and
21 non-dollar-based measures such as reliability, safety and customer
22 satisfaction.
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1 111. THE FALSE DICHOTOMY BETWEEN COMPENSATION TIED TO
2 "FINANCIAL" MEASURES AND COMPENSATION TIED TO
3 "OPERATIONAL" MEASURES; AND THE BENEFITS OF COST
4 CONTROL. PROFITABILITY, AND STOCK PRICE MEASURES
5 Q. DO YOU AGREE WITH THE OPINION THAT INCENTIVE
6 COMPENSATION LINKED TO WHAT THE COMMISSION HAS TERMED
7 "FINANCIAL MEASURES" DOES NOT PROVIDE DIRECT BENEFITS TO
8 CUSTOMERS?
9 A. No. Based on its previous rulings, the Commission appears to be
10 categorizing as "financial" all incentive performance measures that have
11 been labeled as such by the utility and that are based on dollar amounts.
12 These include not only measures such as earnings per share, but also
13 measures designed to promote cost containment. 1 In reading these
14 decisions and the debates among the parties discussed therein, much of
15 the discussion seems to take it as given that incentives linked to financial
16 (or dollar-based) measures, regardless of their specific characteristics, do
17 not benefit customers. As a result, the competing viewpoints reflected in
18 these decisions seem to address mainly whether to label particular
19 measures as operational or financial. 2
20 Instead of focusing on whether a particular measure is dollar-based
21 or not - and therefore, whether incentives linked to that measure are
22 "financial" or "operational" based on the above dichotomy - I think it is
For example, see PUC Docket No. 28840, PFD at 78.
2
For example, see PUC Docket No. 35717, PFD at 98.
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1 more worthwhile to return to the primary question: whether specific
2 incentives linked to dollar-based measures (including cost control,
3 profitability, and stock prices) are of benefit to customers.
4
5 Q. WHY WOULD INCENTIVE COMPENSATION LINKED TO COST
6 CONTROL, PROFITABILITY, AND STOCK PRICE MEASURES BE OF
7 DIRECT BENEFIT TO CUSTOMERS?
8 A. This is the case because these measures provide a necessary and
9 important incentive to managers to improve service and control costs.
10 Perhaps the easiest example of a dollar-based measure that could be
11 used in an incentive compensation plan that would benefit customers
12 directly is cost containment. As an example, consider an incentive
13 compensation plan that pays corporate managers an incentive award if
14 costs are suitably contained. On the one hand, such an incentive is likely
15 to benefit shareholders to some extent - managers who work under such
16 a compensation plan will work to control costs in order to achieve their
17 incentive compensation, and to the extent that they are successful, the
18 company will generate greater profits, benefiting shareholders. But
19 customers also directly benefit, because the company has lower costs,
20 and through the regulatory process, customers will ultimately pay lower
21 rates than they otherwise would have paid in the absence of such cost
22 controls.
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1 Q. WHAT IS THE ROLE OF THE REGULATORY PROCESS IN ENSURING
2 THAT INCENTIVES LINKED TO COST CONTROL BENEFIT
3 CUSTOMERS?
4 A. To understand the role of the regulatory process in linking cost control to
5 customer benefit, first consider an extreme example where there is no
6 regulatory lag and rates adjust instantaneously so that any change in a
7 utility's costs is immediately passed through to customers. In this case, a
8 cost-containment incentive clearly directly benefits customers and does
9 not benefit shareholders at all because customers reap the entire benefit
10 of any cost-saving innovations. In the other extreme, if rates never adjust
11 to changes in costs, then a cost-containment incentive benefits
12 shareholders but not customers. Thus, the regulatory process plays the
13 critical role of sharing the gairis from cost controls brought about by
14 managerial incentive compensation between customers and shareholders.
15
16 Q. IS THIS POINT THAT CUSTOMERS BENEFIT FROM MANAGERIAL
17 EFFICIENCY A COMMONLY ACCEPTED TENANT OF UTILITY RATE
18 ECONOMICS?
19 A. Yes. This idea of a win-win scenario, where both shareholders and
20 customers benefit from managerial efficiency, is not new and is a core
21 idea at the heart of well-established principles of regulatory economics.
22 For example, James C. Bonbright discusses it in his seminal 1961 treatise
23 on utility economics, Principles of Public Utility Rates. He notes that a
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1 potential drawback to regulated rates based on cost-plus-return pricing is
2 that it could discourage managerial efficiency because the firm would earn
3 little to no greater return after an efficiency gain because of a resultant
4 change in rates. He goes on to say that regulatory lag can help resolve
5 this problem, for the reasons discussed above. From his discussion, it
6 follows naturally that incentive compensation that links managerial
7 compensation to cost savings would likely be of benefit to customers.
8
9 Q. DO THESE PRINCIPLES APPLY TO OTHER FORMS OF INCENTIVE
10 COMPENSATION THAT ARE LINKED TO PROFITABILITY AND STOCK
11 PRICE MEASURES?
12 A. Yes. While I think that cost containment measures are the most obvious
13 example of incentives that have in some past PUCT cases been
14 categorized as "financial" and yet directly benefit customers, these
15 principles apply to other dollar-based or financial measures as well, such
16 as incentive awards tied to corporate profitability and stock prices.
17
18 Q. CAN YOU PLEASE FURTHER ELABORATE ON WHY CUSTOMERS
19 ARE LIKELY TO BENEFIT FROM COMPENSATION THAT IS LINKED
20 TO PROFITABILITY?
21 A. Yes. There is a direct link between cost containment and company
22 earnings, especially for a regulated utility. Managers with an incentive to
23 increase earnings will focus on controlling or cutting costs in a regulated
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1 industry because it is more difficult to grow revenues. Additionally, the
2 same type of reasoning that supports a linkage between cost containment
3 and customer benefit also applies to incentive measures that focus on
4 containing capital expenditures. If managers can offer the same service
5 while cutting back on capital expenditures by investing more efficiently,
6 then shareholders benefit due to greater short-run cash flows for the
7 company, and customers benefit through the regulatory process through
8 lower recovery for the cost of capital due to a lower capital base.
9
10 Q. WHAT TYPE OF INCENTIVE COMPENSATION DO YOU INCLUDE
11 WITHIN THE CATEGORY OF COMPENSATION THAT IS LINKED TO
12 STOCK PRICES?
13 A. This category would include most long-term incentive plans (including
14 ETl's) that use performance units that are based on stock prices, as well
15 as stock options.
16
17 Q. CAN YOU BRIEFLY SUMMARIZE WHY YOU BELIEVE THAT
18 COMPENSATION THAT IS LINKED TO STOCK PRICES BENEFITS
19 CUSTOMERS?
20 A. Compensation that is linked to stock prices has several advantages for
21 customers as long as it is part of a reasonable, well-designed
22 compensation plan - in other words, as long as the total level of
23 compensation is reasonable compared to the market for similar positions
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1 and the form of compensation is well balanced across dollar-based and
2 non-dollar-based measures. First, compensation that is linked to stock
3 prices helps ensure that managers will consider the financial health of the
4 company when they make decisions, and it is in customers' interests to
5 have the company continue to be financially healthy. Second,
6 stock-based compensation provides an incentive for managers and
7 employees to ensure that the company operates efficiently, and via the
8 regulatory process, lower costs result in lower rates than would otherwise
9 occur. Third, stock-based compensation provides a monitoring
10 mechanism for managerial decision making and the overall quality of
11 management. Fourth, there is an interaction between these effects, as the
12 capital markets will tend to reward efficient long-term investments or
13 capital expenditures that will also lead to lower costs for customers.
14
15 Q. DO THESE REASONS THAT COMPENSATION THAT IS LINKED TO
16 STOCK PRICES BENEFITS CUSTOMERS ALSO APPLY TO
17 COMPENSATION THAT IS LINKED TO COST CONTROL AND
18 PROFITABILITY?
19 A. In general, yes. Stock prices are driven in part by cost control and
20 profitability, so to the extent that managers have an incentive to increase
21 the stock price, they will also have an incentive to control costs and
22 increase profits and cash flows, and vice versa. Of the reasons listed in
23 the previous answer, the first two reasons - incentives to ensure that the
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1 company is financially healthy and that it operates efficiently - are the
2 ones that are most closely shared by compensation based on cost control
3 and profitability.
4
5 Q. STARTING WITH THE FIRST REASON YOU MENTIONED, WHY DOES
6 COMPENSATION THAT IS LINKED TO PROFITABILITY AND STOCK
7 PRICES BENEFIT CUSTOMERS BY IMPROVING A COMPANY'S
8 FINANCIAL HEALTH?
9 A. If compensation that is linked to profitability and stock prices gives
10 managers an incentive to increase their company's earnings, cash flows,
11 and stock price, then this will also provide them with an incentive to
12 ensure that the company remains financially healthy. Stock prices of firms
13 that are in poor financial condition - for example, that have high debt
14 relative to the value of their assets - tend to be lower, all else being equal.
15 Similarly, firms in poor financial condition tend to have lower earnings and
16 operating cash flows. A stronger financial condition will also benefit
17 customers. If a company maintains a financially healthy position, it will
18 tend to have a lower cost of capital that will in turn benefit customers
19 through lower rates. For a discussion of this effect, see Chapter 15 of
20 Investment Valuation, by Aswath Damodaran. 3 In addition, the costs of
21 doing business with suppliers (of both goods and services, including labor)
3
ASWATH DAMODARAN, INVESTMENT VALUATION (John Wiley & Sons, 2d ed. 2002).
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1 will remain lower. For example, if a company was not in a financially
2 stable condition, suppliers would tend to demand higher prices or more
3 onerous credit terms, resulting in higher costs that would lead to higher
4 rates than would otherwise occur. These are often termed "indirect costs
5 of financial distress," and are a commonly accepted concept in finance
6 that is supported by empirical evidence as I discuss further below.
7
8 Q. CAN YOU FURTHER EXPLAIN HOW INCENTIVE COMPENSATION
9 THAT IS LINKED TO PROFITABILITY AND STOCK PRICES CAN TEND
10 TO LEAD TO LOWER COSTS FOR CUSTOMERS?
11 A. The first step is to understand that compensation linked to profitability and
12 stock prices will provide managers with an incentive to operate efficiently
13 because, by doing so, a company's profitability (including earnings and
14 cash flow) and stock price will be higher than it would otherwise be. To
15 increase stock price, management tries to maximize the present value of a
16 company's expected cash flows by minimizing expenses and the cost of
17 capital. The role of incentive compensation in motivating managers to
18 minimize the cost of capital component and the associated benefits to
19 customers were discussed earlier. A second channel provided by
20 incentive compensation that can benefit customers is the incentive to
21 maximize the company's cash flows. In a regulated environment,
22 particularly one in which promotion of sales growth is discouraged, it is
(
\ 23 likely to be more difficult to increase cash flows or profits by growing
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1 revenues, so management will tend to focus on efficient operations and
2 investment.
3 These lower costs will benefit shareholders in the short run, but
4 customers over the long run. This is due to the regulatory process that
5 directly links operating costs to rates. In fact, it is my understanding that
6 the Formula Rate Plan proposed in this case provides for an even more
7 direct link between cost savings and rates due to the frequency of reviews
8 and reflection of any identified cost savings in customer rates. This
9 channel is similar to the discussion earlier as to why incentive
10 compensation that is based on cost controls will tend to benefit customers.
11
12 Q. HOW DOES COMPENSATION THAT IS LINKED TO STOCK PRICES
13 BENEFIT CUSTOMERS VIA THE MONITORING OF MANAGERIAL
14 DECISIONS?
15 A. One of the functions of the stock market and its various participants is to
16 monitor companies' management. In their efforts to properly value stocks,
17 analysts, portfolio managers, and traders follow companies and
18 continually assess the various decisions, announcements, and pieces of
19 information they produce. In doing so, they act as a monitoring device,
20 ensuring that poor decisions would be punished by a falling stock price, so
21 managers have incentives to invest the shareholders' financial resources
22 efficiently. In this manner, managers help keep customers' costs lower
23 than they might otherwise be in the absence of such monitoring, and
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1 improve the overall quality of service. An example of such evidence, cited
2 in one study, shows that institutional investors can help ensure that
3 management does not act myopically to cut research and development
4 expenditures in order to meet short-term earnings targets. 4
5
6 Q. HOW DO THESE INVESTMENT AND COST EFFECTS INTERACT DUE
7 TO THE STOCK MARKET?
8 A. An important role for stock-based compensation is to encourage
9 managers to refrain from sacrificing long-run success in pursuit of
10 short-term profit. 5 Stock prices are based not just on a company's
11 performance in the current year, but also on the market's expectations
12 about a company's future performance over many years. This ensures
13 that good investments tend to increase stock prices, even though those
14 investments use cash today in order to produce greater cash flows in the
15 future. This is a critical advantage of stock-based compensation over
16 annual incentive plans that are based on a particular year's (or a few
17 years') performance. Stock-based .compensation can help overcome
18 managerial myopia and provide managers with an incentive to make
19 efficient, long-term investments that benefit both customers (due to
4
Brian J. Bushee, The Influence of Institutional Investors on Myopic R&D Investment Behavior,
73 THE ACCOUNTING REVIEW, 3 at 305-333 (July 1998).
5
For example, see M.P. Narayanan, Form of Compensation and Managerial Decision Horizon,
31 JOURNAL OF FINANCIAL AND QUANTITATIVE ANALYSIS, 4 at 467-491 (1996).
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1 efficient investments that lead to lower costs) and shareholders (due to
2 higher cash flows). In this case, the testimony of Company witnesses
3 Joseph F. Domino and Chris E. Barrilleaux addressing the Company's
4 expected future capital investments, and that of Company witness Robert
5 R. Cooper regarding long-term resource planning, provide examples of
6 such consideration.
7
8 IV. COSTS TO CUSTOMERS OF DISCOURAGING THE USE OF
9 INCENTIVE COMPENSATION THAT IS LINKED TO COST CONTROL,
10 PROFITABILITY AND STOCK PRICES
11 Q. WHILE YOUR EARLIER TESTIMONY DISCUSSED THE BENEFITS TO
12 CUSTOMERS OF USING INCENTIVE COMPENSATION THAT IS
13 LINKED TO COST CONTROL, PROFITABILITY AND STOCK PRICES,
14 ARE THERE ALSO NEGATIVE IMPACTS TO CUSTOMERS OF NOT
15 USING STOCK-BASED COMPENSATION?
16 A. Yes. In my opinion customers would be adversely affected if ETI did not
17 include such incentive compensation. in its overall compensation policy.
18
19 Q. STARTING WITH AN EXTREME EXAMPLE OF A COMPENSATION
20 POLICY WHERE ALL EMPLOYEES WERE ONLY PAID WITH
21 SALARIES, CAN YOU HIGHLIGHT THE IMPACT TO CUSTOMERS OF
22 SUCH A POLICY?
23 A. Yes. First, it is useful to note that if employees did not receive any
24 incentive compensation, salaries would have to be much higher in order to
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attract and retain the same quality of talent. Second, costs would likely
rise and employee performance would likely suffer, as it would be difficult
to effectively and efficiently motivate employees to take actions that would
benefit shareholders and customers. In my opinion, customers would be
worse off under such a policy. This is supported by the principle that
individuals respond to incentives (a basic tenet of economics), and by
empirical work that shows workers' output responds to the institution of an
incentive plan.6
WOULD CUSTOMER INTERESTS BE ADVERSELY AFFECTED IF A
COMPANY USED SALARY AND INCENTIVES LINKED TO MEASURES
THAT HAVE BEEN TERMED "OPERATIONAL" ONLY? IN OTHER
WORDS, IF THEY PROVIDED. SALARY AND INCENTIVES BASED ON
MEASURES LIKE RELIABILITY AND SAFETY, BUT NO INCENTIVES
BASED ON COST CONTROL, PROFITABILITY AND STOCK PRICES?
Yes. I believe customers would be worse off under such a compensation
policy. On the one hand, incentives linked to what have beP.n termed
"operational" measures can improve customer welfare because the
company can better attract, motivate and reta in talented employees.
Compared to the hypothetical case where a company compensates its
employees with salary only, by using salary and incentives linked to, for
6
( Edward P. Lazear, Performance Pay and Productivity, 90 THE AMERICAN ECONOMIC REVIEW,
at 1346-1361 (December 2000 ).
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1 example, safety or reliability, the company can pay less in salary and use
2 the associated savings to contribute to the annual incentive plans. On the
3 other hand, such a compensation plan still has substantial problems in the
4 context of customer benefits.
5 First, there is still no free lunch - employees' salaries and incentive
6 payments linked to operational incentives would have to be larger than
7 they otherwise would be if the firm also offered incentive compensation
8 linked to cost control, profitability and stock prices in order for the firm to
9 compete in the market for labor. Second, such a compensation plan
1O would not provide any incentives for employees and managers to control
11 costs. If employees only had incentives to improve non-cash measures of
12 performance, such as safety and reliability, then they would likely
13 over-invest in these measures relative to what customers might prefer, at
14 the expense of alternative investments that would produce lower costs for
15 customers. For example, if management only had incentives based on
16 wait times when customers called with questions or complaints (plus a
17 base salary), then they would have an incentive to hire enough staff such
18 that customers never had to wait if they called to ask a question.
19 However, if you left it up to customers , they would likely view it as
20 worthwhile to run the risk of having to wait for a little while on rare
21 occasions if it meant that their service was provided at a lower cost and
22 those cost savings were passed along to customers through the regulatory
23 process.
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1 Third, a compensation plan consisting of salary and incentives
2 based solely on annual measures of operational performance could likely
3 lead to "horizon problems." By horizon problems, I mean that managers
4 tend to have a natural tendency, absent incentives, to focus on the short
5 run at the expense of the long run. Stock prices by their nature are
6 forward looking. Taken together, a compensation plan that included
7 incentives based on annual measures such as reliability and customer
8 satisfaction, but not incentives based on cost controls, profitability and
9 especially stock prices, could provide incentives for managers to maximize
10 their immediate compensation at the expense of longer-run benefits that
11 the customer could have enjoyed. 7
12 For example, consider a manager facing a decision whether to hire
13 additional staff to answer phones in a call center (and bring down phone
14 wait times) or to invest the same amount in a capital investment to put in
15 place a new, more centralized call center that would produce significantly
16 lower costs several years in the future. If the manager is paid purely in
17 cash compensation including an incentive payment based on current-year
18 customer satisfaction surveys (that would include phone wait times), then
19 the manager would be more likely to forgo the long-term investment
20 project and increase payroll by hiring additional employees in order to
21 maximize his or her incentive pay by implementing the short-term solution
7
See M.P. Narayanan, Form of Compensation and Managerial Decision Horizon, 31 JOURNAL
(, ' OF FINANCIAL AND QUANTITATIVE ANALYSIS, 4 at 467-491 (1996).
2009 ETI Rate Case 4-379
Entergy Texas, Inc. Page 22 of 28
Direct Testimony of Jay C. Hartzell, PhD.
2009 Rate Case
1 today. But, at some point, customers are better off by having slightly
2 longer waits on the phone now but reaping the benefits of lower overall
3 costs in the future. A well-designed compensation plan that includes
4 incentives linked to both customer satisfaction (in this example) and cost
5 control, profitability and stock prices would provide incentives for the
6 manager in this example to properly consider the benefits of such a long-
7 term investment without sacrificing current customer satisfaction.
8
9 Q. HOW DOES THE INCLUSION OF INCENTIVE COMPENSATION THAT
10 IS LINKED TO COST CONTROLS, PROFITABILITY AND STOCK
11 PRICES HELP AVOID THESE NEGATIVE OUTCOMES FOR
12 CUSTOMERS?
13 A. If a company adds compensation that is linked to cost controls,
14 profitability, and stock prices to a compensation plan that includes base
15 salary and incentives based on non-cash based measures in a reasonable
16 way, customers are likely to be better off. Such incentive compensation
17 helps a company attract, motivate, and retain talented employees and
18 gives managers a reason to focus on the long run in addition to the current
19 year's performance, costs, customer service, and the like.
20 This focus on the longer run is evident in the design of ETl's LTIP
21 and stock option plan. For example, ETl's LTIP bases its payments in a
22 particular year on the achievement of goals over the previous three years,
23 encouraging managers to consider consistent and long-term success as
2009 ETI Rate Case 4-380
Entergy Texas, Inc. Page 23 of 28
Direct Testimony of Jay C. Hartzell, PhD.
2009 Rate Case
(
1 key objectives. Plus, options granted vest over a three-year period,
2 forcing managers to think about future years and how the firm will be
3 viewed several years into the future. The stock options also have a life of
4 ten years, which provides an additional incentive to focus on the long
5 term. Such a focus on maximizing stock price over a ten-year period is
6 beneficial for all stakeholders. As stock options may be awarded annually,
7 option grants present a rolling ten-year window for those employees who
8 receive them, reinforcing that long-term view. Finally, the provision that
9 requires senior managers to continue to hold stock received via exercising
10 option grants up to a multiple of their salary further encourages longer-run
11 thinking and incentive alignment, as managers cannot exercise all their
12 options for cash and be immune to declines in the firm's financial health.
13
14 V. RESPONSE TO COMMON ARGUMENTS AGAINST INCENTIVE
15 COMPENSATION LINKED TO COST CONTROL. PROFITABILITY AND
16 STOCK PRICES FROM THE CUSTOMERS' PERSPECTIVE
17 Q. HOW DO YOU RESPOND TO THE ARGUMENT THAT INCENTIVE
18 COMPENSATION THAT IS LINKED TO COST CONTROL,
19 PROFITABILITY, AND STOCK PRICES WILL BE DETRIMENTAL TO
20 CUSTOMERS BECAUSE IT WILL CAUSE MANAGERS TO CUT
21 CUSTOMER SERVICE-RELATED EXPENSES TO INCREASE
22 PROFITS?
23 A. This argument underscores the importance of a well-balanced
24 compensation plan. By including both incentives based on non-dollar
2009 ETI Rate Case 4-381
Entergy Texas, Inc. Page 24 of 28
Direct Testimony of Jay C. Hartzell, PhD .
2009 Rate Case
(
1 based measures such as customer service, reliability and safety, and
2 incentives based on cost control, profitability and stock price, as does ETI,
3 management will not want to cut one in order to increase the other, but will
4 instead look for balanced decisions that help both.
5
6 Q. IS THERE REASON TO BE CONCERNED FROM THE CUSTOMERS'
7 PERSPECTIVE BECAUSE STOCK PRICES AND PROFITS ARE
8 DRIVEN BY MANY OTHER FACTORS IN ADDITION TO
9 CONTROLLING COSTS, OR HAVING A LOW COST OF CAPITAL?
10 A. No. Avoiding this concern is why firms generally do not use compensation
11 plans that consist solely of stock- or profit-based incentive pay - to do so
12 would be too risky for the employees and would lead to larger overall
13 compensation expense because risk-averse individuals would demand
14 higher compensation levels in order to compensate them for bearing the
15 risk of such a hypothetical plan. This is also why stock- and profit-based
16 incentive compensation is more important at the top of the organization.
17 Senior management can more clearly see (and anticipate) the impact of
18 their actions on the firm's stock price, so stock-based compensation is a
19 more efficient compensation tool for this level of management.
2009 ETI Rate Case 4-382
Entergy Texas, Inc. Page 25 of 28
Direct Testimony of Jay C. Hartzell, PhD.
2009 Rate Case
(
1 VI. EMPIRICAL EVIDENCE SUPPORTING TESTIMONY
2 Q. ARE THE CONCEPTS IN SUPPORT OF THE CUSTOMER BENEFITS
3 OF INCENTIVE COMPENSATION SUPPORTED BY EMPIRICAL
4 EVIDENCE?
5 A. Yes. As I discuss below, there are multiple studies published in
6 peer-reviewed journals that report evidence that is consistent with my
7 testimony.
8
9 Q. IS THERE EMPIRICAL EVIDENCE THAT THE ADOPTION OF
10 INCENTIVE TARGETS BASED ON STOCK OR EARNINGS
11 PERFORMANCE BENEFITS CUSTOMERS?
12 A. Yes. There is a published study that examines the adoption of long-term
13 incentive plans that reward managers with stock or stock-based
14 compensation, where the stock grants are based on long-run profitability.8
15 The study finds that after the adoption of such plans, managerial
16 compensation is more closely linked to the interests of managers and
17 stakeholders, including customers. This is also consistent with the studies
18 I discuss below, such as one that links market value with customer
19 satisfaction.
8
( Alka Arora and Pervaiz Alam, CEO Compensation and Stakeholders' Claims,
<-.. 22 CONTEMPORARY ACCOUNTING RESEARCH, 3 at 519-547 (Fall 2005).
2009 ETI Rate Case 4-383
Entergy Texas, Inc. Page 26 of 28
Direct Testimony of Jay C. Hartzell, PhD.
2009 Rate Case
1 Q. HOW DO OTHER EMPIRICAL STUDIES SUPPORT THE OPINION
2 THAT INCENTIVE COMPENSATION TIED TO STOCK OR
3 PROFITABILITY BENEFITS CUSTOMERS?
4 A. Earlier, I mentioned two empirical studies that provide support for my
5 opinion that stock-based incentive compensation provides benefits to
6 customers. The first study provides evidence of how the oversight of
7 companies' performance by stock-market participants can affect those
8 firms' investment behavior and curtail managerial myopia. 9 This is one of
9 the channels I discussed earlier by which the presence of stock-based
10 incentive compensation can benefit customers by encouraging managers
11 to focus beyond the short term and think about long-term efficient
12 investments. The second study shows that workers do respond to
13 incentive plans in a manner consistent with the intent behind the plans'
14 design. 10 Thus, if a company adopts a compensation plan that includes
15 incentives based on customer welfare and stock price, one can expect
16 managers to take actions to improve customer welfare and maximize
17 stock price (holding all else equal).
18 In addition, there is empirical evidence in the literature that firms
19 with higher market values tend to also have higher customer satisfaction,
20 supporting the conclusion that the goals of financial success and customer
9
Brian J. Bushee, The Influence of Institutional Investors on Myopic R&D Investment Behavior,
73 THE ACCOUNTING REVIEW, 3 at 305-333 (July 1998).
10
Edward P. Lazear, Performance Pay and Productivity, 90 THE AMERICAN ECONOMIC REVIEW,
at 1346-1361 (December 2000).
2009 ETI Rate Case 4-384
Entergy Texas, Inc. Page 27 of 28
Direct Testimony of Jay C. Hartzell, PhD.
2009 Rate Case
(
1 satisfaction are interrelated. 11 This result has been shown for a broad
2 sample of firms, but also for utilities in particular. This empirical finding is
3 inconsistent with the idea that the most profitable or valuable firms
4 become that way by cutting customer service, and instead suggests that
5 there exists positive feedback between a firm's financial performance
6 (stock price) ·and customers' welfare, even in the utility industry.
7 Empirical evidence also exists that some firms hurt their financial
8 performance (stock price) by overinvesting in customer service.12 This
9 result suggests that including stock price in the compensation plan will
10 help ensure against myopic investments in short-term service that would
11 come at the expense of investments that would produce greater long-term
12 benefits to customers. It also points toward the conclusion that basing
13 incentive compensation for purposes of setting rates solely on operational
14 goals could well be harmful to customers' interests in the long run .
15 Finally, there is empirical evidence that firms with lower stock prices
16 (or that are less financially healthy) face higher costs and greater risks.
17 For example, some researchers have shown how less financially healthy
18 companies have trouble responding to external shocks, and face higher
19 costs of doing business (through higher wages or worse terms from
11
Christopher D. Ittner and David F. Larcker, Are Nonfinancial Measures Leading Indicators of
Financial Performance? An Analysis of Customer Satisfaction, 36 JOURNAL OF ACCOUNTING
RESEARCH, Supplement 1998 at 1 - 35.
( 12 Id.
2009 ETI Rate Case 4-385
Entergy Texas, Inc. Page 28 of 28
Direct Testimony of Jay C. Hartzell, PhD.
2009 Rate Case
1 suppliers, for example). 13 These results support yet another channel by
2 which stock-based incentive compensation should provide direct benefits
3 to customers. Stock-based incentive compensation encourages
4 managers to maintain a company's financial health, thus leading to more
5 efficient operations and greater cost control than would otherwise occur.
6
7 VII. CONCLUSION
8 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
9 A. Yes, at this time.
13
Chris Parsons and Sheridan Titman, Capital Structure and Corporate Strategy (January
2007). The article is available at http://ssrn.com/abstract=983553.
2009 ETI Rate Case 4-386
~, :'., ·'; r f V ED
.1,., it •• .,
SOAH DOCKET NO. XXX-XX-XXXX zao~ FEB -9 PM 2: 21
PUC DOCKET NO. 28840 PUBLIC UTILIT y COMHISSION
FILING CLERK
APPLICATION OF AEP TEXAS § BEFORE THE STATE OFFICE
CENTRAL COMPANY FOR § OF
AUTHORITY TO CHANGE RATES § ADMINISTRATIVE HEARINGS
REDACTED
DIRECT TESTIMONY
OF
SARAH J. GOODFRIEND, PH.D.
ON BEHALF OF
CITIES SERVED BY AEP TEXAS CENTRAL COMPANY
FEBRUARY 9, 2004
1
2 DIRECT TESTIMONY OF
3 SARAH J. GOODFRIEND, PH.D.
4 TABLE OF CONTENTS
5
6 SECTION PAGE
7
8 I. INTRODUCTION AND ORGANIZATION OF TESTIMONY ................................... 6
9
10 A. PRINCIPAL FINDINGS AND RECOMMENDATIONS ................................. 7
11 B. ORGANIZATION OF TESTIMONY ............................................................... 12
12
13 II. CUSTOMER SERVICE PROVIDED BY TCC TO THE
14 RETAIL MARKET ......................................................................................................... 12
15
16 A. STANDARD OF EVALUATION ....................................................................... 13
17 1. DESCRIPTION OF UNNECESSARY COSTS .................................... 13
18 2. PURA STANDARDS: WHEN UNNECESSARY
19 COSTS BECOME UNACCEPTABLE COSTS ................................... 15
20 3. PURA/ECONOMIC FRAMEWORK: THE
21 ALIGNMENT STANDARD ................................................................... 16
22
23 B. SURVEY DESCRIPTION AND RES UL TS ..................................................... 23
24 1. INTRODUCTION AND ORGANIZATION ......................................... 23
25 2. NUMERICAL RESULTS ....................................................................... 25
26 3. QUALITATIVE RESULTS .................................................................... 29
27 LACK OF RESPONSIVENESS TO REP INQUIRIES ....................... 30
28 NO EDUCATIONAL PROGRAMMING AND
29 OUTREACH TO REPS .......................................................................... 32
30 INACCURACIES AND UNRESPONSIVENESS
31 WORSEN MARKET PROBLEMS ....................................................... 35
32 BILLING AND INVOICING: FOUNDATIONS
33 FOR ERROR ............................................................................................ 46
34 SLOW OR NO GO ON FASTRAK RESOLUTIONS ......................... 56
35
36 c. REBUTTAL TO TCC WITNESSES GORDON AND HOOPER .................. 62
37 1. ISA SERVICE QUALITY ...................................................................... 62
38 SUMMARY FINDING ............................................................................ 62
39 WITNESS GORDON .............................................................................. 63
40 REPORTED PERFORMANCE FOR THE ISA .................................. 65
41 WITNESS HOOPER ............................................................................... 67
42 TCC REPORTED BILLING ACCURACY MEASURE ..................... 69
DIRECT TESTIMONY 2 GOODFRIEND
1 2. SERVICE QUALITY REPORTING:
2 RECOMMENDATION ........................................................................... 70
3
4 III. REQUEST FOR GOOD CAUSE EXCEPTION .......................................................... 71
5
6 A. NEITHER ABD O&M SERVICES NOR TRANSMISSION
7 CONSTRUCTION SERVICES COMPLY WITH SUBST. R.
8 §25.342(.t)(D) Orf HER SERVICE ....................................................................... 71
9 1. REGULATED UTILITY PROVISION OF
10 UNREGULATED SERVICES: DEFINITIONS
11 AND DISTINCTIONS ............................................................................. 71
12 LEGAL FRAMEWORK ......................................................................... 71
13 THE QUID PRO QUO IN RULE-COMPLIANT
14 OTHER SERVICE .................................................................................. 75
15 DEFINING "ESSENTIAL" FOR RULE-COMPLIANCE ................. 78
16 2. TCC HAS YET TO DEMONSTRATE COMPLIANCE
17 WITH THE OTHER SERVICE EXCEPTION .................................... 81
18 THIS IS A SITUATION OF FIRST IMPRESSION ............................ 81
19 INSTRUCTION TO CSW: NO ADDS SOLELY
20 FOR OTHER SERVICE ...................................................................•..... 83
21 TWO EXAMPLE VIOLATIONS AND RELATED
22 CROSS-SUBSIDIES ................................................................................ 84
23 THE EXTENT OF CROSS SUBSIDY .................................................. 87
24 PROBLEMS OF DETECTION .............................................................. 91
25 EVIDENCE OF ANTI-COMPETITIVE POTENTIAL ...................... 92
26
27 B. THE THIRD VIOLATION: TRANSMISSION CONSTRUCTION
28 SERVICE IS NOT AN ESSENTIAL TDSP SYSTEM SERVICE .................. 94
29
30 C. EFFECTS OF GRANTING A GOOD CAUSE EXCEPTION ........................96
31
32 IV. PROPOSED DISCRETIONARY SERVICE FEES .....................................................98
33
34 V. REQUEST FOR PRE-APPROVAL OF DEBT RECOVERY .................................. 108
35
36 VI. RATE CASE EXPENSES ............................................................................................. 113
37
38 APPENDIX A - Resume
39
40 EXHIBIT -SJG-1 Retail Electric Provider Survey
DIRECT TESTIMONY 3 GOODFRIEND
LIST OF ACRONYMS - TERMINOLOGY
Associated Business Development, the category used by TCC to indicate
ABD
unregulated wholesale business activities
AEP-CSW American Electric Power -- Central and South West
BAO Billing and Accounting Operations
ERCOT Electric Reliability Council of Texas
ERCOT
Published standards and requirements for all market participants
Protocols
ESI-ID A unique numerical identifier for each premise location in ERCOT
ERCOT sponsored process for market participants to use in resolving
FASTRAK electronic transaction-related problems in retail markets
GAAP Generally Accepted Accounting Principles
ISA Integrated Stipulation and Agreement
IT
Information Technology
MAC SS
Marketing And Customer Services System
REP retail electric provider or competitive retailer
RMS Retail Market Subcommittee ofERCOT
TCE Texas Commercial Energy
Texas Standard Electronic Transaction -- the market wide electronic standard
Texas SET
for electronic data interfacing (EDI) transactions
DIRECT TESTIMONY 4 GOODFRIEND
TNMP Texas New Mexico Power Company
TXU Texas Utilities
Electronic transaction whereby TDSP acknowledges a switch request to
814-04/05
ERCOT and ERCOT then sends the acknowledgement to the REP
867s,
Electronic transactions containing initial, monthly or historical usage data
867series
TABLE OF FIGURES
1. FIGURE!: RELATIVE RANK OF TCC AMONG ERCOT TDSPS
2. FIGURE 2: TCC GRADE DISTRIBUTION FROM REP SURVEY
3. FIGURE 3: RESPONSIVENESS TO REP INQUIRES
4. FIGURE 4: EDUCATIONAL PROGRAMMING AND OUTREACH
5. FIGURE 5: BUSINESS CASE CUSTOMER CHOICE OPERATIONS
6. FIGURE 6: RESPONSIVENESS IN RESOLVING MARKET PROBLEMS
7. FIGURE 7: METER READING ACCURACY
8. FIGURE 8: 550,000 ADDITIONAL ESTIMATED METER READS -
POTENTIAL MARKET COSTS
9. FIGURE 9: TEXAS CENTRAL COMPANY COMPARISON OF PERCENT
CANCELLED INVOICES [REDACTED TABLE]
10. FIGURE 10: RESPONSIVENESS IN RESOLYING FASTRAK PROBLEMS
11. FIGURE 11: ERCOT: 8678 RECEIVED ON CANCELED SERVICE
ORDERS
12. FIGURE 12: POTENTIAL FOR CROSS-SUBSIDY OF WHOLESALE
OPERATIONS BY RETAIL OPERATIONS (BY JOB TITLE)
DIRECT TESTIMONY 5 GOODFRIEND
1 I. INTRODUCTION AND ORGANIZATION OF TESTIMONY
2
3 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
4 A. My name is Sarah Goodfriend and my business address is 1500 West 24th Street,
5 Austin, Texas 78703.
6 Q. BRIEFLY DESCRIBE YOUR EXPERIENCE AND QUALIFICATIONS
7 RELEVANT TO THIS PROCEEDING.
8 A. As an economic consultant specializing in competition and regulatory policy issues, I
9 have twenty-five years of experience in the regulated electric utility and
10 telecommunications industries. Prior to entering graduate school, I was employed as
11 an economist by the Public Utility Commission of Texas ("PUCT"). In 1983, I
12 worked for Carolina Power And Light Company, receiving a Ph.D. in economics
13 from the University of North Carolina at Chapel Hill in 1985. Since that time, I have
14 worked and testified on behalf of the Economic Policy Office of the Federal Energy
15 Regulatory Commission and the Bureau of Economics of the Federal Trade
16 Commission. I returned to the PUCT in 1992 to create an Office of Economic Policy
17 and was appointed a PUC Commissioner in 1993, serving until 1995. Before starting
18 my consulting practice, I joined the Washington D.C. office of MCI
19 Telecommunications Corporation where I was responsible for policy development
20 and providing expert witness testimony. I have been an independent consultant since
21 1997.
22 As an independent consultant, I provided expert testimony on behalf of South
23 Texas Electric Cooperative and a Central Power and Light Wholesale Customer
24 group in the AEP-CSW merger proceedings. Since then, as my resume shows, I have
DIRECT TESTIMONY 6 GOODFRIEND
1 remained active as an advisor or testifying witness on behalf of various market
2 participants in the electric utility and telecommunications industries. Most recently, I
3 have worked as an advisor to a group of Retail Electric Providers ("REPs") pursuant
4 to their participation in the Texas Nodal Team stakeholder meetings. Some of these
5 REPs are active in the TCC service territory.
6 Q. ON WHOSE BEHALF ARE YOU PROVIDING THIS TESTIMONY?
7 A. I have been retained by Cities served by AEP Texas Central Company ("Cities").
8 AEP Texas Central Company ("TCC") is the monopoly TDSP for these Cities in their
9 role as market participants, end-use customers and ratepayers.
10 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
11 A. Cities desire that the rates and operations of TCC not hinder the development of a
12 competitive market. Cities' experience with the deregulated market has not been
13 good. I have been asked to identify cross-subsidies, anti-competitive behavior and
14 areas where improvements to quality of service can be made. My testimony evaluates
15 TCC's (1) quality of service to retail customers, (2) request for good cause exception
16 Subst. R. §25.342(f)(D), (3) proposed discretionary service fees and (4) request for
17 pre-approval for recovery of REP bad debt expense.
18 A. PRINCIPAL FINDINGS AND RECOMMENDATIONS
19 Q. WHAT ARE YOUR PRINCIPAL FINDINGS?
20 A. My testimony reaches these principal findings:
21 1. The quality of service that TCC is providing to REPs, end-use customers and
22 the market is unacceptable and contrary to provisions of the Public Utility Regulatory
23 Act ("PURA").
DIRECT TESTIMONY 7 GOODFRIEND
1 2. The structure of TCC costs supports difficult to detect cross-subsidy of
2 wholesale operations by using and placing retail ratepayer dollars at risk.
3 3. TCC's request for a good cause exception to the PUCT's Electric Business
4 Separation Subst. R. § 25.342(f)(D) Other Service would permit greater
5 circumvention of the PUCT's Unbundling Rules than now exists.
6 4. Transmission Construction Services and Associated Business Development
7 ("ABD") Operation and Maintenance ("O&M") Services are the two categories of
8 service that TCC offers pursuant to the Other Service exception. Neither class of
9 service complies with the requirements of Subst. R. § 25.342(f)(D)(i).
10 5. TCC's Transmission Construction Service is principally supplied using
11 personnel non-essential to T&D system operations. To avoid future cross-subsidies,
12 TCC's best course of action is to create a stand-alone Construction Services operation
13 separate from the regulated utility business.
14 6. TCC's non-compliance with requirements of Subst. R. § 25.342(f)(D) Other
15 service is consistent with evidence of high Administrative and General expense but
16 declining staffing/resources for retail operations that Dr. Patton finds and is also a
17 likely reason for the poor service quality for regulated retail operations that Dr. Patton
18 and I find.
19 7. Various changes need to be made to TCC's proposed Discretionary Service
20 Tariff fees, terms and conditions to improve service quality and better align TCC's
21 tariff offerings with market needs.
22 8. TCC's request for pre-approval for deferral and inclusion of any REP bad debt
23 expense is premature and contrary to policy.
DIRECT TESTIMONY 8 GOODFRIEND
1 Q. WHAT ARE YOUR PRINCIPAL RECOMMENDATIONS?
2 A. I recommend the Commission:
3 1. Adopt a rate of return recommendation consistent with the requirements of
4 PURA Sec.36.052 to recognize the poor quality of services TCC now provides.
5 2. Direct TCC to return to the lower level of estimated meter readings it reported
6 for each customer class prior to the inception of the retail Choice Pilot project.
7 3. Deny TCC's request for a good cause waiver of Subst. R.
8 § 25.342(f)(D)(ii)(III) Other services. Thus, The Commission should direct TCC to
9 apply the $2,542,584.341 profit TCC has failed to record as a revenue credit in this
10 proceeding to reduce the total revenue requirement in this case. 2
11 4. Immediately place a moratorium on TCC's acceptance of new Transmission
12 Construction contracts. The moratorium should not be lifted until (a) TCC
13 demonstrates compliance with Subst. R. §25.342(f)(D) Other service, or, as a
14 preferred alternative, (b) separates Transmission Construction Services completely
15 from unregulated utility operations in ERCOT.
16 5. Immediately place a moratorium on TCC's acceptance of new ABD O&M
17 contracts until (a) TCC demonstrates compliance with Subst. R§ 25.342(f)(D) Other
18 Service and (b) TCC implements the REP-survey recommendations listed below.
19 6. Direct TCC to implement the following changes to its Discretionary Service
20 tariff fees, terms and conditions:
I Profit from Updated Response to Cities 17-14, provided in Workpapers.
2 Response to Staff BA 1-5. Margins received from third-party contracts for transmission services were booked
to FERC Account No. 417-Revenues from Non-utility operations.
DIRECT TESTIMONY 9 GOODFRIEND
I a) 6.1.2.1.8 Inaccessible Meter Fee should remain a Denial of Access to
2 Meter Fee. TCC should retain responsibility to document, upon request,
3 customer denial of access.
4 b) 6.1.2.1.6 Special Meter Reading Fee should not be charged when a REP
5 requests an actual meter re~d on an outstanding bill with estimated usage.
6 c) An Account History Fee should not be charged to end-users, REPs or
7 aggregators of record. 3
8 d) 6.1.2.1.13 Copying Fee, 6.1.2.15 Special Products/Service Fee or other fee
9 may not be charged as a substitute for the Account History Fee.
10 e) 6.1.2.1.16 Special Billing Services Fee, 6.1.2.1.13 Copy Fee or 6.1.2.15
11 Special Products/Service Fee shall not be charged to REPs or aggregators
12 requesting a Detailed Billing and Invoicing Analysis.
13 f) TCC's terms and conditions are not in compliance with Consumer
14 Protection Rules as proposed. TCC should be directed to conform its tariff
15 to the rule adopted in Docket No. 27084.
16 7. Deny TCC's request to defer any bad debt expense incurred in providing
17 service to REPs and deny TCC's request for grant of authority in this rate proceeding
18 to include such costs in TCC's next base rate case.
19 8. Direct TCC to file as non-confidential the "B Report" portion of TCC's
20 Quarterly Performance Report that ERCOT now files confidentially on behalf of
21 TCC.
3 The Account History Fee does not appear in the tariff as a proposed or existing discretionary service and so
has no tariff reference number.
DIRECT TESTIMONY 10 GOODFRIEND
1 Q. PLEASE PROVIDE THE LIST OF REP-SURVEY RECOMMENDATIONS
2 YOU REFER TO IN YOUR FIFTH RECOMMENDATION ABOVE.
3 A. The list is:
4 • Increase dedicated resources and reorganize job responsibilities so each REP has
5 a dedicated REP relations person. (Now there is one person "dedicated" to all
6 REPs).
7 • Create and apply job performance metrics to reward job performance relating to
8 REP satisfaction.
9 • At no charge, prepare a Detailed Billing and Invoicing Analysis for different
10 classes of meters and services for each REP or aggregator that requests it.4
11 • Schedule and offer at least one face-to-face meeting between REPs and their
12 customer service representatives annually.
13 • Provide current usage information to aggregators upon request for all active
14 premise locations ("ESI-IDs") that have provided a letter of authorization for their
15 usage information to be released to the aggregator.
16 • Annually perform an anonymous Customer Satisfaction Survey for REPs and
17 aggregators.5
18 • Provide Commission staff with a software and staffing improvement plan
19 identifying timetables, targets and budgets for Customer Service business and
4 Alternatively, TCC should produce a manual of information necessary for the REP/aggregator to perform
detailed analysis. A Detailed Billing and Invoicing Analysis includes the breakout and definition of each
charge type which underlies any composite charge provided, so that the bill or invoice may be readily
understood and interpreted.
5 The survey should be modeled on the anonymous telephone survey now being performed by CenterPoint
TDSP for REPs. Perform this survey until granted waiver of this requirement by the Commission. File the
results publicly with the Commission.
DIRECT TESTIMONY 11 GOODFRIEND
1 related Information Technology operations to improve TCC's performance with
2 protocols and other measures of quality of service discussed here.
3 Q. HOW ARE YOUR RECOMMENDATIONS RELATED TO YOUR
4 FINDINGS?
5 A. My recommendations lay out what is necessary for the PUCT to do in this proceeding
6 to (1) gain control over the unnecessary costs that TCC is imposing on the ERCOT
7 market by providing poor service quality at retail and (2) eliminate the cross-subsidies
8 of wholesale operations that TCC is providing from retail ratepayers.
9 B. ORGANIZATION OF TESTIMONY
10 Q. HOW IS YOUR TESTIMONY ORGANIZED?
11 A. This concludes Section I, Principal Findings and Recommendations. In Section II, I
12 evaluate the Customer Service TCC provides to the retail market. Section III
13 addresses TCC's request for good cause exception to §25.342(f)(D)(ii)(III) and
14 includes compliance issues related to TCC's provision of unregulated wholesale
15 service. Section IV addresses TCC's proposed discretionary service fees and Section
16 V addresses TCC's request for certain treatment of REP bad debt expense. The
17 testimony concludes with support for rate case expenses in Section VI.
18 II. CUSTOMER SERVICE PROVIDED BY TCC TO THE RETAIL MARKET
19 Q. WHAT ARE YOUR FINDINGS?
20 A. (1) AEP has unnecessarily imposed significant costs on the market, on market
21 participants, and thereby, on the quality of service the market delivers to end use
22 customers.
DIRECT TESTIMONY 12 GOODFRIEND
1 (2) AEP lacks concern for TCC's retail customers. This lack of concern results in
2 missed opportunities to improve market performance at little or no cost to TCC.
3 (3) AEP management understaffs and undersupports TCC customer service functions
4 necessary for market development and for the delivery of acceptable service quality
5 to end users.
6 (4) Without regulatory action in this proceeding, TCC will continue to provide a case
7 study in how TDSP interests fail to align with market needs.
8 A. STANDARDOFEVALUATION
9 1. DESCRIPTION OF UNNECESSARY COSTS
10 Q. WHAT DO YOU MEAN BY "UNNECESSARY COSTS"?
11 A. Unnecessary costs are costs imposed when a TDSP fails to perform acceptably in all
12 dimensions of service: (1) quality and timeliness of communication, (2) speed of
13 response, (3) pro-active problem solving, (4) dedication of resources and (5) accuracy
14 of response. When any one of these dimensions of service deteriorates, the customer
15 begins to experience unnecessary costs of doing business. Said differently, a TDSP
16 that is able to excel in these performance areas is contributing to minimizing the costs
17 of doing business in the market, and probably minimizing its own long-term costs of
18 providing customer service as well. End-use customers are the ultimate beneficiaries
19 when a TDSP is performing acceptably in all dimensions of service, thereby avoiding
20 unnecessary costs to market participants and consumers.
DIRECT TESTIMONY 13 GOODFRIEND
1 Q. HOW ARE END-USE CUSTOMERS HARMED BY UNNECESSARY COSTS?
2 A. Customers are harmed in three ways:
3 First, a customer suffers directly from unnecessary delay and inaccuracy. A delayed
4 bill means the customer cannot budget or exercise control over electricity costs.
5 Second, customers are harmed by prices higher than they need to be. And, third,
6 customers are harmed because it is not rational for REPs to market, develop a
7 reputation or differentiate their products on the basis of service quality.
8 Q. WHY ARE PRICES HIGHER THAN THEY NEED TO BE?
9 A. There are two paths by which prices to end-use customers increase. Economists
10 understand that in competitive markets, any increase in a suppliers' cost of doing
11 business must ultimately lead to a price increase. Unnecessary costs increase the
12 REP's cost of doing business. Because REPs must ultimately pass along service costs
13 imposed by an inefficient TDSP to end use customers, these unnecessary costs can be
14 thought of as an implicit or hidden tax on REPs, and ultimately on end-use customers.
15 Q. WHAT IS THE SECOND PATH TO HIGHER PRICES?
16 A. By raising all REPs' cost structures, unnecessary costs operate as an implicit
17 reduction in headroom. This understanding is why the Commission has been
18 concerned since before the onset of Customer Choice with "headroom". The
19 reduction in headroom is the second path whereby unnecessary costs result in a price
20 increase to end users. A reduction in headroom can limit entry or force market exit of
21 otherwise worthy suppliers. In tum, this tends to raise prices to end-users by limiting
22 the size, number or extent of diversity among suppliers.
DIRECT TESTIMONY 14 GOODFRIEND
1 Q. WHAT IS THE PROBLEM CREATED FOR RETAIL SERVICE QUALITY?
2 A. With Customer Choice, REPs have become the closest link to customers for
3 enrollment, billing, and customer care services. Yet, the quality of service the REP
4 can provide can be no better than what the REP receives upstream from ERCOT or
5 the monopoly TDSPs. Thus, it makes no sense for REPs interested in differentiating
6 their service from their peers on the basis of superior service quality to invest in
7 resources that would allow them to do so, until risks associated with TDSP service
8 quality are controllable. This important dimension of REP competition cannot take
9 root without reliably acceptable upstream service quality from TDSPs and ERCOT.
10 2. PURA STANDARDS: WHEN UNNECESSARY COSTS
11 BECOME UNACCEPTABLE COSTS
12
13 Q. WHAT PURA STANDARDS ARE INSTRUCTIVE FOR AN ASSESSMENT
14 OF RETAIL SERVICE QUALITY?
15 A. First, PURA provides some qualitative standards for assessing service quality. For
16 example, Sec. 38.022 recognizes that an electric utility may not engage in a practice
17 that tends to restrict or impair competition. As just discussed, poor TDSP service
18 quality is such a practice in the context of an emerging competitive market.
19 Second, within the Customer Safeguards for Retail Competition section,
20 (PURA Sec. 39.101), the Commission must establish customer protection standards
21 that entitle customers to, among other things, bills presented in a clear format and in
22 language understandable by customers; accuracy of metering and billing; and other
23 information or protections necessary to ensure high-quality service to customers. The
24 customer is also entitled to prompt resolution of disputes with its chosen REP and
25 TDSP.
DIRECT TESTIMONY 15 GOODFRIEND
1 PURA recognizes the tendency of suppliers to deteriorate service quality as a
2 method of cost-cutting and so provides for the assessment of civil and administrative
3 penalties to enforce customer safeguards.
4 Q. DOES PURA PROVIDE OTHER STANDARDS?
5 A. Yes, PURA prohibits service from deteriorating relative to standards established
6 under integrated utility operation. PURA directs the PUCT to modify its current
7 customer protection rules on or before June 30, 2001 "to ensure at least the same level
8 of customer protection against potential abuses and the same quality of service that
9 exists on December 31, 1999 is maintained in a restructured electric industry."
10 (PURA Sec. 39.101(£)).
11 Finally, PURA provides for a timely enforcement action and the exercise of
12 some "incentive regulation," in that PURA requires the PUCT to consider quality of
13 service when setting the rate of return. (PURA Sec. 36.052).
14 3. PURA/ECONOMIC FRAMEWORK: THE ALIGNMENT
15 STANDARD
16
17 Q. ARE YOU OFFERING AN ECONOMIC FRAMEWORK FOR ANALYSIS
18 THAT YOU DERIVE FROM PURA'S STATUTORY STANDARDS?
19 A. Yes, I am. There is a simple way to understand how service quality provided by
20 TDSPs can deteriorate relative to the integrated utility world of December 1999.
21 Q. PLEASE EXPLAIN.
22 A. In the integrated utility/captive customer model, "the market" consisted of captive
23 customers, and captive customers or their representatives accessed the regulatory
24 process to provide effective feedback on utility operations. This regulatory model
25 encouraged the private incentives of utility management concerning quality of service
DIRECT TESTIMONY 16 GOODFRIEND
1 to be, depending on specifics of management and regulation, more or less aligned
2 with the interests of end-use customers (or at least aligned with regulatory perceptions
3 of end-user requirements).
4 Q. HOW SO?
5 A. Regulation could create incentives for the utility to align its expenditure pattern with
6 customer service requirements. In rate proceedings, regulators set prices and imposed
7 service standards. This kind of regulation provided readily available ways for end-
8 use customers or their representatives to access the regulatory process and express
9 dissatisfaction with rates, services, service offerings (rate design) and service quality.
IO Considering the total dollars at risk in generation, transmission and distribution
11 combined, utility efforts to respond to customers and manage customer relations were
12 a necessary asset-preservation investment strategy. Absent effective regulation, there
13 was no need to consider regulatory feedback effects on its balance sheet when making
14 cost/quality decisions.
15 Q. HOW HAVE THINGS CHANGED?
16 A. A new problem introduced by Customer Choice is one of "incentive alignment" for
17 the remaining regulated utility, the TDSP. One of the purposes of regulation is to
18 create incentives for a utility to "internalize" important externalities, in other words,
19 to create incentives for the utility to take into account the effects of its decisions and
20 actions on costs borne by others when this "internalization" is in the public interest.
DIRECT TESTIMONY 17 GOODFRIEND
1 Q. ARE YOU SAYING THAT AEP ISN'T PROVIDING TCC WITH ENOUGH
2 RESOURCES DEDICATED TO RETAIL CUSTOMER SERVICE QUALITY?
3 A. Yes, and I am saying more. Although a misallocation of resources is a part of the
4 answer, it is not the full answer.
5 Q. PLEASE EXPLAIN.
6 A. One can explain the poor quality of customer service at TCC as a consequence of
7 cost-cutting by AEP management in response to financial pressures (such as those
8 created by recent failed investments in unregulated businesses).6 To manage needed
9 cash flow, AEP allows the service quality offered by the regulated business to
10 deteriorate in order to compensate for cash flow lost by unregulated operations. This
11 describes a situation of unacceptable and impermissible cross-subsidy of the
12 unregulated operations by misallocation ofresources from the regulated business.
13 Although the evidence is consistent with this view, I believe this unacceptable
14 cross-subsidy is a symptom as well as a contributing factor to problems with
15 customer service at TCC. Said differently, even if AEP were not cross-subsidizing
16 losses, due to the incentive alignment problem I describe, we would still find TCC's
17 service quality to deteriorate with the arrival ofretail choice in ERCOT.
18 Q. WHY AREN'T AEP-TCC'S INCENTIVES TO PROVIDE QUALITY
19 SERVICE PROPERLY ALIGNED NOW?
20 A. Incentives have changed because the odds have changed. Especially in the case of
21 AEP, significant assets are no longer at risk in this regulatory proceeding. AEP has
6 See for example, the $5.8 million in trading losses that appears against Miscellaneous Income in TCC's Rate
Filing Package, WP II-E-5. See also AEP's Annual Report for 2002.
DIRECT TESTIMONY 18 GOODFRIEND
1 sold or will sell ERCOT assets upstream and downstream of its TDSPs. Unlike the
2 other TDSPs in ERCOT, AEP no longer has significant investment in affiliated REP
3 operations whose service quality depends, at least in part, on the service quality it
4 receives from the TDSP. Moreover, AEP is prohibited under its agreement with
5 Centrica from entering the ERCOT market as a residential and small commercial REP
6 until 2006.7
7 From a utility management perspective, generation is no longer subject to
8 rate-of-return regulation by Texas regulators. In ERCOT, the individual utility
9 transmission investment decision is now subjected to an ERCOT-wide priority
10 planning process and then annual costs are socialized. In subjecting major
11 transmission projects to ERCOT staff and stakeholder review, the ERCOT planning
12 process tends to operate like a pre-investment prudence review, reducing
13 disallowance risks (except perhaps for cost overruns) for larger transmission
14 investments. Thus, compared to the old world, the dollars at risk or exposure from
15 poor service quality are significantly reduced. End-use customers' dissatisfaction
16 with service from the distribution utility no longer poses the potential threat to
17 revenues or profits that it once did.
18 From an end-user perspective, finding the responsible party has become more
19 difficult and once found, the payoffs for effort are simply lower. With socialized
20 transmission costs, end-use customers of the TDSP are no longer directly responsible
21 for paying the costs of their TDSP's transmission investments. Thus, the payoff to
7 Notice and Request for Approval of Changes in Ownership and Affiliation of Mutual Energy CPL, LP and
Mutual Energy WTU, LP, May 22,2002 Docket No. 25957, Attachments.
DIRECT TESTIMONY 19 GOODFRIEND
1 end-use customers in terms of cost/bill reductions from using the regulatory process
2 to address concerns with service quality has declined.
3 Moreover, the complexity and interdependence of market transactions
4 necessary in order to provide end-user services has increased, requiring the
5 coordinated efforts of TDSPs, ERCOT and REPs. Not surprisingly, Customer Choice
6 engendered unprecedented levels of electricity customer complaints. 8 If customers
7 are unsure where responsibility lies, this complexity further reduces the pay-off to
8 end use customers or their representatives of holding a TDSP accountable for its
9 contribution (or lack thereof) in setting the level of service quality the market is
10 capable of providing.
11 Q. WHAT KIND OF STANDARDS HAS THE COMMISSION SET FOR TDSPS,
12 ERCOT AND REPS ?
13 A. The Commission has set quantitative standards for certain electronic transactions and
14 numerical and qualitative standards throughout its Customer Protection Rules.
15 Q. WHY HAS THE COMMISSION SET QUANTITATIVE STANDARDS FOR
16 CERTAIN ELECTRONIC TRANSACTIONS?
17 A. Essentially, the Commission has set quantitative standards for certain electronic
18 transactions in order to create accountability among parties for the success of highly
19 interdependent transactions.
8 See Report to the 78th Texas Legislature, Scope of Competition in Electric Markets in Texas, Public Utility
Commission of Texas, January 2003, page 106
DIRECT TESTIMONY 20 GOODFRIEND
Q. PLEASE EXPLAIN.
2 A. ERCOT is the central registration agent for retail premises and the electronic hub for
3 all retail electronic "enrollment" transactions. Electronic transactions are necessary
4 for customers to change REPs, change premises, receive electric service, etc. At the
5 beginning of the market, technical problems were affecting the ability of parties to
6 timely "turnaround" the necessary transactions.
7 Q. WHAT KIND OF STANDARDS APPLY TO TDSPS?
8 A. Standards are established for certain transactions by ERCOT Protocols. Some
9 standards also appear in TDSP tariffs. For example, when ERCOT sends a TDSP a
10 notice of a switch request, the ERCOT Protocol requires the TDSP to send an
11 electronic acknowledgement of the request back to ERCOT within two business days
12 of receipt. TDSPs are also required to send their invoicing out to REPs within tariff-
13 established time frames.
14 Q. WHAT ARE THE QUARTERLY PERFORMANCE REPORTS?
15 A. Among other things, Quarterly Performance Reports provide technical information
16 about several electronic transactions. To identify how successful ERCOT, TDSPs
17 and REPs are in moving electronic transactions over their interconnected networks
18 and in completing the necessary electronic lifecycles in a timely and accurate fashion,
19 the technical report examines some of the 47 standard electronic transactions in the
20 Texas market (Texas SET) that can occur. 9
9 Developed in response to early problems in turning around electronic transactions, the Performance Measure
Reports require that ERCOT report transaction volumes and "success rates" in completing electronic
transactions within established Protocols. The Commission established a benchmark for success rates equal to
98%. In other words, ERCOT, the TDSPs and REPs should strive to complete the electronic transactions that
are their portion of the turnarounds within Protocol, 98% of the time.
DIRECT TESTIMONY 21 GOODFRIEND
1 Q. DO THE QUARTERLY PERFORMANCE REPORTS PROVIDE OTHER
2 TECHNICAL INFORMATION?
3 A. Yes. Due to early market problems, a shadow system of "workarounds" or "safety
4 net" transactions came into being bypassing ERCOT and requiring the direct
5 coordination of TDSPs and REPs. The Quarterly Report requires some limited
6 reporting by TDSPs and REPs on these manual/electronic transactions and on inter-
7 company invoicing. I will be referencing some of this data later in my testimony.
8 Q. WHAT OTHER STANDARDS WILL YOU BE REFERENCING?
9 A. The PUCT has promulgated specific standards within its Consumer Protection rules.
10 A reading of these rules suggests that the qualitative standards I have suggested above
11 describe the essential elements that together can make or break service quality. IO
12 Q. HOW DO THESE FIVE DIMENSIONS OF SERVICE QUALITY RELATE
13 TO THE ALIGNMENT STANDARD FROM ECONOMIC THEORY?
14 A. Deficiencies in any one of these will impose unnecessary costs on the market.
15 Q. HOW DID YOU DECIDE TO PROCEED?
16 A. In order to investigate the quality of service provided to REPs, I decided to survey
17 REPs active in the TCC service area regarding service quality.
10 These are: (1) Quality and Timeliness of Communication, (2) Speed of Response, (3) Pro-active Problem
solving, (4) Dedication of Resources and (5) Accuracy of Response.
DIRECT TESTIMONY 22 GOODFRIEND
1 B. SURVEY DESCRIPTION AND RESULTS
2 1. INTRODUCTION AND ORGANIZATION
3 Q. HAS AEP-TCC SURVEYED REPS REGARDING THEIR EVALUATION OF
4 TCC SERVICE QUALITY?
5 A. No.
6 Q. HAVE OTHER AEP TDSPS IN STATES WITH RETAIL CHOICE
7 SURVEYED REPS REGARDING THEIR EVALUATION OF TDSP SERVICE
8 QUALITY?
9 A. No. There has been no survey. I I Moreover, there is no incentive structure in place at
10 AEP or TCC to reward employees according to REP perceptions of service quality.12
11 Q. HAVE ANY OTHER ERCOT TDSPS SURVEYED SERVICE QUALITY?
12 A. Within the last month, I understand that an anonymous telephone survey by a market
13 research firm is being conducted on behalf of CenterPoint, the TDSP in the Reliant
14 service territory. To my knowledge this is CenterPoint's first formal survey of its
15 REP customers. ERCOT also has announced plans for its first customer survey.13
16 Q. HOW DID YOU PROCEED?
17 A. To investigate TCC service quality, I created and sent a REP Customer Satisfaction
18 Survey to all REPs active in the TCC service territory. I surveyed four areas of
19 importance to REP service quality: (1) Responsiveness to REP inquiries, (2)
20 Educational programming and outreach to REPs, (3) Responsiveness in resolving
11 Response to Cities 2-97.
12 Response to Cities 2-96.
13 Ercot Report to RMS, 1/14/04.
DIRECT TESTIMONY 23 GOODFRIEND
1 market problems generally, and (4) specifically, with respect to FasTrak issues. The
2 survey and cover letter is provided as Exhibit SJG-1.
3 Q. HOW IS THIS SECTION OF YOUR SERVICE QUALITY TESTIMONY
4 ORGANIZED?
5 A. First, I will introduce the survey. Second, I will report the numerical results of
6 responses on relative and absolute rankings of TCC. Third, I will review each of the
7 four topic areas for which I solicited comments. For ease of exposition, I will not be
8 discussing all the survey responses. However, I have included them all in matrix
9 form within the body of my testimony. I will be discussing some representative
10 responses that appear in the matrix.
11 Q. DID YOU EVALUATE THE RESPONSES YOU RECEIVED?
12 A. Yes. Research and discovery pennitted me to directly evaluate some of the REP
13 responses to the Customer Satisfaction Survey. I have supplemented the REP
14 responses with additional examples or illustrations related to assessing unnecessary
15 costs imposed on the market by TCC's service quality failures.
16 Q. WHY WAS THERE A NEED FOR AN ANONYMOUS SURVEY?
17 A. Because of the day-to-day working relationship with TCC, and fear of possible
18 retaliation, REPs suggested the need for anonymous survey response. Even so,
19 several REPs I contacted indicated that they would not be responding due to
20 confidentiality concerns.
21 Q. DO YOU BELIEVE FEAR OF RETALIATION IS RATIONAL?
22 A. Yes. REPs depend upon the cooperation of TDSP personnel. It is rational to fear
23 forms of retaliation such as assigning a new employee to work an critical issue for a
DIRECT TESTIMONY 24 GOODFRIEND
1 particular REP, working orders from one REP before another, responding to emails or
2 phone calls more promptly, etc. that discriminate but are difficult to detect.
3 Q. ARE THERE SOME OTHER REPS YOU DID NOT EXPECT TO
4 PARTICIPATE?
5 A. Yes, based on economic self-interest it seemed less likely that I would receive
6 responses from REPs affiliated with AEP or REPs affiliated with other TDSPs.
7 Q. HOW LARGE THEN WAS YOUR POTENTIAL POOL OF RESPONDENTS?
8 A. These considerations leave 26 or 27 REPs as potential respondents. Roughly 113 of
9 these potential respondents completed and returned the survey. The respondent group
10 of REPs included those who had been in the market from the beginning and those
11 entered later; REPs serving Residential, Commercial and Industrial customers (or
12 some combination thereof), and REPs with different market shares and distributions
13 of overall market share in AEP.
14 2. NUMERICAL RESULTS
15 Q. YOU SAID EARLIER THAT YOU WOULD BE PROVIDING DIRECT
16 QUOTES FROM THE SURVEY IN ITALICS AS REPRESENTATIVE OF
17 YOUR FINDINGS FOR EACH AREA. DO YOU HAVE A
18 REPRESENTATIVE RESPONSE FOR THIS SECTION?
19 A. Yes. It all comes down to communication and responsiveness. Resource constraints
20 may play a role but CenterPoint and Oncor find themselves well in front of AEP and
21 TNMP. The relative ranking of AEP-TCC is consistent with the individual
22 respondent's statement .
DIRECT TESTIMONY 25 GOODFRIEND
1 Q. HOW DID YOU PROCEED IN THIS AREA?
2 A. For each of the four survey areas (responsiveness to inquiries, education and
3 outreach, resolving market problems and FasTrak), I requested that respondents
4 provide a relative ranking of the four ERCOT TDSPs, from 1 (best) to 4 (worst). For
5 the four survey areas combined, respondents provided 30 relative rankings for AEP-
6 TCC.
7 The distribution of these ranks is represented by the following chart.
8
Figure 1: Relative Rank of TCC
Among ERCOT TDSPs
8 .-~---========;-------------------,
•Inquiries 7 7
(I) 7- Resolve Fas Trak ,_____ _ ____
1!111
"'0s:: 6 - ~Educ
& Outreach
c. D Resolve Problems
"'
~ 5
'O 4
~ 3
s::
(I)
::s
C" 2
~ 1
u. 1
0 0 0
O+---==---~
Best 2nd 3rd Worst
9
10 Q. PLEASE DESCRIBE THE CHART.
11 A. The relative rankings are clustered at number 3, with a few outliers. The chart may
12 be read as indicating that for the Inquiries responses, indicated by solid black, 7
13 respondents gave TCC a 3rd, while 1 respondent gave AEP a 2nd and the other gave
14 AEP a 4th or Worst. For Education and Outreach, indicated by the diagonal stripe, 7
DIRECT TESTIMONY 26 GOODFRIEND
1 respondents gave AEP a 3rd and 1 respondent gave TCC a 4th. That one respondent
2 did not rank TCC on the question is indicated by a "0." (The "O"s indicate non-
3 responses ). While AEP does best on FasTrak, notice that there were only 6 responses
4 indicated by the hatch marks of 4 giving AEP a 3rd, 1 giving TCC a 2nd and 1 giving
5 TCC a 1. Some respondents indicated that they had not initiated FasTrak issues with
6 TCC. Others indicated they had little experience with TCC in this area. TCC fairs
7 worst on resolving market problems. While it is tempting to discuss the outliers, it
8 would be a mistake to give them too much attention, since some variation in opinion
9 is to be expected and the sample is small.
10 Q. DID YOU ALSO PROVIDE RESPONDENTS AN OPPORTUNITY TO
11 GRADETCC?
12 A. Yes. For each survey area, I requested that respondents provide a grade with
13 A=excellent, B::=good, C=fair, D=poor, and F=fail. The resulting frequency
14 distribution shows more variation in this small sample than the one above. This
15 results express differences in the graders' standards as well as differences of opinion.
16 Q. DO YOU HA VE A REPRESENTATIVE RESPONSE FOR THIS RANKING?
17 A. Yes. Management needs to make customer service a priority.
18 Q. DO REP RESPONSES SHOW A DIVERSITY IN STANDARDS?
19 A. Yes. Those REPs that want to use service quality as a competitive distinction will be
20 sensitive to TDSP service quality, since their ability to distinguish themselves
21 depends upon the TDSP's service quality. REPs competing on the basis of price are
22 less sensitive to service quality issues (as long as other REPs are getting the same
DIRECT TESTIMONY 27 GOODFRIEND
1 level of service quality that they do). The distribution of REP grades is provided in
2 the following chart:
3
4
Figure 2: TCC Grade Distribution
from REP Survey
•Inquiries &'1 Educ & Outreach 1111 Resolve Problems D Resolve Fas Trak
~ 10
~
(,!)
>-
..c 8
3l"' 6
c:
&.
~ 4
0::
0 2
=t:I:
0 __.___ _ _ __
A Excellent BGood C Fair D Poor F Fail
Grades for Performance
5 Q. WHAT IS TCC'S GRADE POINT AVERAGE?
6 A. Using 4.0 for A, 1.0 for D and 0 for F, TCC's overall grade point is 1.834.
7 Q. WHAT ARE YOUR COMMENTS ON THIS CHART?
8 A. Although the numerical results are interesting, they lack the consistency that appears
9 across the repeated written responses. The frequency distributions that result visually
10 from the ranking exercises provide information about where most responses lie
11 (central tendency) but also report some inconsistencies that exist in the responses.
12 The qualitative responses are much more uniform.
DIRECT TESTIMONY 28 GOODFRIEND
1 Q. HOW IS THE PUCT STANDARD THAT YOU RECOMMEND RELATED TO
2 THESE REP STANDARDS?
3 A. The PUCT standard is more stringent because the PUCT has the responsibility of
4 evaluating service quality in light of all market costs, costs to REPs, to the market, to
5 the competitive process and to end-users.
6 Q. IF YOU WERE GRADING TCC, WHAT GRADE WOULD YOU GIVE TCC?
7 A. Applying the standard I urge the Commission to adopt, and based on the evidence I
8 will present, I would give TCC a grade of unacceptable, a Dor an F.
9 3. QUALITATIVE RESULTS
10 Q. HOW WILL YOU PROCEED IN THIS SECTION?
11 A. This section is divided into four subsections for each of the four survey areas. The
12 survey asked REPs for comment on TCC practice, and on best practices, whether
13 AEP-TCC could achieve best practice and, if so, how. For each survey area, I created
14 tables to catalogue all the narrative responses I received. There are three table rows.
15 The rows are: (1) TCC Practice, (2) Best Practice Standards/Suggestions for
16 Improvement and (3) Issue Subject to Further Analysis and/or Testimony
17 Recommendations for this area. Comments are further classified by the columns of
18 the table. Table columns identify the dimension of service quality to which the
19 comment most pertains. These service quality dimensions, which have been
20 discussed above, are: Quality and Timeliness of Communication, Speed of Response,
21 Pro-Active Problem Solving, Dedication of Resources, and Accuracy of Response.
DIRECT TESTIMONY 29 GOODFRIEND
1 LACK OF RESPONSIVENESS TO REP INQUIRIES
2 Q. WHAT ARE YOUR GENERAL FINDINGS IN THIS AREA?
3 A. REPs found TCC slow to respond to inquiries and poor at maintaining
4 communication. They had many suggestions for improvement. A representative
5 statement of response is the following: At the REP relations level we are rarely able
6 to reach TCC representatives via telephone. Issue resolution usually takes between
7 2-4 weeks when we are able to reach a representative via phone. Issue resolution,
8 when communicated via email, usually takes 4-6 weeks. We attribute many of these
9 problems to lack of resources. We have one contact who handles all issues, from ES!
10 ID questions to tariff questions. This contact is the only contact for many other
11 REPs.
12 In contrast, REPs report that other TDSPs had a habit of maintaining
13 communication regardless of whether there was an outstanding issue or not. Other
14 TDSPs routinely send back data within 2 days without follow up contact. The
15 following table summarizes results.
DIRECT TESTIMONY 30 GOODFRIEND
1
Dimensions of Service Quality
Figure 3
Quality and Speed of Pro- Dedication Accuracy
Responsiveness Timeliness of Response active of of
to REP Inquiries Communication Problem Resources Response
Solving
At the REP relations level we rec is slow in TCC has relatively
TCC Practice are rarely able to reach TCC responding to limited account
representatives via historical usage management
telephone. Issue resolution requests. For resources available
usually takes between 2-4 example, in a to REPs to handle
weeks when we are able to [redacted] letter of inquiries outside the
reach a representative via authorization was scope of day to day
phone. Issue resolution, when sent to TCC with operational issues.
communicated via email, multiple ESI IDs. Responses to
usually takes 4-6 weeks. We TCC was contacted business practices
attribute many of these [redacted] times and policies, tariffs,
problems to lack of and has not etc. are often
resources. We have one responded. Often delayed if one or
contact who handles all have to follow up on more contacts are
issues, from ESI ID questions usage requests and unavailable.
to tariff questions. This resend LOAs
contact is the only contact for multiple times to get From our
many other REPs. usage data back experiences, the
poor
We do not have a responsiveness is
lot of ESl-IDs in the not due to
AEP territory so we performance, but
do not need a lot of due to resource
help. However, constraints on the
when we have Customer Relations
needed responses Rep.
to issues timing has
been slow.
Improvement in the
supplying of
historical data when
requested with an
LOA is needed.
2
DIRECT TESTIMONY 31 GOODFRIEND
1
Dimensions of Service Quality
Figure 3 (cont.):
Quality and Speed of Pro- Dedication Accuracy
Responsiveness Timeliness of Response active of of
to REP Inquiries Communication Problem Resources Response
Solving
Other TDSPs were and are in We generally Need: Annual Need: a designated
Best Practice constant contact with our receive responses meetings to point of contact --
Standards/ REP, not just in cases of from other TDSPs "get to know" name and personal
problem or transaction in 2 days. the company email. Someone to
Suggestions for resolution. and individual develop a working
Improvement Other TDSPs: REP relations relationship with.
Other Customer Relations Routinely send managers. Also, [need]
Reps make it a point to back data within 2 knowledgeable
communicate on a weekly or days without follow OtherTDSPs support Reps who
biweekly basis to ensure up contact. have: have escalation
customer care. Redundancy of support if they need
Other TDSPs: Very transaction it.
Go out and meet the REPs fast response to procedures
they represent and make ii a requests. (i.e.,
policy to answer all emails. workarounds
Need: Quicken through email,
response times to fax and
requests for telephone)
historical
information. (2
REPs)
2
3 NO EDUCATIONAL PROGRAMMING AND OUTREACH TO REPS
4
5 Q. WHAT WERE YOUR FINDINGS?
6 A. The strong consensus of opinion in the numerical rankings on this aspect of TCC
7 service is confirmed in what REPs had to say on this issue. Four respondents were
8 unaware of any educational or outreach program. Another commented that TCC has
9 never hosted any informational workshops for REPs. This respondent continued: No
10 proactive measures have been taken to inform REPs of TCC's business practices
11 regarding customer enrollment, billing, service order processing or issue resolution.
12 When attempting to obtain answers to these types of day to day operational questions
13 answers are at times inconsistent and the appropriate personnel are difficult to
14 contact.
DIRECT TESTIMONY 32 GOODFRIEND
Q. WHAT UNNECESSARY SERVICE COSTS ARE CREATED BY THIS
2 FAILURE TO COMMUNICATE?
3 A. Labor costs associated with manual interventions and reparative software costs. The
4 REP responded: TCC provides very little outreach to help educate REPs. For
5 example, TCC altered the format of usage data responses. We had no advance notice
6 of the change. Our systems are configured to automatically upload usage data. The
7 change in format did not work with our systems. This caused operational problems
8 until we recognized the change and were able to alter our systems. This REP
9 contrasted TCC with Oncor, reporting that Oncor also altered its format for usage
10 data responses but provided ample advance notice and an example of the new format.
11 This advance notice permitted system changes and the avoidance of operational
12 problems.
13 Q. WHAT IS YOUR OBSERVATION ABOUT THESE COMMENTS?
14 A. TCC's poor ranking on education and outreach show a lack of interest not a lack of
15 resources. This is not a situation where TCC must incur significant costs to support
16 market development. This is simply a lack of pro-active customer focus. For
17 example, a comment was: Holding workshops and proactive communication are
18 attainable goals for AEP; There is no clear reason why TCC should not be able to
19 host such workshops for REPs. This should not only improve the operating efficiency
20 of REPs but that of TCC as well.
DIRECT TESTIMONY 33 GOODFRIEND
1 Q. HAVE YOU PROVIDED SPECIFIC RECOMMENDATIONS RESULTING
2 FROM YOUR ANALYSIS OF THIS CUSTOMER SERVICE ISSUE?
3 A. Yes. These recommendations are included in summary at the beginning of my
4 testimony.
5
6
Dimensions of Service Quality
Figure 4:
Educational Quality and Pro-active Dedication of
Programming Timeliness of Problem Solving Resources
and Outreach Communication
To date, TCC has never hosted
Three REPs: To respondent's any informational workshops for
TCC Practice knowledge, no education or REPs. No pro-active measures
outreach provided. have been taken to inform
REPs of TCC's business
We are not aware of any practices regarding customer
educational programs offered by enrollment, billing, service order
TCC. However, we have processing or issue resolution.
received email When attempting to obtain
updates/correspondence answers to these types of day
regarding TCC processes. to day operational questions
answers are at times
inconsistent and the
appropriate personnel are
difficult to contact.
TCC provides very little
outreach to help educate REPs.
For example, TCC altered the
format of usage data
responses. We had no advance
notice of the change. Our
systems are configured to
automatically upload usage
data. The change in format did
not work with our systems. This
caused operational problems
until we recognized the change
and were able to alter our
systems.
DIRECT TESTIMONY 34 GOODFRIEND
Dimensions of Service Quality
Figure 4:
Educational Quality and Pro-active Dedication of
Programming Timeliness of Problem Solving Resources
and Outreach Communication
Three REPs: Oncor and Invited to office and provided
Best Practice CenterPoint have regular Detailed Billing Analysis
Standards/ workshops designed to educate notebook of all accounts. Other TDSPs offer periodic
REP. This is helpful because it Breakout and definition of each training &seminars. Also,
Suggestions for keeps REPs up to date on type and explained how to have one specific rep relation
Improvement changes with the TDSPs and interpret the bill. person assigned
also allows us interaction with
our CSRs in person. We never Other TDSP's meetings Other TDSPs: (Two Reps
had a physical meeting with provide: gaining a better commented) Meetings provide
main contact at TCC. understanding of internal TDSP opportunity to meet
processes, an opportunity to representatives face to face.
CenterPoint holds meetings as address specific issues or
necessary to discuss procedural concerns and an opportunity to
or market changes that REPs meet and greet. We would like
need to know. to see TCC offer these
programs as well.
They(Oncor] also cover any
upcoming tarriff (sic] changes
and cover updates to their web
site.
CenterPoint holds meetings as
necessary to discuss
procedural or market changes
that REPs need to know. (Two
REPs)
1
2 INACCURACIES AND UNRESPONSIVENESS WORSEN MARKET PROBLEMS
3 Q. WHAT IS THE NEXT AREA OF EVALUATION?
4 A. The next area is how well TCC responds in resolving market problems. This subject
5 area elicited the longest and most numerous responses. Before presenting the
6 tabulated responses, I want to present the results of my investigation of a general, but
7 repeated allegation.
DIRECT TESTIMONY 35 GOODFRIEND
1 Q. WHAT WAS THE REPEATED REP ALLEGATION YOU INVESTIGATED?
2 A. A REP respondent stated: rec is also usually the first group to complain about a
3 change in the market and the last to get their software updated. rec often appears
4 to want to do just what is required and nothing more. Another REP made the same
5 point more diplomatically, stating: AEP is generally somewhat inflexible in changing
6 their internal practices to accommodate market concerns.
7 Q. IS THIS ALLEGATION OF PARTICULAR INTEREST IN YOUR
8 FRAMEWORK?
9 A. Yes. These allegations are another way of identifying the alignment problem. In
10 failing to accommodate market concerns, these REP statements imply that TCC is
11 imposing costs on the market that directly diminish the quality of service delivered to
12 ERCOT retail market participants.
13 Q. WERE YOU ABLE TO FIND SOME EVIDENCE SUPPORTING THIS
14 ALLEGATION?
15 A. Yes. But before reviewing it, having a bit more background about electronic
16 transactions in ERCOT is helpful.
17 Q. WILL YOU BE DESCRIBING THE REASON FOR MOVING FROM THE
18 CURRENT VERSION OF TEXAS SET, VERSION 1.6 TO A NEW SERIES
19 RELEASE, TEXAS SET 2.0?
20 A. Yes. At the present time, service orders, such as requests for switching a customer's
21 REP, moving a customer either in or out of an existing premise, providing
22 connection, reconnection or disconnection, requests for changing when a meter is
23 read or for current or historical usage data, etc. all arrive to the TDSPs in
DIRECT TESTIMONY 36 GOODFRIEND
1 chronological time. When orders arrive in chronological time but out-of-sequence for
2 the implied cycle of transactions on a single active premise location (ESI ID), rejects
3 occur. 47% ofrejects are caused by this type of problem.14
4 In these cases, the TDSPs and REPs must manually intervene and workaround
5 the reject. These manual workarounds in tum give rise to other problems. Texas Set
6 2.0 will solve the problem of multiple non-sequential transactions on a single ESI ID
7 via a "parking lot" or stacking solution. Over the last few months, ERCOT
8 information technology and customer service employees have been offering training
9 seminars to acquaint market participants with these changes. The ERCOT Protocols
10 contain gray-tone provisional sections incorporating new Protocol standards once
11 Texas SET 2.0 is in place.
12 The seminars are necessary because Texas SET is literally the standard for
13 how electronic data transactions between market participants must interface, so it is
14 mandatory that each market participants be able to fully execute Texas SET.
15 Everyone who participates in the market must update their systems with changes in
16 Texas SET. Substantial market benefits are anticipated from this major upgrade. IS
17 Finally, in the document below references to MACSS is to a customer
18 information system internal to the AEP system. References to the "parking lot" are
19 references to ERCOT's problem resolution embodied in the release of Texas Set 2.0.
14 ERCOT, Solution to Stacking Educational Seminar, 12/9/03 available from RMS (Keydoc's) section at
www.ercot.com.
IS ERCOT, Solution to Stacking Educational Seminar, 12/9/03 lists expected benefits as: significant reductions
in rejects, significant reduction in the need for Safety Net Move-ins, better manages customer expectations
regarding dates, billing, etc, fewer backdated clean up efforts, fewer cancel/rebills, helps keep systems in synch,
reduces unaccounted for energy, reduces transaction volume, expedites connecting and billing the customers by
the correct REP and improves transactions reliability.
DIRECT TESTIMONY 37 GOODFRIEND
1 Q. WHAT IS THE DOCUMENT YOU ARE PROVIDING BELOW?
2 A. Reproduced below is a Customer Choice Operations Business Case Analysis
3 provided by TCC in discovery. This document rather perfectly illustrates my thesis:
4 absent Commission action in this case, TCC will disregard significant market costs it
5 imposes on others by its actions. Narrow profitability concerns are driving TCC
6 service quality decisions. TCC has actively resisted improvements benefiting the
7 market. The evidence corroborates the REP survey allegations I have quoted above.
8 Q. WHY DO YOU INCLUDE THE ENTIRE BUSINESS CASE ANALYSIS?
9 A. The document itself is important and the complete context of the document is an
10 important reference. The business case analysis does a good job of describing the
11 significant costs being imposed on the market by delaying the implementation of
12 Texas Set 2.0. Then, when discussing alternatives to the necessary investment the
13 analyst says: The parking lot will benefit the overall functioning of the market and will
14 benefit CRs [competitive retailers or REPs]. Due to the minimal benefit to AEP TDSP, we
15 have attempted to delay implementation through negotiation in working groups.
16 The author's use of the past tense is disturbing.
17
DIRECT TESTIMONY 38 GOODFRIEND
Source: Cities 10 Q 12
FIGURE 5: BUSINESS CASE, CUSTOMER CHOICE OPERATIONS
Business Case
Business Unit: Customer Choice Operations
Project Name: CCPRIL TX Service Order Parking Lot (Texas SET 2.0)
Project ID: CHG000000724085
Start Date: End Date:
Executive Summary: AEP is required to conform to the ERCOT Protocols as specified in Texas Standard
Electronic Transactions (SET.) Texas SET will make periodic releases to address market issues and it is
mandatory that AEP make all changes necessary to comply. Consistent with the planned release of TX SET
2.0, AEP will need a new application for Texas to properly sequence multiple future-dated service orders for
a single premise. The BU and IT sponsors are Jim Sorrels and Bill Vogel, respectively.
Current Situation and Problem Statement: Today, transactions are received in the order they are sent from
market participants, not necessarily in chronological order. Service orders entered into MACSS that are not
in chronological sequence cannot be completed. These out-ofsequence orders either must be manually
processed or rejected back to the CRs for resequencing. Either of these options requires significant manual
effort to resolve. Each TDU in Texas has this same problem and the market has decided that the appropriate
solution is for each TDU to modify their systems to deal with out-ofsequence transactions.
Project Description: Functionality will be established to ensure that as the transactions are received by
MACSS, they will be "parked", or held, until just before the event when the specific transaction is needed (to
provide time for other orders to arrive). The transactions will then be properly sequenced to the work
management system and allowing each to complete appropriately, instead of being exceptioned for manual
processing or being rejected back to the CRs.
Solution Overview: Implementation would allow AEP to comply with TX SET and reduce the workload
associated with.fixing problems resulting from out-ofsequence transactions.
Solution Detail: MACSS has estimated a delivery cost of $106,080. There is lost opportunity costs in that
other projects that have revenue benefit will be delayed. An unquantified, but tangible benefit would be the
reduction in manual processing necessary to fix out-of sequence transactions. The risk of not implementing
these changes is that we would be in non-compliance with TX SET, with potential regulatory repercussions.
Alternatives Considered: Tlte parking lot will benefit the overall functioning of the market and will
benefit CRs. Due to the minimal benefit to AEP TDSP, we have attempted to delay implementation
through negotiation in working groups.
Implementation Summary: The anticipated delivery date for this market requirement is May 2004, subject to
formal approval of a schedule by ERCOT.
Relationship to other Initiatives: This project is consistent with other system modifications and
enhancements required in the TX marketplace.
Metrics: Success will be measured by the successful implementation of Texas SET 2.0 and our associated
internal transaction processing. The benefits should be seen in the marketplace immediately.
DIRECT TESTIMONY 39 GOODFRIEND
1 Q. HOW HAVE REPS CHARACTERIZED OTHER WIRES COMPANIES'
2 PARTICIPATION IN WORKING GROUPS?
3 A. In describing best practices among other wires companies, one REP said: Other
4 Wires Companies have got a lot of active members involved in many market
5 committees and subcommittees. These members are taking the time to improve the
6 market place through new software, faster hardware, better logic, improved
7 communication between REPs and more accurate market reporting. They are
8 proactively seeking solutions to lingering problems and trying to clear out all of the
9 old ones.
10 Q. BEFORE YOU LEAVE THIS TOPIC, IS THERE OTHER EVIDENCE
11 PERTINENT TO TCC'S SUPPORT OF MARKET WIDE SERVICE
12 IMPROVEMENTS AND COST REDUCTION EFFORTS?
13 A. Yes. TCC lags significantly behind Oncor and CenterPoint in providing the resource
14 investment needed for Texas SET 2.0. Oncor is 95% through the design stage and
15 90% through the build stage for Texas SET 2.0. CenterPoint is 85% through the
16 design stage and 25% through build. In contrast, AEP is 20% into the design stage
17 with no build and TNMP is 10% in the design stage with no build, according to recent
18 self-reports. l 6
19 Q. IS THERE ANOTHER CHARACTERIZATION OF TCC THAT IS ALSO
20 CAUSE FOR CONCERN?
21 A. Yes. AEP has a history of taking unilateral action against Market Rules e.g., billing
22 customers for T&D charges who showed no REP of Record.
16 The complete ERCOT presentation is provided in Workpapers.
DIRECT TESTIMONY 40 GOODFRIEND
1 Q. WERE YOU ABLE TO INVESTIGATE THIS ALLEGATION?
2 A. Not definitively. It's clear that TCC spoke with Commission staff concerning
3 unbilled customers. In the early stages of the market there were customers for whom
4 either the TDSP and/or ERCOT had no "REP of record." TCC decided to direct bill
5 these customers without a REP of record and it appears that in the test year, this
6 brought in over $1.2 million to TCC.17 Whether TCC sent the letter first and
7 discussed it with Staff after the fact or visa versa, I do not know. I was also unable to
8 determine to what extent the Commission itself had an opportunity to comment on
9 TCC's action.
10 Q. WERE YOU ABLE TO INVESTIGATE THIS ALLEGATION OF
11 UNILATERAL ACTION USING OTHER INFORMATION?
12 A. Yes. I asked about whether TCC had ever discouraged a REP from using the FasTrak
13 process. TCC responded: In fewer than a dozen instances, TCC has asked certain
14 REPs not to utilize FasTrak for particular billing and payment issues.
15 In the discovery response quoted, TCC reasoned that it was burdensome for
16 TCC to use FasTrak and so substituted its own databases and archives to track the
17 disputes. TCC opined that FasTrak in its present form "is not necessarily the best to
18 tool to use in the instances discussed above." 18
19 Q. WHAT DO YOU MAKE OF THIS UNILATERAL ACTION?
20 A. The unilateral decision to bypass market processes can impose market costs. While it
21 may be burdensome at times for market participants to use FasTrak in cases where
17 TCC Workpaper 11-E-5 line 40 "CWRR"
l 8 Response to Cities 15-3
DIRECT TESTIMONY 41 GOODFRIEND
1 multiple premises share a common transactional problem, FasTrak is the means by
2 which ERCOT, as the central registration agent, monitors and identifies transaction
3 problems, trends and prioritizes needs for improvement. Once logged, FasTrak issues
4 are never deleted. They become part of the knowledge base of historical information
5 for each active premise and can be searched by individual ESI-ID when needed to
6 provide background and/or resolve issues.19 Here, again TCC seems to show a basic
7 disregard for the effects of its decisions on the market as a whole.
8 Q. WILL YOU BE PRESENTING OTHER EVIDENCE THAT
9 CORROBORATES REP'S STATEMENTS OF CONCERN ABOUT TCC
10 PERFORMANCE?
11 A. Yes, but first I will review specific survey findings. Although I have tried to
12 categorize responses in this section by quality dimension, in fact, it seems that most
13 examples indicate a combination of factors are responsible for performance problems.
14 The first two examples focus on the role of inaccuracies as the source of later market
15 problems. In the instances described, inaccuracies impose direct costs on REPs and
16 end-use customers and may impose a second round of costs because of slow
17 responsiveness in resolving the initial inaccuracies:
18 The first example addresses errors in TCC's data at ERCOT:
19 TCC still has a lot of issues with inaccurate address/ESJ-ID information at
20 ERCOT. Many consumers in the TCC region are affected by un-authorized switches
21 due to incorrect information in the ERCOT portal and information TCC provides by
22 phone to the CR.
19 See Day to Day FasTrak Issues Users Manual 10/24/2003 -Version 4.0 available from www.ercot.com.
DIRECT TESTIMONY 42 GOODFRIEND
l The second example shows the effects of inaccurate use of a Texas SET
2 transaction sequence. This may also be evidence of a resource or training problem at
3 TCC.
4 There have been instances where a meter exchange had occurred and TCC
5 was sending 814_20 transactions [create/maintain/retire ESI-ID request} indicating
6 a meter removal. Then, TCC would send an 814_20 transaction indicating a meter
7 add. Once this Texas SET error was acknowledged by TCC it still took 4 months for
8 them to correct the problem. This incorrect use of the ESI-ID transaction caused
9 REPs additional workload, including REPs contacting the customer via telephone to
10 question the reason for the meter removal, the submission [of} final invoices to the
11 customer and the creation of new customer accounts.
12 Q. WHAT ABOUT BEST PRACTICE IN THESE AREAS?
13 A. With respect to speed and accuracy, REPs responded that other wires companies:
14 provide timely and accurate connections based on 814-04105 [switch notification and
15 enrollment] transactions and safety-net/priority connections; are in synch with
16 ERCOT relating to address and ESI-ID information; and respond to inquiries within
17 a 2-hour time frame.
DIRECT TESTIMONY 43 GOODFRIEND
Figure 6: Dimensions of Service Quality
Responsiveness Quality and
in Resolving Timeliness of Speed of Pro-active Problem Dedication Accuracy of Response
Market Communication Response Solving of Resources
Problems
It all comes down to An isolated AEP is generally TCC is also TCC still has a lot of
TCC Practice communication and example of poor somewhat inflexible usually the issues with inaccurate
responsiveness. resolution of a in changing their first group to address/ESI-ID
Resource constraints market issue internal practices to complain information at ERCOT.
may play a role but occurred when accommodate market about a Many consumers in the
CenterPoint and TCC issued concerns change in the TCC region are affected
Oncor find market market and by Un-authorized
themselves well in transactions with Responds well but the last to get switches due to incorrect
front of AEP and inaccurate meter other TDSPs more their software information in the
TNMP data. The issue helpful. updated. TCC ERCOT portal and
was identified and often appears information TCC provides
AEP has a history of brought to the We have repeatedly to want to do by phone to the CR.
taking unilateral attention ofTCC requested a report just what is
action against in [redacted]. from TCC regarding required and There have been instances
Market Rules e.g., After multiple outstanding invoices nothing more. where a meter exchange
billing customers for follow up phone and TCC has failed to had occurred and TCC
T&D charges who calls and emails acknowledge or All are good was sending 814_20
showed no REP of the majority of respond to voicemail except for transactions
Record. the impacted ESI or email TNMP. TCC [create/maintain/retire
IDs with inquiries ... Then, after could ESI-ID request] indicating
When issues arise inaccurate meter months of making probably a meter removal. Then,
multiple emails must data were finally requests, TCC sent a improve TCC would send an
be sent before corrected and the spreadsheet with ranking with 814 20 transaction
answers provided. issue was [redacted] invoices more staff. indicating a meter add.
resolved entirely indicating they were Once this Texas SET
in [redacted]. past due. Of those, error was acknowledged
During this [7 (redacted] were by TCC it still took 4
month period] never received months for them to
time, no pro- [before] and were correct the problem.
active measures over 60 days old; This incorrect use of
were taken by [redacted] were the ESI-ID transaction
TCC to identify duplicates; caused REPs additional
and correct the [redacted) were workload, including REPs
relevant ESI IDs rejected (redacted] ... contacting the customer
affected during via telephone to question
this period. the reason for the meter
removal, the submission
Unmetered [of] final invoices to the
service resolution customer and the creation
takes 4-6 weeks. of new customer accounts
based on the new meter
Meter re-reads information.
and cancel re-bills
are not timely.
DIRECT TESTIMONY 44 GOODFRIEND
Many other ..it was [only] TCC also does not
TCC Practice TDSPs send back through our perform a connection on
(cont'd) IDR and non-IDR employees research move-in on the dates they
data much faster that these issues were confirm from the 814-
than TCC. The discovered. TCC did 04105. (For example, if
IDR data is not offer any the CR receives an 814-
especially slow in resources or 04105 from TCC with a
arriving to us. A assistance in connect date of 12.09.03,
quicker evaluating the the service may not be
turnaround would contents of the connected until 12.14.03
be most helpful. spreadsheet. or 12.15.03. Even though
TCC has a safety
Luckily I have not No ESI-IDs account net/priority connect
had a lot of notation is made process, they never follow
problems with when a CR calls in, through when a request is
TCC in quite a so there is no history made.
while. However, kept on any ES I/ID.
when there is a
problem the
response is fairly
slow.
Best Practice Other Wires Other wires (TCC] management Best practice
Standards/ Companies : have companies: needs to make is to follow
Suggestions for got a lot of active provide timely customer service a through on
Improvement members involved in and accurate priority. issues. Most
many market connections based issues
committees and on 814-04/05 CenterPoint and resolved
subcommittees. transactions and Oncor both take what easily but
These members are safety-net/priority they are given from those that are
taking the time to connections; are the CR's and actively more difficult
improve the market in synch with participate at WMS, following
place through new ERCOT relating RMS, and Texas SET through are
software, faster to address and to reach out and important to
hardware, better ESI-ID assist the evolution of customer
logic, improved information. the best in service.
communication Respond to deregulated markets
between REPs and inquiries within a in the U.S. today. CNP and
more accurate 2 hour time Oncor have
market reporting. frame. Yes, [best practice is the better
They are proactively achievable by TCC]. capability for
seeking solutions to TCC has the ability working
lingering problems to improve capability around
and trying to clear for working around market
out all of the old market problems problems
ones. through structured through
procedures and structured
AEP TCC can be contacts for procedures
assured that if they resolution. and contacts
are actively involved for resolution.
and listen to their
customers, ERCOT
can only evolve into
a better market than
we have now.
DIRECT TESTIMONY 45 GOODFRIEND
1 BILLING AND INVOICING: FOUNDATIONS FOR ERROR
2
3 Q. DID YOU INVESTIGATE ISSUES RELATING TO THE ACCURACY OF
4 BILLING AND INVOICING?
5 A. Yes. In this section I discuss TCC's use of estimates for meter reads and related
6 problems of billing and invoicing. Prompt and accurate billing and invoicing are
7 foundational issues because poor processes here can snowball into additional
8 problems. Any deficiencies in dedicated resources appear more severe when
9 underlying processes or systems are prone to error. Another REP provided a good
10 example of the relationship between data inaccuracy and slow response:
11 An isolated example of poor resolution of a market issue occurred when TCC
12 issued market transactions with inaccurate meter data. The issue was identified and
13 brought to the attention of TCC in [redacted]. After multiple follow up phone calls
14 and emails the majority of the impacted ES! IDs with inaccurate meter data were
15 finally corrected and the issue was resolved entirely in [redacted]. During this [7-
16 month period] time, no pro-active measures were taken by TCC to identify and
17 correct the relevant ES! IDs affected during this period.
18 Another REP noted: Meter re-reads and cancel re-bills are not timely.
19 Prompt and accurate billing and invoicing are foundational issues. Wires
20 charges include kW and kWh charges and invoices must be cancelled and re-billed
21 when underlying usage data is incorrect. In the ERCOT protocols, a meter read error
22 gives rise to four separate electronic transactions, a cancel and rebill of the associated
23 usage data and a cancel and re bill of the associated invoice.
DIRECT TESTIMONY 46 GOODFRIEND
1 Moreover, timeliness and accuracy are both important service dimensions, but
2 they are not independent. Estimated meter reads can become a source of inaccuracy.
3 Inaccuracy can become a drag on responsiveness as the number of errors that have to
4 be corrected increase. In tum, the volume of cancel/rebills increases and rebillings
5 take longer to send out because the necessary corrective actions for usage information
6 strain existing resources.
7 Q. DOES THE COMMISSION SET STANDARDS FOR BILLING ACCURACY?
8 A. No, however, Subst. R.§ 25.25 provides limits to the use of estimated bills. When
9 questioned as to policy concerning the use of estimates versus actual meter reads,
10 TCC said that its policy concerning the use of estimated versus actual meter reads is
11 to comply with the rule.20 The rule says: An electric utility may submit estimated
12 bills for good cause provided that an actual meter reading is taken no less than every
13 third month.
14 Further, under existing consumer protection rules, REPs must notify
15 customers if the REP is unable to issue a bill based on an actual meter reading due to
16 TDSP or other failure to timely provide actual usage and inform the customer of the
17 reason for the issuance of an estimated bill.21
18 Q. HOW ACCURATE ARE TCC'S ESTIMATED METER READS?
19 A. The PUCT has no standards specifying particular methodologies for usage estimation.
20 TCC has provided documents describing the AEP estimation programs in use by TCC
21 since 1/112002. The estimation methods rely on simple extrapolations of historical
20 TCC Response to Cities 15-1.
21 See Subst. R. §25.479(e).
DIRECT TESTIMONY 47 GOODFRIEND
1 meter reads or historical estimates. The estimates are not adjusted to recognize
2 differences in weather as a factor affecting usage. 22
3 Q. WHAT IS AEP'S VIEW?
4 A. AEP must agree with me that its estimation method needs improvement. In response
5 to a discovery request provided 2/4/04, AEP provided a business case started
6 12/04/03 titled Load Research Analysis Preliminary Plan for MACSS Bill estimation
7 improvement. The plan includes a more statistically sophisticated approach and a
8 weather-related adjustment for some customers. Expected completion date is May
9 2004.23
10 Q. ARE THERE OTHER POTENTIAL ACCURACY ISSUES ASSOCIATED
11 WITH TCC'S USE OF ESTIMATED METER READS?
12 A. Yes. TCC's current approach allows TCC to "dial up or dial down" its acceptable
13 level of accuracy.
14 TCC explains that in its approach to estimation, the acceptability of estimates
15 depends on the TCC's choice of an accuracy tolerance limit. If the tolerance limit is
16 loosened, more estimates are accepted as "good." When TCC is unable to create
17 estimates that are good enough, then the account is a "no bill" for the current reading
18 date with obvious cash flow implications for TCC.24 It is not surprising that one of
19 the measures TCC tracks for customer operations functions is the level of no bill
20 accounts more than 10 days old, and that there are very, very few of these.25
22 Response to Cities 15-2, Attachment 1.
23 Response to Cities 35-2, Attachment 1.
24 Response to Cities 16-6.
25 Response to Cities 30-14 attachment page 4 of 6.
DIRECT TESTIMONY 48 GOODFRIEND
1 Q. WHAT HAPPENS IF TCC'S AUTOMATED SYSTEM TRIES TO ESTIMATE
2 A THIRD MONTH IN A ROW?
3 A. PUCT rule §25.25 requires an actual meter read every third month. TCC says: If the
4 automated system tries to estimate for a third month, then efforts are made to obtain
5 an actual reading. This may result in manual estimation. Because the automated
6 system will not estimate accounts with demand greater than 10 kW, all estimates for
7 these larger accounts are manual. Except for a small pilot program using remote
8 meter reading, all other meter readings require a premise visit.26
9 Q. WHAT HAS HAPPENED TO THE VOLUME OF TCC ESTIMATED METER
10 READS SINCE CUSTOMER CHOICE?
11 A. It has exploded in all rate classes.
12 Q. WHAT INCENTIVE ALIGNMENT PROBLEM DOES THIS SUGGEST?
13 A. Obviously, for every estimated meter read, a premise visit may be avoided. Provided
14 data indicates the cost-savings to TCC. Using TCC's fully embedded cost estimate to
15 a REP requesting a re-read or out-of-cycle read, the savings per avoided read would
16 be about $17.00. Eliminating supervisory overheads, and using just direct meter read
17 avoided costs saves $5.60 on the meter reader and $1.98 on the truck.
18 Q. WHAT DATA DO YOU HAVE TO SUPPORT YOUR STATEMENT THAT
19 THE VOLUME OF METER READS HAS EXPLODED IN ALL RATE
20 CLASSES?
21 A. TCC provided data on the percentage of estimated meter reads by customer class
22 since January 2000, well before Customer Choice began. The data series continues
26 Response to Cities 16-6.
DIRECT TESTIMONY 49 GOODFRIEND
1 through November 2003.27 The graphic below visually demonstrates the change in
2 TCC's reliance on estimated meter reads, beginning roughly with the Pilot Program
3 for Choice.
4 As the graphic makes clear, there has been a dramatic increase in estimated
5 meter reads, beginning roughly at the time of the Pilot Project. As could be expected
6 from this visual view of the data, the observed differences in means before and after
Figure 7: Meter Reading Accuracy
Percent Estimated Meter Reads
Integrated Utility vs Retail Choice
• • Residential
....
-commercial
lndnstria!
'
- - · Public Authority ' " --·--
Start of Retail Choice --+
.---
l
--•----- - --
'
' •'
..
- -ti-ii--j--
----
----~--
\
- - -\_------ -- -
''
-,---
~ !-
Start of Pilot Project _______.: : ·~
-~; _L
:, I
} 1~ i: ~
- __ :_v_
~ ' • :•,lil.._"l
~
'
j_ ~_%_
7 the onset of choice are statistically significant for each customer class.28
8
27 Response to Cities 15-1, Attachment 1.
28 So as not to influence the results, I have removed the month in which Hurricane Claudette led to use of
estimated meter readings from the data provided.
DIRECT TESTIMONY 50 GOODFRIEND
1 Q. HOW MANY ESTIMATED METER READS DO THE PERCENTAGES
2 DEPICTED REPRESENT?
3 A. In discovery, TCC reported a total of 594,632 automated estimated meter reads since
4 1/1/02 and 55,332 manual estimates since 111/02. Thus, since 1/1/02, TCC has relied
5 upon approximately 650,000 estimated meter reads in total.29
6 Q. HOW MANY ESTIMATED METER READS WERE THERE BEFORE
7 CUSTOMER CHOICE?
8 A. By my estimates, there would have been only about 100,000 or so estimated meter
9 reads (through November, 2003) ifTCC had continued its pre-Choice practices.30
10 Q. HOW MUCH HAS THE NUMBER OF ESTIMATED METER READS
11 INCREASED?
12 A. The number of estimated meter reads have increased by 550,000 over the 23 month
13 period since Choice began. This indicates that at current customer levels, some
14 100,000 estimated meter reads rather than the 650,000-meter reads would have
15 occurred by now had historical norms continued.
16 Q. HOW MUCH MONEY IS TCC SAYING THROUGH ITS CHANGED
17 PRACTICE?
18 A. Using $5 for net avoided cost for TCC, on an annual basis the increase saves TCC
19 about $1.4 million annually. The net avoided cost approach recognizes that there will
20 be cost impacts to TCC, for example in higher levels of cancel/rebill transactions.
29 Response to Cities 16-6.
30 The actual calculations are provided in Workpapers. Depending on assumptions the range of baseline or pre-
Choice estimated meter reads runs from 83,000 to 180,000 and, correspondingly the range of increase runs from
567,000 to 470,000 expressed cumulatively.
DIRECT TESTIMONY 51 GOODFRIEND
For illustration, I am assuming a net savings of $5 from TCC's decision to increase
2 the use of estimated meter reads.
3 Q. WHAT ARE THE EFFECTS OF 550,000 ADDITIONAL ESTIMATED READS
4 ON END-USE CUSTOMERS, REPS AND THE MARKET?
5 A. The Company provided an analysis of AEP-wide data on this topic. The AEP
6 analysis suggests that approximately 50% of AEP's required billing adjustments each
7 year relate to bill estimation. For AEP, 27% of customer calls are related to high bill
8 concerns, including estimations. Over the period January through July 2003, 4.7% of
9 all AEP billing complaints were for inaccurate estimations.31
10 Q. CONSIDER END-USERS. WHAT COSTS ARE IMPOSED ON END-USERS?
11 A. First, depending on the contact option chosen, the end-use customer will need to call
12 the REP or possibly, TCC directly to inquire about the bill. The customer may feel
13 the need to escalate the inquiry into a complaint, engaging in the necessary phone
14 calls and other transactions.
15 Second, a surprised customer is not a happy customer. REPs have indicated
16 that they must respond to customers' bill shock associated with estimated reads,
17 particularly where a seasonal rate is employed. In this context, the REP must decide
18 whether a request for re-reads is in order, and, depending on the arrangements, either
19 the REP or the customer becomes subject to the Special Meter Reading Fee.
31 TCC Response to Cities 15-2, Attachment 1.
DIRECT TESTIMONY 52 GOODFRIEND
1 Third, use of estimates followed by an ultimate true-up when the meter is read
2 makes it more difficult for customers to judge savings they receive from their chosen
3 REP. As a limiting case, the customer may feel the need to search for and switch to
4 another REP.
5 Q. WHAT COSTS ARE IMPOSED ON ERCOT MARKET PARTICIPANTS?
6 A. The relationship between estimated meter reads and the need for cancel and rebill
7 transactions suggests that TCC will have a higher level of cancel and rebill
8 transactions than otherwise. Since four transactions accompany every cancel with
9 rebilling, these unnecessary transactions strain ERCOT resources and, where any
10 manual input is involved, potentially gives rise to errors and rejected transactions.
11 Q. WHAT COSTS ARE IMPOSED DIRECTLY ON REPS AND THEREBY
12 INDIRECTLY ON END-USERS?
13 A. The REP now bears the customer relations costs associated with the inquiring,
14 unhappy or complaining customer. There is also an expected cost to checking the
15 accuracy of the estimated meter read. TCC proposes to charge $17.00 as a Special
16 Meter Reading Fee. The tariff says the REP will not be charged for a re-read if the
17 new reading indicates the original reading was in error. So, the REP faces an
18 uncertain cost of $0 or $17. During the test year, TCC earned $385, 735 on 25,716
19 occurrences where the REP took the gamble and lost.32 Said differently, the REP
20 may have mixed incentives for following up with a re-read request on an estimated
21 bill (regardless of whether the REP or the end-use customer will pay).
32 Response to Cities 23-4, Attachment.
DIRECT TESTIMONY 53 GOODFRIEND
As discussed previously, costs placed on REPs must ultimately be passed to
2 end-use customers. Even so, the costs imposed on REPs still have an effect. They
3 will affect the REP's perceptions of the ultimate costs of serving the customer, and
4 thereby affect REP's pricing and service offers and possibly decisions about when or
5 whether to enter or remain in TCC's market area.
6 Q. CAN YOU QUANTIFY ANY OF THE COSTS YOU'VE CONSIDERED
7 HERE?
8 A. I can illustrate some of the potential costs. Remember that TCC will incur some costs
9 too. The alignment problem is that TCC considers only its net savings, in this case
10 estimated to be $5/estimated meter read, when deciding policy on the extent to use
11 estimated meter reads. My point is simply that when the potential costs to all
12 other parties are considered, if these costs exceed TCC's net $5 saving per
13 estimated meter read, TCC has made the wrong customer service decision based
14 on the alignment standard. An illustration of costs imposed on others by the
15 change in meter reading policy toward estimated meter reads appears below: The
16 "x"s reflect the distribution of costs and the "Illustrative Unit Costs" column provides
17 hard estimates from discovery information. So, for example, the "x" across from the
18 Call Center Calls row in the end-user cost column and the REP cost column identifies
19 the fact that both of these parties may incur these kinds of costs.
DIRECT TESTIMONY 54 GOODFRIEND
1
Figure 8
550, 000 Additional Estimated Meter Reads--Potential Market Costs
Impacted Parties
End-User REP Market and PUCT
Additional Transactions Required Illustrative Unit Costs Costs Costs Costs
Inspect and Determine Action ? x x
Cancel and Rebill - electronic 1 minx 40/hr = 0.66 x x
Cancel and Rebill - manual 15 minx 40/hr =$10 x
Call Center Calls 3.5 minx 1.00 x x
Calls Forwarded 8 minx 1.00 x
Field Rep Trips $17 /no error xi Ix
High Bill Complaint Customer Service 1hrx34/hr x x
Opportunity Costs of Time ? x
Higher Market Prices ? x x
Bill "surprise" and
Degradation of REP reputation ? x x x
Delayed Bill x x
"?"signifies difficult to quantify costs
Estimates from Response to Cities 15-2 Attachment l
And Schedule IV J-2 p. 18
2
3
4 Q. EARLIER YOU STATED THAT HIGH LEVELS OF ESTIMATED METER
5 READS COULD BE EXPECTED TO LEAD TO MORE CANCEL AND
6 REBILL TRANSACTIONS FOR METERS AND INVOICES.
7 A. Yes. The available data for TCC demonstrates this. In the data below, I have had to
8 combine two incomplete series -- one provided in discovery and the other based on
9 confidential and privileged information.
10 Q. IS THE DATA ON CANCELLATIONS CONSISTENT WITH ESTIMATED
11 METER READS AS ONE REASON FOR THE LEVEL OF
12 CANCELLATIONS AND REBILLINGS?
13 A. Yes.
14 [FIGURE 9 REDACTED]
DIRECT TESTIMONY 55 GOODFRIEND
1 Q. HOW MANY CANCEL/REBILL TRANSACTIONS DO THE
2 PERCENTAGES IN FIGURE 9 REPRESENT?
3 A. TCC sends out about 1 million bills annually. So a [redacted] rate of cancel/rebills is
4 [redacted] cancel/rebill transactions annually.
5 SLOW OR NO GO ON FASTRAK RESOLUTIONS
6 Q. WHAT ARE FASTRAK ISSUES AND WHY ARE THESE IMPORTANT IN
7 DEFINING SERVICE QUALITY?
8 A. FasTrak is an issues-resolution system sponsored by ERCOT. FasTrak is the primary
9 tool and entry system used by REPs and TDSPs to communicate with ERCOT
10 regarding problems with electronic customer enrollment. Problems reported through
11 FasTrak could include, for example, missing usage data or other information not in
12 the ERCOT system that is associated with a customer/premise location, rejected
13 transactions, requests for cancellation of transactions, inadvertent switches, or
14 whether or not ERCOT received a specific transaction, etc.
15 For issues submitted to ERCOT, ERCOT will follow up with the TDSP for
16 thirty days to obtain requested transaction(s). After thirty days, the issue will be
17 reassigned as a Non-ERCOT issue, and the submitting REP and TDSP will be left to
18 continue efforts to resolve. Alternatively, some issues are initially submitted as Non-
19 ERCOT when the issue is "point-to-point" between a REP and a TDSP). No FasTrak
20 issue is deleted. Resolved or rejected issues are archived and available for search
21 purposes.33
33 ERCOT FasTrak Day-to-Day User Manual -- Version 4.0 available from www.ercot.com.
DIRECT TESTIMONY 56 GOODFRIEND
1 REPs depend on TDSPs to take responsibility for Non-ERCOT issues and to
2 assign sufficient resources to help resolve all FasTrak issues promptly. Resolution
3 also requires good communication because ERCOT will not generate missing
4 transactions when manual corrections are needed.
5 Q. WHAT GENERAL EXPLANATIONS DID REPS PROVIDE FOR THEIR
6 RANKINGS OF TCC IN THIS AREA?
7 A. Being quick to resolve FasTrak issues is the key service quality dimension for
8 FasTrak. Two REPs made this point, stating that TCC was slow to respond to
9 FasTrak issues. A customer with "very few customers in AEP territory" said: TCC is
IO generally responsive to FasTrak issues, however they rarely answer their 800-line for
11 REP support and are very slow to respond to emails and voicemails.
12 Another REP linked the slow response to lack of dedicated resources: The
13 personnel that are working FasTrak are very helpful and knowledgeable but seem
14 overwhelmed with the volume of FasTrak issues requiring their attention. [TCC
15 needs] more trained personnel.
16 Q. DID YOU RECEIVE ANY SPECIFIC EXAMPLES?
17 A. Yes. A respondent commented: TCC is generally quicker than other TDSPs to
18 acknowledge new logged FasTrak issues. However, once acknowledged, there is an
19 average resolution time of 3 weeks, with outliers up to 8 weeks. We have noted that
20 TCC is quicker to respond to logged FasTrak issues relating to enrollment and less
21 responsive to ongoing maintenance issues related to monthly meter reads and ES! ID
22 maintenance issues. Not all survey participants have logged FasTrak issues with
DIRECT TESTIMONY 57 GOODFRIEND
1 TCC so some answered the survey questions with N/A. The remaining responses are
2 provided below.
Figure 10 Dimensions of Service Quality
Responsiveness Quality and
in Resolving Timeliness of Speed of Pro· Dedication Accuracy
FasTrak Issues Communication Response active of of
Problem Resources Response
Solving
We have very few Timeliness is the The personnel that
TCC Practice customers in AEP biggest issue with are working FasTrak
territory ... AEP is generally FasTrak are very helpful and
responsive to FasTrak resolution. TCC is knowledgeable, but
issues, however, they rarely slow to respond seem overwhelmed
answer their 800-line for to Fas Trak issues with the volume of
REP support and are very (2 responses) Fas Trak issues
slow to respond to emails requiring their
and voicemails. TCC is generally attention. Need more
quicker than trained personnel.
Not many issues for us other TDSPs to
since we have so few acknowledge new
customers in territory. logged FasTrak
Issues generally resolved in issues. However,
a timely, accurate matter. once
acknowledged,
there is an
average
resolution time of
3 weeks, with
outliers up to 8
weeks. We have
noted that TCC is
quicker to
respond to
logged FasTrak
issues relating to
enrollment and
less responsive
to ongoing
maintenance
issues related to
monthly meter
reads and ESI ID
maintenance
issues.
DIRECT TESTIMONY 58 GOODFRIEND
Other TDSPs keep you well Timeliness is key Same day Other TDSPs provide (See response in
Best Practice informed on the status of to resolving response, direct contacts and Column 3)
Standards/ FasTrak issues and respond issues on knowledgeable personnel
very quickly. FasTrak. Other and well- representatives.
Suggestions for TDSPs are trained Reps,
Improvement It is much easier to call a extremely update Recommended
CSR contact at the other proficient in FasTrak ticket Action:
TDSPs and not get voice processing without having Assignment of a
mail. Also, callbacks are requests in a to be asked, customer
much faster when you do timely manner. notify representative for our
leave a message. monitoring company.
Others often have party by email
same day when action Best Practice is
resolution. They has been Achievable by TCC
are much quicker, taken/ticket [with] training and
requiring a few updated, operation al efficiency
days or at most a resolving
week. action is Yes, if their staffing is
accurate. adequate.
1
2 Q. DO YOU HAVE EVIDENCE CORROBORATING THAT TCC IS SLOW ON
3 FASTRAK?
4 A. Yes. As indicated above, ERCOT personnel are also involved in FasTrak issues.
5 Among the many reports that ERCOT personnel present at the monthly ERCOT
6 Retail Market Subcommittee (RMS) meetings is a report on FasTrak activities. The
7 most recent available evidence suggests that TCC is slow on resolving its FasTrak
8 issues with ERCOT.
9 Q. PLEASE EXPLAIN.
10 A. Here too, it is necessary to briefly discuss what is involved in making certain market
11 transactions succeed. ERCOT periodically receives from TDSPs final monthly meter
12 reads and notifications of an initial meter read on service orders that have been
13 cancelled in ERCOT service order recording systems. ERCOT recognizes various
14 types of service order cancels. ERCOT cancels service orders when it receives cancel
15 requests from the REP (perhaps due to manual or concurrent re-processing of the
16 original service order), cancel requests due to customer request, customer objection
DIRECT TESTIMONY 59 GOODFRIEND
1 (e.g., during the switch rescission period, the customer exercises the right not to
2 switch providers), cancels due to a necessary permit not being received (e.g., on a
3 move-in transaction where construction may be needed) or for other reasons. That
4 the TDSP has sent ERCOT a meter read for this service order can indicate an "out-of-
5 sync" condition in which TDSP records and ERCOT records may fail to agree on
6 which REP is providing service.
7 To manage these situations, ERCOT initiated a process on November 7, 2003.
8 In this process, ERCOT initiates a weekly FasTrak issue with the appropriate TDSP
9 as the resolving party for these transactions. ERCOT requests the TDSP to provide a
10 response either updating the FasTrak issue if the service orders are canceled in the
11 TDSP system or, if complete in the TDSP system, identify the out-of-synch condition
12 with ERCOT and initiate an effort to clear the out-of-sync conditions.
13 With respect to these November 7, 2003 cancelled service orders, the last
14 column of the second table below indicates that among the four major TDSPs TCC is
15 the only TDSP with ERCOT still waiting for responses as of the January 14, 2004
16 Report. The following figure is Figure 11.
DIRECT TESTIMONY 60 GOODFRIEND
TDSP Tot.:il '12/31103 12/19/03 '12/12103 1215;03 'l'l/28/03 '11/21/03 '11/14103 11/7,03
AEP '127 12 23 23 9 12 10 34 4
Cente1Pnint 237 16 31 20 18 34 34 67 17
ONCOR 287 '14 '166 1'I 14 26 32 '16 8
Sh.11 vi.ind 17 2 2 2 3 3 0 2 3
TNMP 275 '12 94 92 21 '17 '17 '16 6
G1 .1nd Total 943 56 3'16 148 65 92 93 '135 38
Cancelled comp1etea
byTDSP byTDSP Awaiting TDSP
TDSP Total (In-Sync) (Out-of-Sync) Response
AEP 127 9 51 67
CenterPoint 237 164 73 0
ONCOR 287 187 100 0
Sharyland 17 0 8 9
TNMP 275 275 0 0
Grand Total 943 635 232 76
1
2 The full ERCOT presentation is provided in Workpapers.
3 Q. DID REPS HAVE ANY RECOMMENDATIONS FOR TCC THAT YOU
4 HAVE NOT INCLUDED IN SECTION I OF YOUR TESTIMONY?
5 A. Yes. These were generally specific requests for better performance on the service
6 quality dimensions. REP suggestions to TCC not already captured in my specific
7 recommendations are that TCC should:
8 • provide faster customer service;
9 • respond at first request rather than requiring multiple contacts;
10 • be more pro-active informing REPs about changes to procedures;
11 • provide additional/more knowledgeable and qualified personnel to respond to
12 inquiries or issues;
DIRECT TESTIMONY 61 GOODFRIEND
1 • provide additional educational programs regarding TCC's internal processes and
2 procedures;
3 • provide historical usage in a user friendly format; and
4 • provide quicker turnaround on IDR and non-IDR data.
5 C. REBUTTAL TO TCC WITNESSES GORDON AND HOOPER
6 1. ISA SERVICE QUALITY
7 SUMMARY FINDING
8 Q. HA VE YOU REVIEWED ALL THE REPORTS FILED WITH THE PUCT
9 PURSUANT TO TCC DUTIES TO REPORT THE CUSTOMER SERVICE
10 STANDARDS THAT TCC NEGOTIATED IN THE ISA?
11 A. Yes, and I have done additional discovery on these matters.
12 Q. WHAT IS YOUR OVERALL IMPRESSION OF TCC'S PERFORMANCE ON
13 ISA REQUIREMENTS?
14 A. TCC owes fines in the form of customer credits based on inability to satisfy targets
15 that its predecessor companies had a hand in negotiating.34 As is clear from review
16 of its required reports, TCC has not been able to demonstrate sustained or full
17 compliance with negotiated targets. TCC's offers to fix reporting problems that
18 "explain" the non-compliance are still promises rather than realities.
34 See Direct Testimony of Dr. A. D. Patton.
DIRECT TESTIMONY 62 GOODFRIEND
1 WITNESS GORDON
2 Q. PLEASE SUMMARIZE THE INTEGRATED STIPULATION AND
3 AGREEMENT (ISA) WITH RESPECT TO CUSTOMER SERVICE (NOT
4 RELIABILITY) ISSUES.
5 A. The Integrated Stipulation and Agreement was entered into by TCC's predecessor
6 companies in May 1999. Included within the ISA in Section 7 are Customer Service
7 Standards as well as the Reliability Standards discussed in the testimony of Cities
8 Witness Dr. A.D. Patton. TCC Witness Gordon provides ISA Section 7 in his Exhibit
9 HRG-4.
10 Q. WHAT KIND OF CUSTOMER SERVICES ARE MEASURED IN THE ISA?
11 A. The agreement provides for measurement in four areas: (1) a time-to-connect
12 standard for new service installation where no construction is required, and (2) where
13 installation construction is required, a time-to-connect standard for (a) standard
14 facility construction and (b) a time-to-connect standard for non-standard facility
15 construction. There is also a time-to-restore/replace standard for (3) security and
16 streetlight outages, and time-to-average-answer standard for (4) telephone response of
17 call center employees.
18 Q. DID YOU REVIEW THE TESTIMONY ON ISA STANDARDS OF TCC
19 WITNESS GORDON?
20 A. Yes. Mr. Gordon describes performance in the areas of new service requiring
21 standard construction and non-standard construction and with respect to lighting
22 replacement for outages, what I have called items 2(a and b) and Item 3 above.
DIRECT TESTIMONY 63 GOODFRIEND
1 As Mr. Gordon shows, TCC has failed to meet target for new service
2 involving standard construction in the third and fourth quarters of 2002 and in every
3 quarter reported thus far for 2003. He blames the problem on a newly initiated
4 automated customer information system. And, he is convinced that the problem lies
5 in the reporting system rather than performance.
6 Q. HAS TCC FIXED ITS REPORTING SYSTEM FOR TRACKING STANDARD
7 CONSTRUCTION TIME-TO-CONNECT?
8 A. Mr. Gordon reports that problems still exist with the reporting system. Although a
9 discovery response now asserts the reporting system has been fixed, the assertion is
10 based on the "planned implementation" of new software and order management
11 systems.35
12 Q. DOES MR. GORDON REPORT PERFORMANCE FOR NON-STANDARD
13 CONSTRUCTION REQUESTS?
14 A. Yes. He minimizes the failure to meet targets by explaining that there are very few
15 requests of this nature.
16 Q. WHAT ABOUT LIGHTING REPLACEMENTS?
17 A. Here again, TCC does not meet targets but feels that reporting problems are to blame.
18 In response to a follow-up question, TCC explains that the order tracking
19 system identified by Mr. Gordon36 is still unable to differentiated between standard
20 and non-standard lighting replacement. A procedural change relying on functionality
35 Response to Cities 29-13. Moreover, the discovery response suggests that, to the extent that TCC may
subjectively evaluate "customer readiness," TCC may reset this variable thereby restarting the clock. Full
discovery responses to Cities 29-13 are provided in Workpapers as is Response to Cities 16-21 which identifies
the readiness requirements.
36 Direct Testimony of Mr. Gordon at 34.
DIRECT TESTIMONY 64 GOODFRIEND
1 to be implemented should be able to report actual performance by the last quarter of
2 2004.
3 Q. HOW DO YOU CHARACTERIZE PERFORMANCE ON THE TWO AREAS
4 DISCUSSED BY MR. GORDON?
5 A. Like the filed reports, for each failure, the reporting incident brings with it either an
6 excuse, a promise, or evidence of a promise unkept. These excuses and explanations
7 also characterize Mr. Gordon's testimony.
8 REPORTED PERFORMANCE FOR THE ISA
9 Q. WHAT ARE THE REPORTING REQUIREMENTS OF THE ISA?
10 A. The ISA imposed three annual reporting requirements: a Customer Service Survey of
11 Texas Customers and a Customer Service Report to be filed with the PUCT, and a
12 Utility Scorecard to be sent to its customers. A fourth report to the PUCT is triggered
13 by failure to meet minimum service standards for any two months within a 12-month
14 period.
15 Q. HAS TCC BEEN ABLE TO CONSISTENTLY MEET THE TARGETS IT
16 NEGOTIATED FOR ITSELF IN THE ISA?
17 A. No.
18 Q. PLEASE EXPLAIN.
19 A. First, TCC never filed all the reports contemplated by the ISA. In December 2001,
20 before any annual reports had been filed, TCC filed a petition requesting modification
21 of the standards in the ISA. By agreement with Staff, TCC was permitted to forego
22 providing the ISA-required Annual Utility Scorecard to customers. So, in February
23 2002, TCC filed 2001 data for the other two annual reports.
DIRECT TESTIMONY 65 GOODFRIEND
1 (1) 2001 data
2 Q. WAS TCC IN COMPLIANCE WITH ALL ITS ISA TARGETS?
3 A. No, TCC was not in compliance for light replacement. TCC explained that the data
4 was contaminated by inclusion of more complex repairs that those called for in the
5 performance measure. TCC opined that a system modification in January 2002
6 would allow TCC to demonstrate better, and presumably, compliant performance.
7 Q. WERE THERE OTHER INCIDENTS OF NON-COMPLIANCE?
8 A. Yes. In April, 2001 TCC notified the PUCT that it had experienced three months in a
9 row where average speed of answer was too slow, relative to the target. TCC
10 identified the combination of extreme weather, rising gas prices and changes in the
11 volume, duration and nature of calls as causes.
12 (2) 2002 data
13 Q. WHAT ABOUT 2002 DATA?
14 A. TCC was out of compliance for both lighting replacement and for connection
15 requiring standard installations. In February 2003, TCC filed its 2002 data under
16 agreement with Staff that TCC provide only the same information as TCC provided
17 in 2001. Although TCC had modified its work order system in January 2002, TCC
18 was again unable to demonstrate compliance or improved lighting replacement
19 performance as predicted/ hoped for last year in TCC's explanatory comments. The
20 measure for connection requiring standard installation was also out of compliance.
21 TCC explained that the conversion from the CSW to the AEP Customer
22 Information System (known as Marketing And Customer Services System), combined
23 with workarounds necessitated by electronic exchange problems under Customer
DIRECT TESTIMONY 66 GOODFRIEND
1 Choice had resulted in the need to reconstruct lost data such as construction
2 completion dates. Thus, the reported 2002 data for connection times for standard and
3 nonstandard installation was based on recollections of people in the field, and so, not
4 totally accurate.
5 WITNESS HOOPER
6 Q. WHAT MEASURES DOES WITNESS DAVID L. HOOPER DISCUSS?
7 A. He discusses what I have called Item 4, "time-to-average-answer standard for
8 telephone response of call center employees." Presumably he also discusses what I
9 have called Item the " time-to-connect standard for new service installation where no
10 construction is required."
11 Q. WHY DO YOU SAY "PRESUMABLY"?
12 A. Because Mr. Hooper does not report the proper measure for time-to-connect, as
13 contemplated in the ISA. I discuss this below.
14 Q. WHAT IS THE FIRST MEASURE MR. HOOPER DISCUSSES IN HIS
15 TESTIMONY?
16 A. The target for average speed of answer (ASA) set by the ISA is within 60 seconds.
17 As I discussed above, under certain stresses, TCC was unable to satisfy the standard,
18 and had to provide an improvement plan to the PUCT as required by the ISA.
19 Q. WHAT ARE THE RESULTS OF THE IMPROVEMENT PLAN?
20 A. Using the Virtual Call Center, Mr. Hooper suggests, TCC has been able to drop the
21 ASA to 38 seconds, year to date. However, since then the ASA seems to be creeping
22 up again. The updated ASA through 12/31/04 is 42 seconds.
DIRECT TESTIMONY 67 GOODFRIEND
1 Q. AVERAGES ARE NICE. DOES VARIANCE MATTER?
2 A. Yes. As in the April 2001 event, TCC has not consistently met target in all months.
3 Arguably it is most important to have a timely response when the system is under
4 stress from external events that are generating the customer calls. Events in October
5 2003 forced the monthly average above the target, suggesting that consistency of
6 achievement on the ASA target is still in some question.37
7 Q. WHAT IS HIS SECOND MEASURE?
8 A. Mr. Hooper uses the term "existing meter" connects, and then asserts that this is what
9 is supposed to be measured by the ISA. The ISA doesn't use this term. An "existing
10 meter" connect is a "left in hot" or energized meter. TCC has a fully automated
11 process for connecting these meters on a move-in or switch transaction, if they have a
12 meter reading within five days prior to the requested date.38 And, we know if they
13 don't, they can complete the automated process, keeping these performance statistics
14 up, by use of an estimated meter read.
15 The question, of course, is what happens with more difficult move-m
16 transactions. Thus, we really don't know whether TCC is meeting the 95% target
17 when the reported data is properly expanded to include all new service installations.
18 Moreover, TCC reports that it is exceeding the PUCT target of 95% in Subst.
19 R.§25.490. Subst. R. §25.490 governs the ending of the moratorium on disconnects
20 which the PUCT instituted early on to address re-connection problems. Here again,
21 TCC is describing a left-in hot or energized meter situation. Like all the other TDSPs
37 Response to Cities 30-14 Attachment 1.
38 Response to Cities 16-20.
DIRECT TESTIMONY 68 GOODFRIEND
1 who report on this measure, TCC is meeting this target for reconnection on energized
2 meters. TCC is reporting a measure based on less than full scenarios.
3 TCC REPORTED BILLING ACCURACY MEASURE
4 Q. DOES MR. HOOPER REPORT ANY OTHER STATISTICS?
5 A. In addition to his ISA reporting, Mr. Hooper reports a measure he describes as the
6 percentage of bills that require no adjustments and indicates that for the period
7 January through August this number is 98.74%. The 2003 measure is 98.78%.39 He
8 claims that this statistic is a good indicator of meter reading and billing success.
9 Q. WHAT DO YOU MAKE OF HIS CLAIM?
10 A. First, there is no definition showing how the statistic is constructed and what data are
11 used. Although Mr. Hooper provides no definition for his statistic, it appears to be
12 the same statistic that TCC has reported previously as the one measure TCC decided
13 to include in the ISA reports to the PUCT that was not specifically asked for: the
14 BILLADJ measure. Perhaps, BILLADJ was provided in response to a general ISA
15 request to include billing error information.
16 Second, if this is BILLADJ, it is interesting to notice that this measure, unlike
17 the other ISA reported measures, shows very little variability: For 2001 the statistic
18 is 99.79. For 2002 the statistic is 99.86. For 2003, through August, as reported by
19 Mr. Hooper, the statistic is 98.74 and updated for all of 2003, the statistic is 98.78.
20 For example, if BILLADJ is measuring every bill that TCC sends, not just bills based
21 on meter reads to retail customers, but a larger universe of billings, then one would
22 expect this statistic to behave as it does. That is, the reason it has such low variability
39 Response to Cities 30-13.
DIRECT TESTIMONY 69 GOODFRIEND
1 may be because, as a statistical measure, BILLADJ isn't really providing much
2 information of value from the perspective of assessing regulated utility billing quality.
3 Third, if my suppositions above are all wrong, then I will simply point out that
4 TCC is not currently meeting its Texas target for BILLADJ, which TCC reported in
5 its 2001 ISA filing to the PUCT as being 99%.
6 And fourth, other billing data provided by TCC in discovery, some filed
7 confidentially and some not, indicate less than 99% billing accuracy when what is
8 being measured is the sending of bills to REPs. The reported measure here is simply
9 inconsistent with utility-specific data on estimated meter readings, cancellations and
10 rebillings, etc. provided to me by TCC in this proceeding.
11 2. SERVICE QUALITY REPORTING: RECOMMENDATION
12 Q. DO YOU HAVE ANY CONCLUDING REMARKS FOR THIS SECTION?
13 A. First, confidential reporting of TDSP performance measures is contrary to good
14 regulation and results solely from an anomaly created in drafting the rule rather than
15 from regulatory intentions. The reporting of performance measures by regulated
16 utilities is a tool for regulation, not a means to secrecy. The intention of Subst. R.
17 §25.88 is not to put information concerning a regulated TDSP with no competitors
18 and subject to rate regulation on par with information pertaining to competitive
19 entities such as REPs. For example, none of the ERCOT performance measures are
20 confidential because ERCOT files on behalf of itself. That ERCOT also files on
21 behalf of the TDSPs has created the anomalous result that information pertaining to
DIRECT TESTIMONY 70 GOODFRIEND
1 TDSP performance requested by the Commission is not available for analysis to
2 anyone other than Staff able to review the confidential filings.4°
3 Second, public reporting of TDSP performance measures is in the public
4 interest. The public reporting of TDSP performance information can create
5 benchmarks for further assessment and identification of the most pressing problems
6 by those who have an interest in seeing performance problems identified and fixed.
7 Thus, the Commission should direct TCC to file as non-confidential the "B
8 Report" portion of TCC's Quarterly Performance Report that ERCOT now files
9 confidentially on behalf ofTCC.
10 III. REQUEST FOR GOOD CAUSE EXCEPTION
11 A. NEITHER ABD O&M SERVICES NOR TRANSMISSION
12 CONSTRUCTION SERVICES COMPLY WITH SUBST. R.
13 §25.342(f)(D) OTHER SERVICE
14
15 1. REGULATED UTILITY PROVISION OF UNREGULATED
16 SERVICES: DEFINITIONS AND DISTINCTIONS
17
18 LEGAL FRAMEWORK
19
20 Q. WHAT FRAMEWORK WILL YOU USE TO EVALUATE TCC'S REQUEST?
21 A. I will be using the Substantive Rules governing Unbundling. Specifically, I will be
22 discussing §25.341 "Definitions" and §25.342 "Electric Business Separation," and in
23 particular, § 25.342 (f) "Separation of transmission and distribution utility services,"
24 of which the "Other service" rule is a part.
40 This is data reported by ERCOT on the TDSPs behalf. ERCOT may send or sends this data to the TDSP
under its right to contest the accuracy of the ERCOT Report. ERCOT must report TDSP information as
confidential since any information relating specifically to any other entity (unless the Commission determines
otherwise) must be confidentially reported. See Filing Requirements For Performance Measure Reporting
Pursuant to PUC Subst. R. 25.88.
DIRECT TESTIMONY 71 GOODFRIEND
APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784...
2005 WL 6472784 (Tex.P.U.C.)
Slip Copy
APPLICATION OF AEP TEXAS CENTRAL COMPANY FOR AUTHORITY TO CHANGE RATES
PUC Docket No. 28840
SOAH Docket No. XXX-XX-XXXX
Texas Public Utility Commission
2005
ORDER
Before Hudson, Chairman, Parsley, and Smitherman, Commissioners.
BY THE COMMISSION:
This Order addresses the application of AEP Texas Central Company (TCC) for authority to change its rates. TCC initially filed
its application on November 3, 2003, seeking approval of a revenue requirement of $519.9 million. For the reasons discussed in
this Order, the Commission determines that TCC's appropriate revenue requirement is $443,607,238. The reduction reflects an
agreed disallowance of $10.5 million in affiliate expenses, as well as additional disallowances as determined by the Commission.
As allocated, the distribution portion of TCC's current revenue requirement will increase by $5.3 million, whereas the wholesale
transmission portion will decrease by $14.1 million.
As discussed in this Order, the Commission adopts in part and rejects in part the proposal for decision (PFD) and remand PFD
issued by the State Office of Administrative Hearings (SOAH) administrative law judges (ALJs) in this proceeding, including
the findings of fact and conclusions of law.
I. Procedural History
The Commission referred this case to SOAH on November 4, 2003, and SOAH issued its initial PFD on July 1, 2004.
The Commission issued an Order on Remand on July 28, 2004, directing SOAH to consider the appropriate amount for a
consolidated tax-savings adjustment, which was not calculated in the initial PFD. On August 25, 2004, the Commission issued
a Second Order on Remand, directing SOAH to provide further evaluation regarding the following issues: affiliate costs,
distribution administrative and general (A&G) expense adjustments, depreciation expense, net salvage, special meter reading
fee, connect fee and service reconnect fee, and priority disconnect fee. SOAH issued its Remand PFD on November 16, 2004.
The Commission considered the initial PFD and the Remand PFD at its January 13 and January 27, 2005 open meetings. The
Commission determined at that time that the issues of merger savings, affiliate costs, and distribution A&G expense adjustments
needed additional consideration and held a hearing on March 3, 4, and 7, 2005 to develop a further understanding of the record
on those issues. Accordingly, finding of fact 20A is added to reflect this additional procedural history. Additionally, finding of
fact 20 and conclusion of law 6 are modified to reflect TCC's waiver of the effective date to allow the Commission additional
time to hold this hearing and to complete its deliberations. 1
This Order combines the findings of fact and conclusions of law from both the initial and the remand PFDs, as well as those
added by the ALJs pursuant to their letter of clarifications and changes filed on August 19, 2004. Thus, the remand findings
of fact and conclusions of law are inserted in the appropriate location and designated with an “R” followed by its Remand
PFD number, while the Commission's amended findings of fact and conclusions of law are designated with the traditional “A,”
“B,” etc.
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II. Discussion
A. Merger Savings
In Docket No. 19265, 2 the Commission approved the merger of American Electric Power Company (AEP) and Central and
Southwest Corporation (CSW). In approving the merger, the Commission adopted the Integrated Stipulation and Agreement
(ISA), which was an agreement among a majority of the parties to the case that reflected numerous commitments made by
AEP regarding merger-related issues. Among those commitments was a regulatory plan that provided for net merger-savings
rate-reduction riders, which reduced rates to customers by annual, pre-determined amounts. Additionally, the regulatory-plan
portion of the ISA provided for a “net merger savings” expense item designed “to prevent ratepayers from receiving their share
of merger savings twice and to ensure that shareholders retain their share of net merger savings.…” 3 This expense item was
limited by a provision that applies if a Texas operating company initiates a rate case. Specifically, Section 3.F.(3) of the ISA
provides the following:
(3) In any proceeding initiated by a Texas operating company requesting an increase to overall base rate revenues to become
effective prior to the end of the six year period after the date of the merger:
(a) The net merger savings expense item and annual amount of amortization costs to achieve the merger will not be included
in the calculation of the cost of service unless the Texas operating company demonstrates:
(i) that the proposed rate increase results from circumstances not directly or indirectly related to the merger; and
(ii) that the full level of achieved merger savings for the applicable year as reflected in Attachment D have been achieved; and
(b) the revenue requirements otherwise determined to be reasonable and necessary will be reduced by the annual amounts
included in Attachment E.
As stated previously, this section applies only if TCC initiated a proceeding requesting an increase to overall base-rate revenues.
The PFD determined that TCC initiated such a proceeding, and the Commission affirms that finding. Pursuant to Section 3.F.
(3), TCC requested an increase to overall base-rate revenue, and thus initiated the rate case. Had TCC come to the Commission
to defend its current rates, or requesting a rate decrease, it would not have been subject to this provision.
The next inquiry is to determine whether the proposed rate increase results from circumstances not directly or indirectly related
to the merger. The ALJs found that the proposed rate increase did not result from circumstances directly or indirectly related
to the merger, and the Commission also affirms that finding. In addition to this query, Section 3.F.(3)(a)(ii) requires that TCC
demonstrate that the full level of merger savings, as reflected in Attachment D to the ISA, have been achieved.
In presenting its case on whether merger savings were achieved, TCC relied heavily on the testimony of its witness Michael
Heyeck, who in turn relied on the study completed in Docket No. 19265 by witness Thomas Flaherty. Mr. Heyeck projected
total electric operations and management (O&M) costs (adjusted to exclude purchased power, fuel, and factoring of accounts
receivables) on a stand-alone basis beginning with actual 1997 data. The adjusted balance was calculated using a weighted-
average composite rate from escalators employed by Mr. Flaherty in Docket No. 19265. These escalators reflect increases
of 3% for general inflation, 4% for wages and salaries, and 5% for certain other professional services. After performing his
calculations, Mr. Heyeck determined that the gross merger savings for the test year were $27.7 million. 4 Additionally, TCC's
witness David Carpenter presented testimony of large-scale corporate savings throughout AEP as a result of the merger. 5
A chief criticism of the intervenors' was that Mr. Heyeck relied on the work product of a former witness who was not called in
this proceeding. 6 They further complained that Mr. Heyeck's calculations were faulty and that he failed to use current inflation
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factors and instead used the same inflation factors used by Mr. Flaherty in 1997. 7 The ALJs agreed with the intervenors and
found that TCC did not meet its burden to prove that the company achieved the full level of required merger savings.
The Commission disagrees with the ALJs, and determines that TCC did meet its burden of proof to demonstrate that merger
savings were achieved. The Commission did not require the company to specifically track merger savings. 8 Thus, there was
no requirement that the company provide a detailed cost analysis identifying all merger-related cost reductions. Accordingly,
Mr. Heyeck did not improperly rely on the work of Mr. Flaherty, but appropriately used his work to calculate merger savings in
a manner compatible with the merger-savings target in the ISA. Consequently, the Commission concludes that the information
provided by Mr. Heyeck is sufficient to demonstrate that merger savings were achieved. The merger-savings target contemplated
by Attachment D to the ISA, although not directly calculated by Mr. Flaherty, was based on the merger-savings projections made
by him in Docket No. 19265. 9 By applying the same inflation rate that Mr. Flaherty used, Mr. Heyeck reasonably projected the
appropriate amount of merger savings; applying a different inflation factor would result in a skewed comparison of data. In the
absence of a specific directive to track merger savings, the Commission determines that TCC demonstrated not only that the full
level of merger savings has been achieved, but also that the savings exceeded the amount required by Attachment D to the ISA.
Accordingly, findings of fact 32A and 32B are added and conclusion of law 7 is modified. Additionally, finding of fact 33 is
modified to delete the term “affiliate,” and replace it with the term “effective.”
B. Rate Base
1. Post-Test-Year Adjustments
In its application, TCC sought to add $8.2 million to its rate base for distribution-plant capital expenditures made during the test
year for plant placed in service after the test year. Additionally, TCC proposed reducing its rate base by $6.2 million based on
an expected sale of certain distributed-related facilities after the test year. The Commission adopts the ALJs' recommendations
to disallow TCC's proposed addition to distribution rate base of $8.2 million and to accept TCC's initially proposed reduction
to distribution rate base of $6.2 million. In support of this ruling, the Commission recognizes that P.U.C. SUBST. R. 25.231
prescribes different standards for post-test-year additions to rate base than for post-test-year reductions. Specifically, P.U.C.
SUBST. R. 25.231(c)(2)(F)(i)(II) requires any such addition to constitute at least ten percent of the utility's requested rate base,
whereas P.U.C. SUBST. R. 25.231(c)(2)(F)(iii) contains no such requirement for a rate-base reduction. The asymmetry of these
provisions supports the Commission's decision and undercuts TCC's argument that the ALJs' treatment of the addition and
reduction was inconsistent.
To reflect the different standards in P.U.C. Subst. R. 25.231 for post-test-year additions and reductions to rate base, the
Commission adds finding of fact 39A.
2. Coleto Creek Substation
TCC requested an addition to plant-in-service of $3,016,482, which was the amount by which the actual cost exceeded the
cost estimate included in the utility's original CCN proposal for improving the Coleto Creek substation. TCC argued that the
additional improvements were necessary to accommodate the Electric Reliability Council of Texas's (ERCOT's) plans, and
that utilities should be encouraged to assist ERCOT in long-range transmission plans. The ALJs observed that the Commission
never approved the investment associated with the extra cost, concluded that the underlying design changes were not useful in
serving TCC's current customers, and disallowed the extra $3,016,482.
The Commission reverses the ALJs' ruling and allows inclusion of all but $180,000 of the $3,016,482 at issue. The Commission
finds that TCC prudently re-examined and altered its design plans to accommodate ERCOT's proposal of a Coleto-to-Cuero-
to-Holman double-circuit-capable 345-kV line. This proposal was issued after TCC had submitted its original design and cost
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estimate in the CCN case. 10 As explained by TCC, the original design was selected without regard to the land restrictions of
the existing substation site, and construction based on that design would have precluded meeting the facility needs envisioned
by ERCOT, absent construction of another substation at another location. 11 According to TCC, such facility-duplicating
construction would have cost at least $5 million, resulting in a higher net cost of about $2 million. 12
The Commission further notes that the bulk of the $3,016,482 excess stemmed from the modification of the physical arrangement
of the Coleto Creek additions, which in turn required extra spending on structural steel and foundations. 13 According to TCC,
only $180,000 of that total is associated with facilities (six extra 345-kV switches) installed to accommodate future 345-kV
transmission lines, and hence may be considered not yet in service. 14
The Commission finds that electric utilities should be encouraged to cooperate with ERCOT and make reasonable modifications
to Commission-approved plans for facility construction when doing so would avoid costly facility duplication in the foreseeable
future. Otherwise, utilities would have an undue incentive to focus strictly on short-term needs. The Commission finds it unwise
to encourage such short-sightedness. Accordingly, the Commission disallows only $180,000 of the $3,016,482 in question,
and therefore adds findings of fact 46A and 47A, and modifies findings of fact 47 and 245. 15 The Commission also modifies
conclusion of law 13 and adds conclusion of law 13A.
3. Cash Working Capital and Factoring Adjustment
The ALJs recommended that the Commission set the level of cash working capital (CWC) and associated factoring expense
to reflect a much lower factoring ratio than the 100% recommended by Staff and certain intervenors. As noted by the ALJs,
factoring is a financial technique by which a company sells some or all of its accounts receivable to a third party rather than
collect the payments from its own customers. 16 TCC stated that it currently has no ability to factor its accounts receivable
because the banks with which its predecessor, Central Power and Light Company (CPL), dealt previously (and which are the
ultimate purchasers of accounts receivable) are no longer willing to factor TCC's receivables. TCC noted three reasons for this
unwillingness. First, TCC now bills only a handful of customers (the retail electric providers (REPs)), compared to the hundreds
of thousands of customers it billed before unbundling, and the concentration of credit risk in a few receivables is unacceptable
to the banks. 17 Second, the REPs have no credit history with the banks versus the many years of predictable history regarding
the level of bad-debt expense reasonably expected when TCC was serving end-use customers. Finally, the type of wholesale
customers whose receivables that CPL factored before unbundling were municipal and cooperative utilities, who did not present
as significant a credit risk as the REPs.
The Commission finds that TCC presented persuasive testimony that it had been unable to find any banks willing to factor TCC's
receivables because of credit concerns in the restructured Texas market. 18 Accordingly, the Commission reverses the ALJs and
adopts TCC's original proposal to calculate its cash working capital on the assumption of no factoring. The Commission's ruling
should not be viewed as necessarily applicable to any future rate case of an unbundled transmission and distribution (T&D)
utility. In particular, it is possible that as the retail electric market matures, some REPs will develop credit histories sufficient
to induce banks to participate once again in factoring arrangements with T&D utilities. In such circumstances, the utility could
be required to calculate its cash working capital under the assumption that it factors some or all of its accounts receivable.
In accordance with this ruling, the Commission modifies findings of fact 51 and 52 and deletes finding of fact 53.
C. Cost of Service
1. Affiliate Costs
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TCC originally requested $63.8 million in affiliate expenses. In the initial PFD, the ALJs recommended specific allowances and
disallowances in certain instances. However, after the ALJs discussed the itemized allowances and disallowances, they stated
that the “Applicant has not carried its burden of proving the entirety of its affiliate costs. Specifically, we conclude that for
many of the individual items the Applicant did not overcome the statutory presumption against inclusion.” 19 The ALJs then
stated that they were “hesitant to remove an income stream that may be necessary to maintain the ratepayers' level of service
and to maintain the Applicant's financial viability.” 20 Ultimately, they recommended a $10.3 million disallowance, based on
Dr. Dennis Thomas' testimony. 21
Recognizing that PURA 22 provides that the Commission may not allow affiliate costs unless it has made a specific finding
of the reasonableness and necessity of each item or class of items, 23 and that a disallowance of all affiliate costs is required
where a utility has failed to meet its burden of proving that its rates are just and reasonable, 24 the Commission remanded the
issue of affiliate costs to SOAH for further consideration. The Commission directed that
for costs that the ALJs recommend allowing, that the ALJs make specific findings, supported by the evidentiary record, that the
costs are reasonable and necessary. The findings should be made on an item-by-item or class-of-item by class-of-item basis.
Further, for those items or classes of items for which the ALJs find the Applicant did not meet its burden, the Commission
requests a discussion of the deficiency of the evidence that led to such a finding. 25
In their Remand PFD, the ALJs' primary recommendation did not include specific findings on an item-by-item or class-of-
item by class-of-item basis. Instead, they recommended adopting Dr. Thomas's position that $53.4 million in affiliate costs be
disallowed as TCC did not provide comparisons to demonstrate that each item or class of items was reasonable, necessary, and
not higher than prices charged to others, as set forth in PURA § 36.058. In making this determination, the ALJs concluded that
the provisions of PURA § 36.058(d) relate to each of the two findings required in PURA § 36.058(c).
Thus, the Commission must take into account quantity, terms, date of contract, place of delivery, and allow
for appropriate differences in making each of those findings. Thus, the legislature requires evidence of
comparability as an element not only of the not-higher-than requirement, but also of the reasonableness
and necessity requirements. 26
Expressing concern that the Commission may not agree with their analysis, the ALJs provided an alternative recommendation
“based on an item-by-item or class-by-class review of each of TCC's proposed affiliate costs.” 27 The Commission did not agree
with the ALJs' analysis of PURA § 36.058(d), and was hesitant to adopt either the primary or the alternative recommendations
proposed by the ALJs on this issue. Thus, in order to fully understand the record evidence on this issue, the Commission
conducted its own hearing to further evaluate the evidence that TCC presented on its affiliate costs.
Before the Commission made its final decision on whether TCC met its burden of proof on affiliate expenses, TCC and
Texas Industrial Energy Consumers (TIEC) filed a nonunanimous stipulation (NUS) that provided for a disallowance of $10.5
million. 28 Many parties did not oppose the NUS, 29 but three parties did: the Office of Public Utility Counsel (OPC), CPL
Retail, and Texas Legal Services Center/Texas Ratepayer's Organization to Save Energy (TLSC/Texas ROSE). None of the
parties opposing the NUS requested a hearing on the settlement. 30
In opposing the NUS, CPL Retail now argues that its “top-down” approach may be in jeopardy as a result of the passage of
Senate Bill 1668, 31 and that if the Commission instead uses a “bottom-up” approach, the evidence would support a larger
disallowance than that realized through the NUS. 32 OPC argues that the NUS will result in a rate increase to distribution
customers and that instead the Commission should disallow between $16.6 and $50 million. 33
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The Commission adopts the NUS, and determines that it meets the standards required of a non-unanimous settlement: it complies
with applicable law; it is just, reasonable, and in the public interest; and it is supported by a preponderance of the record
evidence. 34
The arguments set forth by OPC and CPL Retail are not persuasive. Although in their initial direct testimony, both Cities and
CPL Retail argued that the lack of evidence provided by TCC on its affiliate expenses could have supported a disallowance of
nearly the entire amount requested, neither party fully advocated that position, and instead recommended a smaller disallowance.
The evidence in the record supports adoption of the NUS. The disallowance recommended in the NUS is within the range of
that recommended by the intervenor witnesses in this proceeding. OPC's witness Carol Szerszen recommended a total affiliate
disallowance of $13,402,570; 35 Cities' witness Gerald Tucker recommended a total affiliate disallowance of $16,572,333; 36
and CPL Retail's witness Dr. Thomas recommended a disallowance of $10,319,991. 37
Additionally, in compliance with PURA § 36.058, the stipulating parties have agreed that, except for the proposed disallowance,
TCC's affiliate expenses are reasonable and necessary and that the charges to TCC are not higher than the prices charged by
its affiliate, American Electric Power Service Corporation, to its other affiliates or divisions or to non-affiliated persons for the
same item or class of items. Finally, the NUS results in a reasonable resolution of this complicated issue. 38
Accordingly, the Commission deletes remand findings of fact R9-R13 and adds findings of fact 69A, 158A-158H, and deletes
conclusions of law 26-29 and 72-74. In addition, the Commission modifies findings of fact 55, 39 67 and 71 and adds conclusions
of law 25A-25C to reflect this decision.
2. Debt-Reacquisition Costs
In its application, TCC sought to include in its rate base approximately $12.5 million in costs resulting from the company's
retirement of debt during unbundling. TCC requested that amortization of this amount over a fifteen-year period be included in
its cost of service. The ALJs disallowed this item, and held that TCC inappropriately included the entire $12.5 million in this
proceeding, rather than allocating this amount to transmission and distribution on the basis of proportionate net book value for
the transmission, distribution, and generation functions.
The Commission disagrees with the ALJs' determination that TCC's requested recovery of $12.5 million in debt reacquisition
costs in this case is inappropriate. The Commission finds that TCC appropriately included the entire $12.5 million in rate base,
to be amortized into cost of service over fifteen years. The ALJs and the intervenors rest their determination on an incorrect
reading of the Commission's final order in Docket No. 22352, TCC's unbundled cost of service (UCOS) case. 40 In that case,
the parties' stipulation resolving the proceeding and the Commission order adopting it stated that debt refinancing costs incurred
to restructure CPL were to be deferred and amortized over a fifteen-year period, with the unamortized portion included in rate
base. 41 The parties retained the right to challenge the reasonableness of the total amount of debt restructuring costs, as well
as the reasonableness of the fifteen-year amortization period. 42
In this proceeding, the parties are challenging neither the amount of debt-restructuring costs nor the reasonableness of the fifteen-
year amortization period. Rather, the intervenors' challenge is to TCC's allocation of the $12.5 million in debt-restructuring costs
solely to transmission and distribution. The stipulation and order in Docket No. 22352 do not expressly permit the signatories to
challenge the allocation of restructuring costs, only their amount and the timing of recovery. Thus, the Commission concludes
that the intervenors are precluded from making the argument they now urge in this rate case.
Furthermore, the substance of the intervenors' argument is incorrect. The order in Docket No. 22352 did not state that TCC
may recover a total amount of debt restructuring charges that must be further allocated between T&D and generation; rather,
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the debt-restructuring cost discussed in the order reflects an amount already allocated to transmission and distribution. Finding
of fact 98 in the Docket No. 22352 order envisioned that these costs would be included in rate base and amortized, and that
the parties may only challenge the costs in a future rate case on certain limited grounds. These concepts have relevance only in
cost-of-service regulation, under which only CPL's unbundled T&D utility would operate.
Therefore, TCC may include approximately $12.5 million in debt-restructuring costs in its rate base, and may amortize the
amount into cost of service over a fifteen-year period. The Commission deletes finding of fact 161 and modifies finding of fact
162 to reflect the foregoing discussion. The Commission also modifies conclusions of law 30 and 31.
3. Group-Insurance Expense
TCC originally requested $4,649,872 in total group-insurance expenses, an amount which included both $3,741,039 in test-year
group-insurance expenses and a post-test-year increase of $908,833. The PFD, as corrected by the ALJs' letter filed on August
19, 2005, recommended inclusion of both the test-year amount and the post-test-year increase. The ALJs cited an actuarial
study conducted for TCC and presented by the company in this proceeding as support for the post-test-year increase.
The Commission finds that the company's actuarial study provides insufficient support for a post-test-year increase to group-
insurance expense. The proper criteria by which to evaluate a requested post-test year increase is the “known and measurable”
standard; the Commission has codified this standard in its substantive rules. 43 This standard is not satisfied by an actuarial
study that predicts increased group-insurance expense in the future. Such a study, and the cost estimates that derive from the
study, are subject to change, and the company itself is not bound to incur the group-insurance expense predicted by the study.
Accordingly, the amount that TCC will expend for group insurance after the test year is not currently known or measurable. If
TCC desires that the group-insurance expense projected by the actuarial study be included in its cost of service, the company
must actually incur those expenses and seek recovery of those costs on a historical basis.
Accordingly, the Commission modifies the ALJ's proposed finding of fact 179 and adds finding of fact 179A to reflect that
only TCC's test-year group-insurance expense is recoverable through cost of service. Additionally, the Commission modifies
conclusion of law 48 to indicate that the expense is includible in TCC's cost of service rather than its rate base.
4. Catastrophe Reserve
In its application, TCC sought to increase its catastrophe reserve from $5.4 million to $13.5 million. TCC argued that the
increase was necessary because its reserve was virtually depleted as a result of Hurricanes Brett in 1999 and Claudette in 2003.
The ALJs, relying on the analysis adopted by the Commission in Docket No. 14965, concluded that the previously approved
$5.4 million reserve is adequate. The ALJs noted that TCC has not requested Commission approval to resume the accrual of
funds to re-establish the currently approved maximum. Thus, the ALJs rejected the proposed increase and recommended that
TCC simply resume its funding to reach the maximum level.
The Commission disagrees that the current funding level is adequate. As set forth in TCC's witness Nadel's testimony, there is a
10% probability that the loss in any single year from hurricane damage could be as high as $14 million. 44 The Commission does
not, however, agree that TCC's proposed increase to $13.5 million is reasonable. Instead the Commission allows the catastrophe
reserve to be funded at $9 million for 10 years. This amount was within the range proposed by the witnesses on this issue. 45
Accordingly, the Commission modifies findings of fact 181 and 181A and conclusion of law 48A to reflect this change. 46
5. Distribution O&M Expense Adjustments
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The PFD recommended that TCC's request for distribution operations-and-maintenance (O&M) expenses be granted, except
that $1.0 million attributed to various other accounts should not be approved, as the ALJs were uncomfortable with TCC's lack
of specificity as to this requested amount. 47 The evidence supporting this request was further considered by the Commission
at its hearing. At the hearing, TCC demonstrated through Randall Hamlett's rebuttal testimony that the expense was charged
to FERC Account 588 during the test year and is includable in cost of service because TCC will continue to incur vehicle-
maintenance expense. 48
The Commission reverses the PFD and determines that the $1 million expense for vehicle maintenance was a necessary,
recurring expense. Accordingly, the Commission modifies finding of fact 201 and conclusion of law 55.
6. Distribution A&G Expense Adjustments
The Commission remanded this item to SOAH to provide further analysis of the basis for the reasonableness of the Applicant's
actual A&G expense. The Commission adopts the recommendations contained in the Remand PFD; however, it appears that
the ALJs included an incorrect number in finding of fact R16. Accordingly, the Commission modifies this finding to accurately
reflect the merger-related revenue-requirement credit of $7,496,000.
7. Third-Party-Contract Margin-Sharing Proposal
The ALJs determined that TCC should not be granted a good-cause exception to P.U.C. SUBST. R. 25.342(f)(1)(D)(ii)(III),
which requires all revenue from an “other” service to be credited to reduce a utility's cost of service. TCC had requested that it
credit only half of the revenues received from its associated business-development program.
The Commission agrees with the ALJs' recommendation; however, it further clarifies finding of fact 209 to reflect that TCC's
request is denied. Additionally, the Commission modifies conclusion of law 59 by replacing the word “faith” with “cause.”
8. Rate-Case Expenses
The Commission severs rate-case expenses into a separate proceeding for further consideration of the reasonableness and
necessity of the expenses. Accordingly, the Commission deletes findings of fact 210-216, modifies finding of fact 256, and
deletes conclusion of law 58.
D. Quality and Reliability of Service Issues
1. Reliability of Service
The PFD in this case addressed certain overlapping issues related to American Electric Power Company's (AEP's) 49 petition
to revise service-quality commitments in Docket No. 25157. 50 The PFD issued in Docket No. 25157 incorporated a portion
of the PFD issued in this proceeding regarding service-quality issues and penalty payments.
On December 17, 2004, TCC filed an alternative motion to sever and abate certain service-quality issues from this Docket
No. 28840 to Docket No. 25157. TCC argued that the issues overlap and that severance promotes administrative efficiency
and consistent treatment among all AEP companies. At its January 13, 2005 open meeting, the Commission granted TCC's
motion. The Commission agrees that it is appropriate to consider all issues related to the service-quality commitments in a
single proceeding, Docket No. 25157. Accordingly, the Commission does not adopt the ALJs' discussion of this issue in the
PFD and deletes findings of fact 218 and 219 and conclusions of law 61 and 62.
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E. Rate Design
1. Load Data and Distribution Field Study
The ALJs recommended that the load data and distribution field study provided by TCC be used in this proceeding. The
ALJs also recommended that TCC develop new load data prior to TCC's next rate case. The Commission adopts these
recommendations. In addition, the Commission requires TCC to develop a new distribution field study prior to its next rate case.
Developing new data will ensure that TCC has the most recent information to determine costs in future ratemaking proceedings.
2. Energy-Efficiency-Program Costs
The ALJs recommended that energy-efficiency-program costs be allocated on a 50% demand and 50% energy basis. The
Commission reverses this recommendation based on PURA § 39.905(c), which specifically refers to energy demand when
requiring “incentives sufficient for retail electric providers and competitive energy service providers to acquire additional cost-
effective-energy efficiency equivalent to at least 10 percent of the electric utility's growth in demand.” Based on the language
of the statute, the Commission finds that cost allocation should be made on a demand basis, rather than allocated on the basis
of 50% demand and 50% energy. Therefore, the Commission modifies finding of fact 237 and conclusion of law 64 to allocate
energy-efficiency costs based on a demand basis.
3. Debt-Reacquisition Costs
The ALJs recommended disallowing the recovery of $12.5 million in debt-reacquisition costs. Due to this disallowance, the
ALJs did not reach a decision on the proper allocation of these costs. However, as discussed in section II.C.2 of this Order,
the Commission reversed the ALJs' recommendation and allowed for the recovery of the debt-reacquisition costs based on the
stipulation and order in Docket No. 22352 in this proceeding. Consistent with this decision, the Commission adopts TCC's
proposed allocation method for the recovery of these costs using a distribution-plant allocator. Before declining to issue a
recommendation, even the ALJs pointed out that “the costs in question were incurred to finance invested capital, [and] it would
appear that the refinancing costs should be allocated on the same basis as the underlying investments supported by the debt.” 51
The Commission agrees. Using the distribution-plant allocator will recover the costs from customers that primarily benefit from
the investment supported by the debt. Accordingly, the Commission adds finding of fact 237A to reflect the proper allocation
of the debt-reacquisition costs.
4. FERC Account 370 (Meter Installation)
TCC proposed to allocate meter costs in FERC Account 370 to all customers based on a weighted number of meters for each
class. TCC used the meter costs developed in Docket No. 28559, 52 the competitive-metering-credit docket, for all classes
except for primary- and transmission-voltage-level customers. The costs for these customers were not updated in Docket No.
28559, and the costs used were from TCC's UCOS case, Docket No. 22352. Several parties objected to mixing cost data from
two different time periods, arguing that it could lead to skewed and disparate results. The ALJ agreed, and recommended that
the costs established in Docket No. 22352 be used for all classes.
The Commission disagrees with the ALJs' recommendation, and finds that the use of the most up-to-date information is
preferable. The data developed in Docket No. 28559 takes into account changes to the customer classes that have occurred
since the UCOS docket. The Commission finds that TCC's proposed Account 370 allocator should be used to allocate meter
costs, and appropriately modifies finding of fact 241.
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5. FERC Account 565
The ALJs recommended several changes proposed by Staff to TCC's Account 565 allocator. These changes to the allocator are
due to TCC's incorrect methodology to develop the allocator. While the changes recommended by the ALJs ultimately achieve
the correct results, the Commission clarifies that the correct method to determine the amount to be collected in retail rates for
the transmission function is to use Schedule TCOS as included in the rate-filing package. Use of Schedule TCOS in future rate
cases will achieve accurate results without the need for the corrections made by the ALJs.
6. Nuclear-Decommissioning Rider
The ALJs recommended that nuclear-decommissioning costs should be recovered through base rates, pursuant to the settlement
reached in Docket No. 22352. However, in the period since the ALJs issued the PFD, the Commission amended P.U.C. SUBST.
R. 25.303(g)(1) to require that a utility's nuclear-decommissioning costs be “removed from its general rates and stated as a
separate nonbypassable charge.” 53 Based on the change to Commission rules, the Commission reverses the PFD to require that
nuclear decommissioning costs be recovered through a separate rider, and modifies findings of fact 259 and 261 and conclusion
of law 71.
7. Resolved Disputes
Several parties disputed different fees charged by TCC. Of these, the disputes were resolved between the parties relating to
the Account History Fee, the Inaccessible Meter Fee, and the Service Call Fee. The Commission modifies the applicability of
the Service Call Fee to clarify that the fee is only charged if, when a service call is made and an employee dispatched to the
customer's premise, the source of the problem is on the customer's side of the meter. If the problem is determined to be on the
company's side of the meter, the customer will not be charged for the Service Call Fee. Accordingly, the Commission modifies
finding of fact 264 to give effect to this clarification.
8. Disputed Fees
Several other fees that were disputed by the intervenors were not resolved. These fees are the Special Meter Reading Fee,
Connect Fee, Service Reconnect Fee, Priority Connect Fee, Priority Disconnect Fee, Dispatched Order Fee, and the Priority
Dispatched Order Fee. In the Remand PFD, the ALJs evaluated whether TCC provided sufficient evidence for the labor charges
and the loading factor that were used to determine the rates for these services. TCC proposed a loading factor of 60.18%, which
consisted of taxes and a non-productive fringe rate. The loading factor was multiplied by the hourly salary of the employee
to determine the total-loaded-labor rate for each employee. The total-loaded-labor rate was multiplied by 2.5% to adjust for
salary-grade-level increases from 2002 to 2003. TCC also determined the time that various employees performed for each task.
The total-loaded-labor rate adjusted for the salary increase was multiplied by the amount of time for each employee for each
service. This determined the cost for each employee involved for each service. The costs were added to determine the final
cost and proposed charge for the service.
The ALJs concluded that only 7.65% of the loading factor related to social security and medicare taxes was reasonable, and
that no evidence was submitted showing that employees receive a salary increase of 2.5%. The ALJs, using the reduced loading
factor of 7.65%, reduced the amount of all the disputed fees from what TCC recommended.
The Commission notes that in the schedules provided, TCC proposes different charges based on the type of meter or equipment
involved. For example, there are separate proposed charges for the Priority Disconnect Fee depending on whether there is a self-
contained meter, a subsurface box, or pole/metering equipment. 54 In all three situations, the proposed charge is based on the
amount of labor required for various employees, which use the total-loaded-labor rate with the salary adjustment. In the specific
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situation of the Priority Disconnect Fee, only the charge related to the self-contained meter was disputed by intervenors and
re-examined by the ALJs. The charges related to the subsurface box and the pole/metering equipment, which also include the
loading factor and salary adjustment, were not disputed by the intervenors or the ALJs in the Remand PFD. This re-examination
of all the other disputed fees was likewise limited to only a single type of charge within each fee category.
Therefore, to ensure consistency in the use of the loading factor and the salary adjustment across the agreed and disputed
items, the Commission finds that TCC's proposed fees should be adopted. The intervenors do not dispute using the loading
factor and salary adjustment for some charges within each disputed fee category. It is inconsistent that the loading factor and
salary adjustment be changed for certain charges and not for others within the fee categories. The Commission concludes that
the loading rate and salary adjustment are appropriate, and should be used consistently for all service fees. Accordingly, the
Commission modifies findings of fact R19-R22, and deletes findings of fact R23, R24, and 269.
9. Gradualism
TIEC, the State, and CCR recommended that gradualism be applied in this case, while TCC and TXU rejected its application.
TCC contended that this case is a better proceeding to benchmark T&D rates than the UCOS case, while TXU looked at the
UCOS proceeding for Commission direction that gradualism is no longer appropriate. The State proposed gradualism on a
function-by-function basis, which TIEC opposed. TIEC recommended that a cap of 1.75 times the system average be applied
to the tariffed class as a whole. The State recommended a cap of three times the system average for the distribution function,
and 1.5 times the system average for an increase to the metering function. The ALJs were not convinced that gradualism is
an abandoned policy, but viewed the 1.75 times the system-average cap as inadequate, and stated that a cap of two times the
system average is appropriate.
The Commission declines to apply gradualism in this case. This proceeding develops the T&D rates, as opposed to the broader
rates developed for a fully integrated utility. As the T&D rates are only a subset of the total rates paid by customers, changes
to the T&D rates would not have as large an impact as they would if the broader rates for a customer class were changed by
the same percentage. Therefore, gradualism will not be used in this case, and the Commission modifies findings of fact 279
and 283, and deletes finding of fact 281.
F. Miscellaneous Issues
Finding of fact 224 is modified to delete the term “not” to reflect that customers were placed in the new classes in January
2002. 55 Finding of fact R17 is modified to remove “accumulated” and add “expense” as it relates to TCC's end-of-test-year
depreciation expense. Additionally, findings of fact 48, 55, 158G, 272, R17, and conclusions of law 25A and 51 are modified
to reflect updated numbers. 56
Conclusion of law 11 is modified to replace the term “data” with “rate base.” Additionally, conclusions of law 45-47 and 49
relate to inclusions of certain costs in rate base. The Commission modifies these conclusions to replace the term “rate base”
with “cost of service.”
Finally, the Commission adds findings of fact 206A-B to reflect the additional findings related to nuclear decommissioning
expense requested by TCC. 57
III. Findings of Fact
1. AEP Texas Central Company (TCC, the Company, or the Applicant) is an electric utility operating company and wholly
owned subsidiary of American Electric Power Company (AEP), a public utility holding company.
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2. TCC is a transmission and distribution (T&D) utility providing service to a 44,000 square-mile area of South Texas that
includes the portion of Texas from just south of San Antonio to the Mexican border and from Bay City west to Eagle Pass.
3. TCC provides distribution service to approximately 785,000 electric connections receiving electric service from 28 retail
electric providers (REPs) and provides wholesale and transmission service in the Electric Reliability Council of Texas
(ERCOT).
4. On November 3, 2003, TCC filed an application with the Public Utility Commission of Texas to change its T&D rates.
5. On November 4, 2003, the Commission referred this case to the State Office of Administrative Hearings.
6. The Commission issued its Preliminary Order on December 5, 2003.
7. Concurrent with its filing of the application with the Commission, TCC filed a similar petition and statement of intent with
each incorporated city in its service area that has original jurisdiction over its retail rates. Eighty-six (86) cities denied TCC's
petition and statement of intent. TCC filed petitions for Commission review of those denials and filed motions to consolidate
those petitions for review into this rate proceeding.
8. Notice of TCC's application was published once a week for four consecutive weeks in newspapers having general circulation
in each county in TCC's service territory and was completed on November 30, 2003.
9. Individual notice of the application was provided on November 3, 2003, to the Commission Staff (Staff), Office of Public
Utility Counsel (OPC), City of McAllen, City of Harlingen, City of Laredo, City of Victoria, City of Corpus Christi, and City
of Edna.
10. Individual notice of the application was provided by November 3, 2003, to each municipality having original jurisdiction
over TCC's rates.
11. Individual notice of the application was provided by November 3, 2003, to all retail electric providers who have been
certified by the Commission.
12. Individual notice of the Application was provided to each party that participated in Application of Central Power and
Light Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and Public Utility Commission
Substantive Rule § 25.344, Docket No. 22352 (Oct. 5, 2001), TCC's unbundled-cost-of-service (UCOS) rate case.
13. Individual notice of the application was provided on November 3, 2003 to each party that participated in Joint Application
of AEP Texas Central Texas Company and LCRA Transmission Services Corporation to Transfer Certificate Rights and for
Approval of Transfer of Facilities in Goliad and Karnes Counties, Docket No. 27282 (Oct. 31, 2003).
14. The following parties intervened and participated in the hearing: the Cities of Alice, Aransas Pass, Carrizo Springs, Dilley,
Donna, Eagle Lake, Freer, Ganado, George West, Ingleside, Kingsville, La Feria, Laguna Vista, La Joya, Leakey, Los Fresnos,
Lyford, Lytle, McAllen, Mercedes, Mission, Nordheim, Odem, Pharr, Port Aransas, Portland, Port Lavaca, Poteet, Rancho
Viejo, Refugio, Rio Hondo, Runge, San Benito, San Juan, Sinton, Uvalde, and Weslaco (Cities); Texas Industrial Energy
Consumers (TIEC); CPL Retail Energy (CPL Retail); Coalition of Commercial Ratepayers (CCR); City of Garland; Alliance
for Retail Markets (ARM); TXU Business Services (TXU); Texas Legal Services Center and Texas Ratepayers' Organization
to Save Energy (TLSC/ROSE); South Texas Electric Cooperative, Inc. (STEC); State of Texas; OPC; and Staff.
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15. Applicant requests approval of a revenue requirement of $519.9 million, based on an historical test year of July 1, 2002,
through June 30, 2003. Of that amount, $426.6 million is for providing retail T&D service (including the portion of the ERCOT-
wide transmission costs) and $93.3 million for providing wholesale transmission service.
16. Applicant proposes an overall rate increase of 14.7% from its current rate levels: a 19% increase for distribution service
and a 2.5% decrease for transmission service.
17. TCC also seeks a good-cause exception to P.U.C. SUBST. R. 25.342(f)(1)(D)(ii)(III), requesting to share equally with
the ratepayers all net revenues from transmission projects involving Magic Valley Electric Cooperative, Inc. (Magic Valley),
Sharyland Utilities (Sharyland), and LCRA Transmission Services Corporation (LCRA).
18. TCC also seeks approval of a modification of its business separation plan (BSP). The change would allow TCC to retain
its generating assets as part of TCC instead of creating a new unregulated subsidiary for those assets, until they are sold to
a third party.
19. The hearing on the merits was held from March 2 through March 18, 2004. The record closed on June 17, 2004.
20. TCC proposed an effective date of December 8, 2003, for the proposed rates. The effective date was suspended for 150 days
until May 7, 2004, pursuant to P.U.C. PROC. R. 22.33(b)(6) and P.U.C. SUBST. R 25.241(i). In a letter dated May 13, 2004,
TCC agreed to extend the effective date for new rates until August 6, 2004. At the Commission's January 13, 2005 open meeting,
TCC agreed to waive the effective date to allow the Commission additional time to complete the processing of this case.
R1. The Commission issued Orders on July 28 and August 25, 2004, remanding portions of the case to the State Office of
Administrative Hearings.
R2. A hearing on the remanded consolidated tax savings issues was held on September 3, 2004. The record closed on September
17, 2004.
20A. On March 3, 4, and 7, 2005, the Commission held additional hearings to further analyze the evidence previously filed
regarding merger savings, affiliate expenses, and distribution administrative and general expense.
A. Merger Savings and Expenses
21. In Application of Central and South West Corporation and American Electric Power Company, Inc. Regarding Proposed
Business Combination, Docket No. 19265 (Nov. 18, 1999), the Commission approved an Integrated Stipulation and Agreement
(ISA) between the Applicant and many of the intervenors in this case, including Cities.
22. The parties' agreements in the ISA define some of the rights and obligations of the parties in this application.
23. In June and July 2003, the cities of McAllen, Victoria, Laredo, Corpus Christi, Harlingen, and Edna (Six Cities) adopted
resolutions that constituted notice of each city's intent to proceed with an inquiry into the T&D rates charged by the Applicant.
24. The goal of each city's inquiry was to determine whether the rates being charged by the Applicant were just and reasonable.
25. The resolutions provided that a procedural schedule should be established for the filing of a rate package by the Applicant,
concluding with a public hearing.
26. On July 14, 2003, before any of the Six Cities' proceedings were initiated, the Six Cities entered into a Stipulation and
Agreement (July 14 Agreement) with the Applicant.
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27. The purpose of the July 14 Agreement was to alter the terms of their resolutions by providing that: (a) the Applicant would
file a rate filing package with each of the cities by November 3, 2003, in the form required by the Commission, (b) the cities
would schedule a public hearing at a date to be set later, and (c) the Applicant would file its rate filing package with the
Commission on November 3, 2003, “in order to initiate the [Commission's] review of [the Applicant's] rates.”
28. The Six Cities gave notice that each would inquire into the question of whether the Applicant's rates were just and reasonable.
29. The ISA contains a set of contingent agreements that turn upon the issue of whether the Applicant “initiates” a rate case
prior to the expiration of a six-year period from the approval of the ISA.
30. The Six Cities' actions in giving notice of their intention to inquire into the reasonableness of the Applicant's rates, without
a final determination, cannot reasonably be characterized as the cities' having initiated a rate case with the Commission.
31. The Applicant initiated the rate case with the Commission.
32. Section 3.F.(3) of the ISA provides that, in cases initiated by TCC, merger-savings expenses and costs to achieve merger
savings will not be allowed in the cost of service unless TCC demonstrates that the proposed rate increase results from
circumstances not directly or indirectly related to the merger and that the full level of achieved merger savings for the applicable
year have been achieved.
32A. Attachment D of the ISA requires TCC to demonstrate that it achieved $22,513,700 in merger savings during the year
applicable to this proceeding.
32B. TCC demonstrated that it achieved at least $27 million in merger savings, therefore meeting the full level of savings
required by Attachment D.
33. Section 3.F.(2) of the ISA permitted TCC to defer and amortize its costs to achieve the merger over a six-year period
following the effective date of the merger.
34. Section § 3.F.(3)(b) of the ISA provides that the revenue requirement otherwise found reasonable and necessary will be
reduced by the annual amount included in Attachment E of the ISA if TCC files a proceeding to increase rates that are to be in
effect prior to the end of the six-year period after the effective date of the merger.
35. The merger became effective on June 15, 2000.
36. Because the test year for this case ended on June 30, 2003, the revenue requirement otherwise found reasonable and necessary
should be reduced by $7,496,000, as provided for in Attachment E.
B. Rate Base Adjustments
37. TCC's proposal to reclassify $24.7 million (distribution) and $18.2 million (transmission) in plant-related investment from
construction work in progress to plant in service is uncontested and is reasonable.
38. TCC proposes a post-test-year adjustment that would increase rate base by $8,228,567 for distribution-plant expenditures
made during the test year for capital projects that were added to plant in service before the new rates are to take effect.
39. The $8,228,567 of distribution plant was dedicated to and in public service before the rates set by this order will take effect.
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39A. P.U.C. SUBST. R. 25.231(c)(2)(F)(i)(II) requires any post-test-year addition to constitute at least 10% of the utility's
requested rate base, whereas P.U.C. SUBST. R. 25.231(c)(2)(F)(iii) contains no such requirement for a rate-base reduction.
40. TCC's rate base is $1,343,448,441. TCC's proposed post-test-year adjustment of $8,228,567 does not comprise at least 10%
of its requested rate base.
41. TCC did not make any adjustments to revenues resulting from customer growth between the end of the test year and the
in-service date of TCC's plant additions.
42. TCC failed to account for accumulated depreciation and accumulated deferred income tax associated with the plant additions.
43. TCC's proposed adjustment to increase rate base by $8,228,567 is unreasonable.
44. TCC's proposal to make a post-test-year reduction to rate base, reflecting its plan to sell $6.2 million worth of distribution
facilities to industrial customers, is uncontested and is reasonable.
45. It is reasonable to reduce TCC's material and supplies inventory from $13,805,198 to $13,503,928 based on more recent data.
46. TCC redesigned improvements to the Coleto Creek substation to accommodate ERCOT's plans for future transmission lines
that would connect to the substation. The cost of the redesigned improvements was $3,016,482.
46A. TCC prudently re-examined and altered its design plans to accommodate ERCOT's proposal of a Coleto-to-Cuero-to-
Holman double-circuit-capable 345-kV line.
47. Only $180,000 of the redesigned improvements to Coleto Creek are not useful to TCC in serving its current ratepayers.
47A. It is reasonable to include in TCC's rate base $2,836,482 in improvements resulting from the redesign of the Coleto Creek
substation.
48. TCC's proposal to include a cash-working-capital amount in rate base of $6,672,117 for distribution and ($2,209,787) for
transmission is reasonable and appropriate.
49. TCC's lead-lag study is reliable and fully supports TCC's cash-working-capital proposal.
50. Factoring of accounts receivable should be considered because it historically benefits customers.
51. TCC is unable to factor any of its REP accounts receivable at this time, because the banks with which it dealt previously
are no longer willing to factor TCC's receivables.
52. At this time, TCC is not able to factor its accounts receivables to the same extent and under the same terms that its predecessor
was able to factor wholesale accounts receivables in the past. Changed circumstances in the future, however, may make such
an adjustment appropriate in a subsequent rate case.
53. Deleted.
54. As required by the Commission's rate-filing package, TCC functionalized its costs by assigning them to the various functions
TCC performs, such as transmission, distribution and T&D customer service.
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55. FERC Account 907 includes customer service and information expenses. It is appropriate to functionalize $53,490 of TCC's
test-year Account 907 costs to the T&D customer-service function rather than demand-side management (DSM) because they
were directly related to the supervision of customer-service activities.
56. FERC Account 303 is entitled Miscellaneous Intangible Plant. It is appropriate to disallow $916,000 in this account for a
software package because it relates to marketing in which a T&D utility like TCC need not engage.
57. FERC Account 303 also includes three software programs related to customer information and billing services (with a cost
of $9,510,439). TCC incorrectly assigned them to the distribution function, and they should instead be assigned to the T&D
customer-service function.
58. FERC Account 303 also contains the cost of several software programs used for plant accounting: the Tax Depreciation
& Normalization System, the General Ledger/Standard Account Structure System, and the Job Cost Accounting and Material
Management System. These accounting-related programs and costs should not be functionalized based on the amount of plant
investment by function. Instead, they should be directly assigned or functionalized using the number of accounting entries by
function because this method best represents the costs each function imposes on these accounting systems.
C. Return on Equity and Capital Structure
59. On April 30, 2004, TCC, TIEC, CPL, and Staff filed a non-unanimous stipulation (Return Stipulation) that settled two main
issues: return on equity (ROE) and capital structure.
60. The terms of the Return Stipulation are that: TCC's ROE be set at 10.125%; its capital structure be set at 60% debt and
40% equity; its rate of return on invested capital be set at 7.475%; and no penalty be applied to TCC's ROE for quality or
reliability of service.
61. The parties expressing neither opposition nor support for the Stipulation are OPC, the State, TLSC/TexasROSE, ARM,
Brazos, STEC, Garland, TXU, and Occidental Power Marketing, LP.
62. Cities and CCR object to the Return Stipulation.
63. The range of the ROE recommendations of the various expert witnesses in this case are as follows:
Witness Range
Mr. Stephen Hill 9.00% to 9.75%
Dr. Carol Szerszen 9.2% to 10.0%
Mr. Michael Gorman 9.2% to 10.5%
Dr. Charles Smaistrla 10.00% to 10.25%
Mr. Slade Cutter 9.22% to 10.23%
Mr. Paul Moul No range (12.000%)
64. The quality of TCC's service is generally adequate and does not warrant a reduction is TCC's ROE.
65. The stipulated return of 10.125% is more likely than not a reasonable return on TCC's equity.
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D. Affiliate Costs
66. TCC is a wholly owned subsidiary of AEP.
67. AEP Service Company (AEPSC), a wholly owned subsidiary of AEP, is a service company that provides a wide variety
of operations and support services to TCC. These services include transmission, distribution, customer services, supply-
chain shared services, general services, information technology, telecommunications, human resources, corporate relations,
regulatory, legal and public policy, customer-choice operations, financial services, interest and amortization, internal support,
research and development, risk management, treasury, cash management and investor relations.
68. During the test year, TCC engaged in transactions with AEPSC and other AEP affiliates.
69. AEP uses AEPSC and other affiliates to provide most of the personnel and services to the Applicant so that the Applicant
can serve its customers.
69A. The services provided to TCC by other affiliates consist of service payments, where the affiliate provides a service (such
as transmission) or convenience payments where the affiliate receives an invoice for costs shared by more than one entity and
bills the other entity for its share.
70. Relatively few employees that provide services through the Applicant are TCC employees.
71. TCC seeks to include in its costs of service $60,362,087 in affiliate expenses provided to TCC by AEPSC and $3,429,479
in affiliate expenses provided by other AEP affiliates of TCC, for a total of $63,791,566 in requested affiliate expenses for
the test year.
72. TCC has not presented evidence of either the amounts of increases actually requested for affiliate expenses or the level of
affiliate expenses currently included in the rates pursuant to the “black box” settlement of the UCOS case (Docket No. 22352).
Thus, the Commission is presented with only two sets of data: the level of affiliate expenses TCC requests in this case and the
amount requested in the UCOS case.
R9-R13. Deleted.
73-158. Withdrawn by ALJ in Remand PFD.
158A. On June 6, 2005, TCC and TIEC filed a joint motion to implement a non-unanimous stipulation (NUS) regarding affiliate
expenses.
158B. The parties expressing no opposition for the NUS are: Staff, Cities, Coalition of Commercial Ratepayers, Brazos Electric
Power Cooperative, Inc., Occidental Chemical, South Texas Electric Cooperative, Inc., the City of Garland, Alliance for Retail
Markets, and TXU Business Services.
158C. The State of Texas takes no position on the NUS.
158D. The NUS is opposed by OPC, TLSC/Texas ROSE, and CPL Retail Energy. These parties did not request a hearing on
the NUS.
158E. The NUS proposed a disallowance of $10,501,860 in AEPSC expenses. The stipulated disallowance consists of
$1,116,742 in AEPSC expenses that TCC previously agreed it would no longer seek recovery of, $5,496,028 of expenses in
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the AEPSC customer service support class of affiliate expenses, and $3,889,090 in the AEPSC distribution class of affiliate
expenses.
158F. The NUS proposes to allocate the stipulated disallowance as follows: $10,300,935 to the distribution function and
$200,925 to the transmission function.
158G. The stipulating parties agree that the remaining $53,289,706 in affiliate expenses, which consist of $49,860,227 in
affiliate expenses from AESPC and $3,429,479 in affiliate expenses from other affiliates, are reasonable and necessary, and
that the price is not higher than the price charged by the supplying affiliate to its other affiliates or divisions or to nonaffiliated
persons for the same item or class of items.
158H. The range of expert testimony regarding disallowances of affiliate costs are as follows:
Cities $16.6 million
OPC $13.4 million
CPL Retail $10.3 million
E. Debt Reacquisition Costs
159. TCC proposes to include in rate base $12,456,000 of restructuring costs related to debt refinancing. TCC also includes
an amount equal to 1/15th of that total amount ($861,712) in TCC's operating expenses. TCC proposes a 15-year amortization
for those costs.
160. The decision to reacquire the first mortgage bonds was driven by unbundling.
161. Deleted.
162. The debt reacquisition costs should be included in rate base and amortized over fifteen years, as required by Docket No.
22352, CPL's UCOS case.
F. Salary Adjustments and Related Taxes
163. Of the $679,344 in salary adjustments and related taxes proposed by the Applicant, $508,761 was proposed for post-test-
year raises for staff.
G. Incentive Compensation
164. The compensation packages that the Company offers its employees include a base payroll amount as well as an incentive-
compensation portion. Both portions are part of an overall compensation package that is designed to be competitive in the
marketplace and allow the Company to attract and retain qualified individuals as employees.
165. The Company requests to include the test-year level of incentive-compensation expense of $4,422,937 in cost of service.
166. The Company's incentives are set through two types of performance measures, financial and operational.
167. Thirty-four percent of the incentive-compensation expenses are for operational measures.
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168. To the extent that the Applicant's employees are given an incentive, their rewards are made with respect to the overall
performance of the holding company.
169. The financial measures are of more immediate benefit to shareholders, and the operating measures are of more immediate
benefit to ratepayers.
170. Incentives to achieve operational measures are necessary and reasonable to provide T&D utility services, but those to
achieve financial measures are not.
H. Pension Expense
171. The Company proposes to increase test-year pension expenses by $7,264,784 from $30,812.
172. The Company's proposed adjustment to the test-year amount of pension expenses is based on forecasts that are highly
dependent on changes in stock-market prices and market interest rates.
173. Future stock-market prices and market interest prices are not within the category of known and measurable changes.
I. Other-Post-Employment-Benefits
174. TCC requests approval of increased revenues to support an other-post-employment-benefits (OPEB) expense of
$5,239,235.
175. OPEB expenses in cost-of-service calculations are subject to P.U.C. SUBST. R. 25.231(b)(1)(H), which requires OPEB
expenses to be based on “actual payments made.”
176. The proposed OPEB expense item had been adjusted to reflect actuarial projections for the 2004-2005 rate year, an amount
that had not been funded and that did not represent actual payments made.
J. Group Insurance Expense
177. The Company's requested amount of group-insurance expense, $4,649,872, represents the actuarial estimate of the amount
that the Company will contribute into its employee group insurance trust fund during the rate year.
178. The requested amount is comprised of the test-year actual cost of $3,741,039 and a projected increase of $908,833.
179. The Applicant's test-year group-insurance expense is reasonable and necessary.
179A. The Applicant's proposed post-test-year group-insurance expense is based on an actuarial study; therefore, this does not
qualify as a known and measurable increase to a test-year expense.
K. Catastrophe Reserve
180. The Applicant's proposed increase in its catastrophe-loss reserve from approximately $5.4 million to $13.5 million is based
on a projected increase in storm damage.
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181. The current upper limit of $5,353,563 for the Catastrophic Reserve is not adequate to cover losses from hurricanes and
other storms.
181A. TCC should fund the catastrophe reserve at $900,000 annually for 10 years as part of the rate-base expense until the
catastrophe reserve reaches its maximum approved level of $9,000,000.
L. DSM Costs
182. The Applicant's test-year energy-efficiency costs were $6,082,450, which should be included in cost of service.
M. Gain on Sale of the AREP
183. When customer choice began in Texas on January 1, 2002, AEP formed a subsidiary, Mutual Energy CPL L.P, to be the
affiliated retail electric provider (AREP), and the former Central Power and Light Co. became TCC.
184. On December 23, 2002, AEP sold the AREP to Centrica.
185. The sale involved the sale of retail assets and not transmission or distribution assets.
186. AEP's gain on the sale of the AREP should not be used to reduce TCC's T&D rates.
N. Bad-Debt Expense
187. The Applicant proposes to create a deferral account in which the Applicant would accrue bad debt arising from future REP
bankruptcies. The Applicant would use the deferral account in which to record any bad debt as a regulatory asset.
188. No current provision of law would permit recovery of bad debts through the proposed method.
O. Ad Valorem Taxes
189. TCC's test-year ad valorem tax expense was $18.3 million.
190. The Company's request to increase its ad valorem tax expense included in its cost of service by $2.5 million is reasonable.
191. This amount was calculated by applying the effective ad valorem tax rate during the test year to the Company's end-of-
test-year property balances.
P. Consolidated Income Taxes
192. TCC is a member of an affiliated group eligible to file a consolidated tax return.
193. AEP files annual consolidated federal income tax returns on behalf of itself and its various subsidiaries.
194. A consolidated tax savings adjustment should be made based on the value of the tax shield the utility provides to the parent
company and its nonregulated affiliates.
195. Withdrawn by ALJ in Remand PFD.
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196. Withdrawn by ALJ in Remand PFD.
R3. It is reasonable to use the interest-credit methodology to calculate TCC's consolidated federal-income-tax-savings
adjustment.
R4. An additional adjustment should be made to reflect the savings due to generation assets that are no longer part of the
transmission and distribution (T&D) utility.
R5. Using the rate-base percentage assigned to the T&D functions in effect for each of the 15 years prior to 2002 is an appropriate
method for functionally assigning consolidated tax savings.
R6. The percentages of the T&D functions for each of the 15 years prior to 2002 produces an allocation of 23.1% to T&D,
resulting in an adjustment of $1,509,656.
R7. Because the adjustment is a direct adjustment to federal income taxes, it must be grossed up to reflect the full effect on
revenue requirement of the adjustment.
R8. The combined effect of the consolidated tax-savings adjustment and the associated gross-up is 1.53846 times the $1,509,656
adjustment for an amount of $2,322,545 to be deducted from federal-income-tax expense.
Q. Distribution Operations & Maintenance (O&M) Expense Adjustments
197. When Customer Choice went into effect and costs were functionalized, TCC included three adjustments that it seeks to
include in its cost of service.
198. The $1.5 million adjustment to correct a mis-entry and the $1.6 million adjustment to correct a building-service posting
should be included in TCC's cost of T&D service.
199. The third adjustment of $3.4 million to reflect changed salvage value for vehicles is only supported to the extent of $2.4
million, which lower amount should be included in TCC's cost of service.
200. Of the $2.4 million adjusted amount sought by the Applicant for this expense, $1.0 million of the decreases were attributed
“to various other distribution O&M accounts.”
201. The evidence shows that $1.0 million represents vehicle maintenance expense, a cost of TCC's service.
R. Distribution Accounting and General (A&G) Expense Adjustments
202. The Applicant's $58.0 million proposed distribution A&G expenses are reasonable and a necessary cost of TCC's T&D
service.
R14. The A&G Expense associated with the distribution function is $58,012,772, including twenty categories of adjustments.
R15. TCC's evidence supports the foregoing proposed A&G expenses, including the adjustments, as just and reasonable, with
two exceptions.
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R16. The two exceptions are Adjustment No. 1, the pension-expense increase of $6,258,658, and Adjustment No. 16, the
merger-related revenue requirement-credit of $7,496,000.
S. Depreciation Expense
203. Withdrawn by ALJ in Remand PFD.
R17. TCC's adjusted end-of-test-year depreciation expense was $64,488,771.
R18. TCC has agreed to and will establish a depreciation reserve by plant account and maintain the reserve by plant account.
T. Decommissioning Expense
204. TCC's share of the cost to decommission the South Texas Project (STP) will be recovered with an annual contribution of
$7.58 million from TCC, which should be included in TCC's cost of service.
205. This amount includes the 10% contingency factor included in the Commission's decommissioning rule.
206. TCC's request to include an additional $580,000 in its cost of service for STP decommissioning for a total of $8.16 million
should be denied.
206A. The amount of decommissioning costs included in the cost of service for Units 1 and 2 of the South Texas Project is
$3,726,662 and $3,856,079, respectively, for the Texas jurisdiction.
206B. The assumptions used in determining the amount of decommissioning costs included in the cost of service for Units 1
and 2 are as follows:
a. The after-tax rates of return assumed to be earned by the amounts collected for decommissioning are shown in the following
table:
Unit 1 Unit 2
Years Rate of Return Years Rate of Return
2003-2025 6.282% 2003-2027 6.282%
2026-2031 4.713% 2028-2045 4.713%
2032-2035 2.977% 2046-2046 2.977%
2036-2037 2.283% 2047-2048 2.283%
b. The after-tax rates of return assumed to be earned by the decommissioning funds were calculated using the 20% tax rate
applicable to qualified decommissioning funds.
c. The proposed method of decommissioning for Units 1 and 2 is DECON as defined by the Nuclear Regulatory Commission
(NRC).
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d. The total estimated cost of decommissioning Units 1 and 2 in 1998 dollars is $515.5 million for Unit 1 and $616.3 million
for Unit 2. TCC's portion of those costs is $125,070,410 for Unit 1 and $150,611,711 for Unit 2.
e. TCC's estimated cost of decommissioning for Units 1 and 2 in future dollars is $463,992,921 for Unit 1 and $633,771,877
for Unit 2.
f. The escalation rates used to convert the current-dollars estimated decommissioning costs to future-dollars estimated
decommissioning costs vary by year and average 4.2% until the time of the last projected payment for decommissioning.
g. Decommissioning costs included in the cost of service total $7,582,741, as detailed in finding of fact 206A, above,
commencing with the effective date of the rates authorized by this Order, until changed by a future order. For purposes of
determining the amount of funds available for decommissioning each individual unit, collection of each individual unit's costs
continues through the license expiration dates of each respective unit.
h. The dates of NRC license expiration are August 20, 2027 for Unit 1 and December 15, 2028 for Unit 2.
i. The amount of decommissioning costs included in TCC's cost of service is based upon the 1999 decommissioning study
prepared by TLG. Services, Inc.
U. Third Party Contract Margin Sharing Proposal
207. Through its associated business development (ABD) operations, the Applicant provides O&M services and major
transmission construction services to third-party clients, which is an “other service” under P.U.C. Subst. R. 25.342(f)(1)(D).
208. The Applicant seeks a good-cause exception to the provisions of the “other services” rule, P.U.C. Subst. R. 25.342(f)
(1)(D)(ii)(III), that requires all revenue from an “other service” to be credited so as to reduce a utility's cost of service. The
exception would permit the Applicant to contribute half-instead of all-of the margins received as part of the Applicant's ABD
program to the rate base calculation.
209. It is not reasonable to grant TCC's request and the full amount of ABD's test-year margins should be credited to TCC's
cost of service, reducing TCC's proposal by $2.7 million.
V. Rate-Case Expenses
210. Deleted.
211. Deleted.
212. Deleted.
213. Deleted.
214. Deleted.
215. Deleted.
216. Deleted.
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W. Miscellaneous Issues
217. At the time of this rate application, TCC was in the process of selling its generating assets. TCC's business separation plan
required that the generating assets be transferred to an affiliate corporation. TCC's request to sell the generating assets directly
rather than through an affiliate corporation is unopposed and is reasonable.
X. Quality of Service
218. Deleted.
Y. Reliability of Service
219. Deleted.
Z. Rate Design
220. A cost-of-service study is used to allocate a utility's cost of service to its various customer classes based upon each class's
cost responsibility and to determine each class's rates.
221. TCC's revenue requirement was attributed to the various classes by classifying each cost by function, including production
(for nuclear decommissioning), transmission, distribution, customer service (including meter reading, billing and collection,
and customer information) and administrative and general costs; classifying the costs of each as demand, energy, or customer
costs; and by allocating those costs among the customer classes.
AA. Load Data
222. TCC used ERCOT load-profile shapes and TCC actual consumption data to develop the demands used in its cost-of-
service study.
223. The ERCOT load-profile shapes used by TCC are the load profiles used by ERCOT to settle the market in TCC's service
area on a 15-minute-by-15-minute basis.
224. TCC did not have sufficient time to derive its own load data because the final order in its UCOS case was issued in April
2001 and customers were placed in their new classes in January 2002.
225. It takes 18 to 24 months to design load-research samples, select the samples, place recording meters in the field, and to
collect and analyze the data.
226. In March 2002, the Commission initiated Project No. 25516, which concluded in March 2003, the purpose of which was
to ascertain and allocate load-research responsibilities in the newly opened market.
227. TCC was not imprudent in failing to have its own post-choice research data available for use in its cost-of-service study.
228. The load data and methodology used by TCC were appropriate for use in its cost-of-service study.
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BB. Cost of Service Allocations
229. TCC relied on a July 31, 1999 study, which it used in its UCOS case, to determine the distribution-function cost of service
in this proceeding.
230. The study categorizes costs as either customer or demand and separates demand-related plant between primary voltage
and secondary voltage.
231. The cost of the distribution system, including poles, transformers, and conductors, does not generally vary.
232. TCC properly allocated the costs of the distribution function found in FERC Accounts 364, 365, 367, and 368.
233. In Application of Central Power and Light Company for Authority to Change Rates, Docket No. 14965, Second Order on
Rehearing (Oct. 15, 1997), Central Power and Light Co.'s last rate case, the Commission approved the use of the probability
of dispatch methodology to allocate costs.
234. In Docket No. 22352, TCC's UCOS case, nuclear-decommissioning costs were allocated based on a settled factor, the
Joint Recommendation on Reserve Spread.
235. Nuclear-decommissioning costs are not stranded costs.
236. TCC properly allocated nuclear-decommissioning costs using an average and excess, four coincident peak (A&E/4CP)
allocator because its use is consistent with Ordering Paragraph No. 12 in Docket No. 14965.
237. Energy-efficiency costs are appropriately allocated on the basis of demand.
237A. Debt-reacquisition costs are appropriately allocated on the basis of the plant-distribution allocator.
238. The non-DSM supervisory costs originally included in Account 907 (Supervision) are properly allocated on the basis of
labor consistent with the allocation of other non-DSM supervisory costs.
239. TCC appropriately allocated the costs contained in Account 903 (Customer Billing and Record) using weightings because
the time associated with billing IDR-metered customers substantially exceeds the time associated with billing non IDR-metered
costs, thereby substantially increasing the costs associated with billing IDR-metered customers.
240. The Company has provided sufficient justification of its current installed meter costs as the basis for determining the
allocation of meter costs among customer classes.
241. TCC appropriately developed the Account 370 cost allocator using information on meter costs from the competitive
metering-credit-docket and information on the primary and transmission classes from TCC's UCOS docket that was not included
in the competitive-metering-credit docket.
242. TCC should use $0.935 per kW as the Access Fee for City Public Service of San Antonio (CPS) because $0.935 per kW
is the current approved rate. Because CPS' application to change its wholesale access fee has been resolved, TCC may adjust
its retail rates through the transmission cost recovery factor mechanism.
243. TCC unnecessarily adjusted the 4CP allocator used in allocating the ERCOT TCOS revenue requirement; the unadjusted
4CP allocator should be used.
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244. The allocation of individual expense adjustments should be made based on the original allocation that TCC has used or
each expense in the cost of service models. On page 12 of 14 in TCC's schedule II-I-I, the $1,868,116 (costs associated with
catastrophic reserve) and $1,330,334 (costs associated with rate-case expenses) are recorded on two lines and are allocated
to different functions based on different allocations. To correctly reduce these expenses in the cost-of-service model, these
expenses should be adjusted differently, based on their original allocations, and not based on a composite allocator.
245. An adjustment of $2,610 related to depreciation expense associated with the $180,000 plant adjustment for the Coleto
Creek substation investment should be made in Account 353 (Station) where the $180,000 adjustment is made.
246. TCC has corrected the error concerning the Taxable Income Allocator.
247. The accounting schedules do not reflect functionalization changes resulting from the cost-of-service functionalization.
TCC's cost-of-service study more accurately reflects the functionalized costs.
248. The allocation factors that are used to allocate certain distribution costs and are derived from costs included in a number of
FERC accounts including FERC Account 565 should be corrected to exclude the costs (the ERCOT TCOS revenue requirement)
included in FERC Account 565. The ERCOT TCOS revenue requirement is not part of the distribution costs and should not be
included in the development of the allocators used for allocating distribution costs.
249. Allocation Factors Nos. 57, 68, and 103 as corrected by Staff should be used in determining class revenue allocations.
CC. Municipal-Franchise Fees
250. Municipalities charge utilities franchise fees for the use of their streets, alleys, rights-of-way, and other property, which
benefits all ratepayers.
251. TCC's proposal to allocate municipal fees to all customers is not appropriate. The cost of municipal-franchise fees should
be directly allocated to customer classes based upon the number of kWh delivered within the municipal boundaries.
252. TCC's proposal to collect the cost of municipal-franchise fees from all classes in TCC's system under a spread-collection
method is appropriate.
253. Municipal franchise fees should be collected through base rates and not through a separate rider.
254. TCC's proposal to implement the Municipal Franchise Fee Adjustment Rider should be rejected as it would create confusion
with potentially over 100 different rates resulting.
255. Simple rates and uniform customer classifications promote competition. Having different rates in each of the municipalities
in TCC's service territory is contrary to the Commission's desire for uniform, simple rates.
DD. Rate-Case Expenses
256. It is appropriate to surcharge all rate-case expenses to be collected from all customers over three years.
EE. Riders
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257. A utility cannot increase its rates unless it demonstrates that its total revenues are insufficient to recover the totality of
its costs, plus a reasonable rate of return. Singling out certain expenses in order to guarantee dollar-for-dollar cost recovery
is piecemeal ratemaking.
258. TCC's proposed energy-efficiency cost-recovery rider with its three-year true-up provision lacks merit because it could
lead to inflated rates and discourage cost control.
259. The proposed nuclear decommissioning rider (NDC Rider) should be accepted based on P.U.C. SUBST. R. 25.303.
260. CPL Retail's proposed rider for catastrophe reserve is unnecessary.
261. All of the riders requested by TCC and CPL Retail, except for the NDC Rider, should be denied to avoid over-recovery
and piecemeal ratemaking. The costs associated with the proposed riders can be adequately recovered through base rates.
FF. Discretionary Service Charges
262. The Account History Fee was erroneously included in Schedule IV-J-2 and should not be approved.
263. The proposed inaccessible Meter Fee, along with its associated revenue credit of $1,229,223, should be removed from
discretionary services.
264. The tariff language of the Service Call Fee should be modified to clarify that customers will not be assessed the fee when
the customer perceives a safety hazard or if the problem addressed is TCC's responsibility.
265. The Copy Fee and Special Products/Service Fee is not a substitute for the Account History Fee and is being appropriately
billed to those who require the service.
266. Withdrawn by ALJ in Remand PFD.
267. Withdrawn by ALJ in Remand PFD.
268. Withdrawn by ALJ in Remand PFD.
R19. TCC provided sufficient evidence for its loading factor of 60.18%.
R20. TCC provided sufficient evidence for its supervisor labor charges.
R21. TCC provided sufficient evidence showing that the employees in questions will receive a salary increase of 2.5%.
R22. The amounts for the Connect Fee, Service Reconnection Fee, Meter Reading Fee, Priority Connect Fee, Priority Disconnect
Fee, Dispatched Order Fee, and the Priority Dispatched Order Fee are reasonable at the levels proposed by TCC.
R23. Deleted.
R24. Deleted.
269. Deleted.
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GG. Lighting
270. TCC's lighting charges result in a double-recovery of lighting maintenance expense. The bulb-replacement portion should
be removed from the maintenance component of the fixed-charge rate calculation for lighting.
271. The cost-of-capital component of the fixed-rate charge calculation should be adjusted to reflect the cost of capital found
reasonable by the Commission in this proceeding.
272. TCC understated non-roadway lighting-facilities revenue by $298,677 when it left out revenue from the 175-Watt mercury-
vapor fixture type. This amount should be credited to lighting customers.
273. Lighting service is not metered and when a bulb goes out, TCC has charged lighting customers for service that is not
provided.
274. In the settlement of Docket No. 22352, TCC agreed to continue to provide non-roadway lighting service. In section 7(A)
(2) of the ISA, TCC agreed to replace 95% of burned-out security and street lighting bulbs within 72 hours.
275. TCC's proposed a tariff change to allow five days for replacement of streetlights and fifteen days for non-roadway lighting
is inconsistent with section 7(A)(2) of the ISA standard agreed to by TCC and should be rejected.
276. TCC's use of average dusk-to-dawn burn time to estimate usage takes into consideration abnormalities associated with
lighting KWh usage.
277. TCC's tariffs should be amended to state that a credit will be provided to the customer if TCC fails to restore a bulb within
three working days after official notice of the outage from the customer to ensure that lighting customers are not charged for
service when the bulbs are burned out.
HH. Revenue Allocations
278. TCC's proposed allocation of $4,520,746 for Other Revenue should not be adopted. The revenue should be allocated in
the same manner that TCC allocates its investment in poles, towers, and fixtures, because the method more closely tracks the
method used to allocate the underlying investment used to generate the revenue.
II. Gradualism
279. In prior rate cases the Commission has moderated the impact of new rates with gradualism to avoid rate shock
280. Gradualism is not an abandoned policy.
281. Deleted.
282. A gradualism constraint should be applied to the total system revenue requirement, not on a function-by-function basis.
283. If TCC's rates are changed, then the T&D rates charged to each customer class should move to cost of service. Therefore,
the Commission declines to adopt gradualism in this case.
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IV. Conclusions of Law
1. TCC is an electric utility as defined by § 31.002 of the Public Utility Regulatory Act (PURA), TEX. UTIL. CODE ANN.,
and therefore it is subject to the Commission's jurisdiction under §§ 32.001, 33.051, and 36.102.
2. TCC is a T&D utility as defined in PURA § 31.002(19).
3. SOAH has jurisdiction over all matters relating to the conduct of the hearing in this case, including the preparation of a
Proposal for Decision pursuant to PURA § 14.053 and TEX. GOV'T CODE ANN. § 2003.049(b).
4. Each municipality in TCC's service area that has not ceded jurisdiction to the Commission has jurisdiction over the application
to the extent that the application seeks to change rates for distribution services within each municipality pursuant to PURA
§ 33.001.
5. TCC provided adequate notice of this proceeding in compliance with P.U.C. PROC. R. 22.55.
6. The effective date of any change approved in this case was extended pursuant to P.U.C. PROC. R. 22.33(c), with the agreement
of applicant, and P.U.C. SUBST. R. 25.241(i).
7. TCC met its burden of proof with regard to sections 3.F.(3)(a)(ii) of the ISA, and TCC's proposal to increase rates by
$22,513,000 for merger expenses is approved.
8. The revenue-requirement credit applies since the Applicant initiated the filing of the rate case.
9. The revenue-requirement credit is determined by a simple counting of each of the years in the six-year period after the
effective date of the merger.
10. The revenue-requirement credit is the amount listed in Year 3 of Attachment E of the ISA, $7,496,000.
11. TCC's proposed addition to historical test-year rate base does not comprise at least 10% of its requested rate base, as required
by P.U.C. SUBST. R. 25.231(c)(2)(F)(i)(II) for a post-test-year adjustment.
12. TCC failed to appropriately take into account all of the attendant impacts associated with plant in service, as required by
P.U.C. SUBST. R. 25.231(c)(2)(F)(i)(IV) for a post-test-year adjustment, including adjustments to revenues resulting from
customer growth beyond the end of the test year and accumulated depreciation and accumulated deferred income tax associated
with the plant additions.
13. The design changes to Coleto Creek substation in the amount of $2,836,482 should be included in TCC's rate base because
the improvements benefit the ratepayers and are used to serve the ratepayers as P.U.C. SUBST. R. 25.231(c)(2)(F) requires
for a post-test-year adjustment.
13A. Electric utilities should be encouraged to cooperate with ERCOT and make reasonable modifications to Commission-
approved plans for facility construction when doing so would avoid costly facility duplication in the foreseeable future.
14. Any stipulation, and in particular, the figure for cost of capital, need only fall within the range of expert testimony and
be supported by a preponderance of the evidence. Central Power and Light Company/Cities of Alice v. Public Utility Comm'n
of Texas, 36 S.W.3d 547, 559 (Tex. App.-Austin 2000, pet. denied); City of El Paso v. Public Utility Comm'n of Texas, 883
S.W.2d 179, 183 (Tex. 1994).
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15. In Generic Issues Associated with Applications for Approval of Unbundled Cost of Service Rate Pursuant to PURA §
39.201 and Public Utility Commission Substantive Rule § 25.344, Docket No. 22344, Order No. 42 at 11 (Dec. 22, 2000), the
Commission determined that a capital structure consisting of 60% debt and 40% equity was appropriate for T&D utilities.
16. In Docket No. 22344, Order No. 42 at 9-10, the Commission concluded there is a close correlation between return on equity
and capital structure.
17. Although § 7(A)(1) of the ISA may require TCC to complete 95% of the requests for new service within one day, the ISA
does not require TCC to report whether it complied with the standard.
18. PURA § 38.005(c) does not require utilities to maintain certain levels of training or personnel in order to comply with
service and reliability standards.
19. Section 7.A.(2) of the ISA requiring TCC to replace 95% of security and street lighting outages within 72 hours does not
contain a penalty.
20. The Commission may only allow as capital cost or as expense a payment to an affiliate for the cost of a service, property,
right, or other item; or interest expense to the extent that the Commission finds the payment is reasonable and necessary for
each item or class of items. PURA § 36.058(a) and (b).
21. To find that such an affiliate payment is reasonable and necessary, the Commission must:
a. specifically find each allowed item or class of items is reasonable and necessary; and
b. find that the price to the electric utility is not higher than the prices charged by the supplying affiliate to its other affiliates or
divisions or to a non-affiliated person for the same item or class of items. PURA § 36.058(c).
22. In making a finding regarding an affiliate transaction, the Commission must:
a. determine the extent to which the conditions and circumstances of that transaction are reasonably comparable relative to
quantity, terms, date of contract, and place of delivery; and
b. allow for appropriate differences based on that determination. PURA § 36.058(d).
23. The Commission must:
a. carefully scrutinize all payments made by a utility to an affiliate, and
b. disallow all such payments unless the utility showed that the payments met the statutory requirements. Railroad Commission
of Texas v. Rio Grande Valley Gas Company, 683 S.W.2d 783 (Tex. App.-Austin 1984, no writ).
24. The specific provisions of PURA-and not the SEC-approved allocation factors-control the Commission's authority, and the
statutory presumption is that payments made to affiliates are not allowed. Central Power and Light Co./Cities of Alice v. Public
Utility Comm'n of Texas, 36 S.W.3d at 563.
25. The legislature has prohibited the Commission from considering for ratemaking purposes an expenditure “for legislative
advocacy, made directly or indirectly, including legislative advocacy expenses in trade association dues.” PURA § 36.062(1).
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25A. $53,289,706 of TCC's affiliate expenses are reasonable and necessary, and the price charged to TCC is not higher than
the price charged by the supplying affiliate to its other affiliates or divisions or to nonaffiliated persons for the same item or
class of items.
25B. To be approved by the Commission, a non-unanimous stipulation must comply with applicable law; be just, reasonable,
and in the public interest; and be supported by a preponderance of the record evidence. City of El Paso v. Public Util. Comm'n,
883 S.W.2d 179, 183 (Tex. 1994).
25C. The non-unanimous stipulation providing for a disallowance of $10.5 million in affiliate expenses is just, reasonable, and
in the public interest, and is supported by a preponderance of the record evidence.
26. Deleted.
27. Deleted.
28. Deleted.
29. Deleted.
30. The final order in Docket No. 22352, including finding of fact 98 and the reservation clause, allows the intervenors to
challenge only the reasonableness of the amount of debt reacquisition charges incurred, and the reasonableness of the time
period of their amortization.
31. The final order in Docket No. 22352 requires that debt-restructuring expenses incurred as a result of the mandate in PURA to
separate business functions be recovered through transmission and distribution rates, subject to the specific challenges described
in conclusion of law 30, above.
32. The Commission has discretion in deciding whether to allow post-test-year adjustments for known and measurable changes.
Central Power & Light Company v. Public Utility Comm'n of Texas, 36 S.W.3d 547, 563 (Tex. App.-Austin 2000, pet. denied).
33. “Changes occurring outside the test period, if known, may be taken into consideration by the regulatory agency … to make
the test year data as representative as possible of the cost situation that is apt to prevail in the future.” Suburban Utility Corp.
v. Public Utility Comm'n, 652 S.W.2d 358, 366 (Tex. 1983).
34. Cost of service expenses in public utility ratemaking cases must be limited to “amounts actually realized or which can be
anticipated with reasonable certainty.” Suburban Utility Corp., 652 S.W.2d at 362.
35. Unlike most other cost-of-service items that are subject to known and measurable adjustments, OPEB expenses in cost-of-
service calculations are subject to a Commission rule that requires OPEB expenses to be based on “actual payments made.”
P.U.C. SUBST. R. 25.231(b)(1)(H)(i).
36. The Applicant's proposed inclusion of non-historical amounts in its OPEB expense item is not permitted under the
Commission's rules. Nothing in the provisions of P.U.C. SUBST. R. 25.231(b)(1)(H)(v) may be read to create an exception to
the “actual payments made” requirement of P.U.C. SUBST. R. 25.231(b)(1)(H)(i).
37. P.U.C. SUBST. R. 25.231(b) establishes that in computing an electric utility's allowable expenses, the only measurement
to be considered is the electric utility's historical test-year expenses as adjusted for known and measurable changes.
38. The Applicant is authorized to deduct its known and measurable expenses for the test year alone.
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APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784...
39. The Commission established four categories of services that could be offered by a T&D utility: system services, discretionary
services, petitioned services, and other services. P.U.C. SUBST. R. 25.342(f)(1).
40. A utility that provides a service that does not come within the definition of any of the first three categories may seek to
treat that offering as an “other” service.
41. An offering may properly be characterized as an “other” service; however, only if the service satisfies specific provisions
of the Commission's rule. “Other services” are “limited to those services that: (I) maximize the value of [T&D] system service
facilities, and (II) are provided without additional personnel and facilities other than those essential to the provision of [T&D]
system services.” P.U.C. SUBST. R. 25.342(f)(1)(D)(i)(I) and (II). If the offering satisfies that definition, then the utility is
also required to “credit all revenues received from the offering of this service during the test year after known and measurable
adjustments are made to lower the revenue requirement of the transmission and distribution utility on which the rates are based.”
42. Whatever its intention in approving the creation of the “other service” category, the Commission made clear that all revenues-
and not net revenues-should be credited to the cost-of- service calculation. If, however, the costs and revenues of providing the
other service are not included in the calculation of rates, then the test-year margins (revenues minus costs) received from the
service should be credited to the cost-of-service calculation.
43. Deleted.
44. The Company failed to meet the legal requirements to recover $508,761 of the $679,344 in proposed salary adjustments
and related taxes.
45. The Applicant met its burden of proof with regard to incentive compensation but only with respect to that portion relating
to Operational Measures; the amount includible in the cost of service is 34% of $4.42 million.
46. TCC met its burden of proof with regard to pension expenses includible in the cost of service in the amount of $30,812.
47. The Applicant failed to meet its burden of proof on its proposed expense item for OPEB; the proposed expense item is not
includible in the cost of service.
48. The group-insurance expense includible in the cost of service is the test-year actual cost of $3,741,039.
48A. The catastrophe-reserve expense includible in the cost of service is $900,000 annually for ten years until the catastrophe
reserve reaches its maximum approved level of $9,000,000.
49. The Applicant proved DSM costs includible in the cost of service in the amount of $6,082,450.
50. PURA § 39.051(g), which states that, “[t]ransactions by electric utilities involving sales, transfers, or other disposition
of assets to accomplish the purposes of this section are not subject to Section 14.101, 35.034, or 35.035,” does not limit the
preclusions to one transaction.
51. $20,699,131 should be included in TCC's cost of service for ad valorem taxes in conformance with prior Commission
precedent.
52. According to PURA § 36.060, an electric utility's income taxes shall be computed as though a consolidated return had been
filed and the utility had realized its fair share of the savings resulting from that return, if the utility is a member of an affiliated
group eligible to file a consolidated income-tax return, and it is advantageous to the utility to do so.
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APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784...
53. Withdrawn by ALJ in Remand PFD.
R1. TCC's federal-income-tax-expense in cost of service should be reduced by $2,322,545 to reflect TCC's share of AEP's
consolidated tax savings.
54. TCC did not prove a need to include a bad-debt deferral account as part of an approved accounting procedure.
55. The distribution O&M-expense adjustments proposed by TCC are appropriate and should be approved.
56. TCC's proposed negative net salvage rates are reasonable. TCC's amended proposed depreciation expense should be adjusted
to reflect the average service lives developed by Cities' witness Nancy Heller Hughes.
57. The possibility of decommissioning-expense under-funding is currently accounted for in the 10% contingency in P.U.C.
SUBST. R. 25.231(b)(1)(F)(i).
58. Deleted.
59. The Applicant should not be granted a good-cause exception to P.U.C. SUBST. R. 25.342(f)(1)(D)(ii)(III), and should be
required to credit to customers the full amount of the test-year margin of $2,708,122 resulting from TCC's transmission and
construction-related ABD services.
60. PURA § 36.052 requires the Commission to consider “the quality of the utility's services” and “the quality of the utility's
management” in establishing a reasonable return on invested capital as part of the PUC's “establishing an electric utility's rates.”
61. Deleted.
62. Deleted.
63. TCC's use of the A&E/4CP allocator to allocate nuclear-decommissioning costs was appropriate pursuant to P.U.C. SUBST.
R. 25.344(h)(2)(E), because the Commission indicated a developing preference for the allocator in Docket No. 14965.
64. Based on PURA § 39.905(a)(3), which mandates energy-efficiency programs to achieve reductions of at least 10% of the
electric utility's annual growth in demand, these program costs should be allocated on a demand basis.
65. PURA § 33.008 was enacted to maintain the same level of revenues for municipalities after the introduction of Customer
Choice.
66. PURA § 33.008(b) requires that the municipal franchise fees be based on the number of kWh delivered within the municipal
boundaries in order to maintain sufficient revenue levels for municipalities.
67. To meet the revenue requirement the municipal franchise fees should be allocated using a direct allocation based on a cents
per kWh allocator within the municipalities.
68. Collecting the municipal franchise fees under the spread collection proposed by TCC is appropriate pursuant to PURA §
33.008(c), which requires that municipal franchise fees be collected from every retail customer served by the electric utility
69. PURA § 36.201 prohibits the Commission from establishing a rider that authorizes an electric utility to automatically adjust
and pass through to the utility's consumers those costs that are incurred.
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APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784...
70. Pursuant to P.U.C. SUBST. R. 25.181, energy-efficiency-program costs should not be recovered through an automatic
adjustment, such as a separate rider.
71. An order amending P.U.C. SUBST. R. 25.303 was adopted by the Commission on October 6, 2004 and allows a separate
nonbypassable charge for nuclear-decommissioning costs.
72. Deleted.
73. Deleted.
74. Deleted.
V. Ordering Paragraphs
1. The proposal for decision prepared by the Administrative Law Judges of the State Office of Administrative Law Hearings
is adopted to the extent consistent with this Order.
2. TCC's application is granted to the extent provided in this Order.
3. Before TCC's next rate case, TCC shall develop new load data reflecting its actual experience, and a new distribution field
study.
4. TCC shall file tariff sheets consistent with this Order (compliance tariff) no later than 20 days after receipt of this Order. The
compliance tariff, and all filings related to it, shall be filed in Tariff Control Number 31271, and shall be styled: Compliance
Tariff Pursuant to Final Order in P.U.C. Docket No. 28840, (Application of AEP Texas Central Company for Authority to
Change Rates). The filing shall include a transmittal letter stating that the tariffs attached are in compliance with the order,
giving the docket number, date of the order, a list of tariff sheets filed, and any other necessary information. The timetable
for review of the compliance tariff shall be established by the P.U.C. ALJ assigned to the tariff. In the event any sheets are
modified or rejected, the applicant shall file proposed revisions to those sheets in accordance with the P.U.C. ALJ's notice. The
effective date of the tariff shall be as determined in the written notice of approval by the P.U.C. ALJ. All subsequent filings
in connection with the compliance tariff (i.e., requests for extensions, textual corrections, revisions) shall be filed in the same
Tariff Control Number provided above, and styled as set forth above. After issuance of the final order, no further filings other
than those pertaining to a motion for rehearing shall be made in this Docket.
5. The determination of the reasonableness and necessity of rate case expenses is severed into Docket No. 31433, Proceeding
to Consider Rate Case Expenses Severed from Docket No. 28840 (Application of AEP Texas Central Company for Authority
to Change Rates).
6. The entry of an order consistent with the Stipulations does not indicate the Commission's endorsement or approval of any
principle or methodology that may underlie the Stipulations. Neither shall the entry of an order be regarded as binding precedent
as to the appropriateness of any principle underlying the Stipulations.
7. All other motions, request for entry of specific findings of fact and conclusions of law, and any other requests for general
or specific relief, if not expressly granted herein, are denied.
SIGNED AT AUSTIN, TEXAS the _____ day of _______________ 2005.
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APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784...
Footnotes
1 See Open Meeting Tr. at 159-60 (Jan. 13, 2005).
2 Application of Central and Southwest Corporation & American Electric Power Company, Inc. Regarding Proposed Business
Combination, Docket No. 19265 (Nov. 18, 1999).
3 Docket No. 19265, ISA at Section 3.F.(1).
4 Direct Testimony of Michael Heyeck, TCC Ex. 6 at 9-12.
5 See Rebuttal Testimony of David Carpenter, TCC Ex. 66 at 28-31.
6 See Cities' Brief on Remand Issues at 3 (Mar. 24, 2005); CCR's Post-Hearing Brief on Merger Savings and Expenses at 3 (Mar.
24, 2005).
7 See, e.g., Direct Testimony of Michael Arndt, Cities Ex. 2 at 15; Direct Testimony of Ellen Blumenthal, CCR Ex.1 at 11-12.
8 See Docket No. 19265, Order (Nov. 18, 1999); Proposal for Decision at 10 (Oct. 1, 1999).
9 See SOAH Hearing Tr. at 240; Commission Hearing Tr. at 46-47; see also Direct Testimony of Thomas J. Flaherty in Docket No.
19265, CCR Ex.12 at 69.
10 Rebuttal Testimony of Mark G. Bailey, TCC Ex. 72 at 13.
11 Id. at 14.
12 Id.; SOAH Hearing Tr. at 2668.
13 Bailey Rebuttal at 14.
14 Id. at 14-15.
15 See Letter from John Williams, Attorney for AEP Texas Central Company, to Tammy Cooper, PUC, Regarding Depreciation Expense
Adjustment (Jul. 29, 2005).
16 PFD at 34.
17 Id. at 11.
18 TCC Ex. 83 at 10.
19 PFD at 71.
20 Id. at 70.
21 See PFD at 72.
22 Public Utility Regulatory Act, TEX. UTIL. CODE ANN. §§ 11.001-64.158 (Vernon 1998 & Supp. 2005) (PURA).
23 PURA § 36.058(b), (c)(1).
24 See Central Power and Light Company/City of Alice et al. v Public Utility Commission of Texas, 36 S.W.3d 547, 567 (Holding that
the Commission can disallow affiliate costs for failing to satisfy the requirements of PURA § 36.058(c)(2)); see also PURA § 36.006.
25 Second Order on Remand at 2 (Aug. 25, 2004).
26 Remand PFD at 11-12 (emphasis in original; footnote omitted).
27 Id. at 12.
28 Joint Motion for Implementation of Stipulation and Agreed Resolution Regarding Affiliate Expense Issues Based on the Evidentiary
Record (Jun. 6, 2005).
29 The following parties did not oppose the NUS: Staff, Cities, Coalition of Commercial Ratepayers, Brazos Electric Power Cooperative,
Inc., Occidental Chemical, South Texas Electric Cooperative, Inc., the City of Garland, Alliance for Retail Markets, and TXU
Business Services. The State of Texas did not take a position on the NUS.
30 See OPC's Response to the Proposed Stipulation Regarding Affiliate Expenses (Jun. 13, 2005); Statement of Position of CPL Retail
Energy, LP on the Nonunanimous Stipulation of Affiliate Costs (Jun. 13, 2005); Texas Legal Services Center's and Texas Ratepayer's
Organization to Save Energy's Response to Order No. 28 (Jun. 13, 2005).
31 Act of May 25, 2005, 79 th Leg., R.S., 2005 Tex. Sess. Law Serv. Ch. 413 (effective Jun. 17, 2005). S.B. 1668 amended PURA
36.058, and provides, in part, that if the Commission finds that an affiliate expense is unreasonable, the Commission shall determine
the reasonable level of expense and include that expense in the utility's cost of service.
32 Statement of Position of CPL Retail Energy, LP on the Nonunanimous Stipulation of Affiliate Costs at 4 (Jun. 13, 2005).
33 OPC's Response to the Proposed Stipulation Regarding Affiliate Expenses at 5 (Jun. 13, 2005).
34 City of El Paso v. Public Util. Comm'n, 883 S.W.2d 179, 183 (Tex. 1994).
35 Direct Testimony of Carol Szerszen, OPC Ex. 1A at 63.
36 Direct Testimony of Gerald W. Tucker, Cities' Ex. 4 at 20.
© 2015 Thomson Reuters. No claim to original U.S. Government Works. 35
APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784...
37 Direct Testimony of Dennis L. Thomas, CPL Ex. 1 at 48. This recommendation was based on CPL Retail's argument that the
Commission should take a “top-down” approach in disallowing affiliate costs that would result in the Commission using TCC's
previously approved affiliate costs (in its unbundled cost of service case, Docket No. 22356) “for the purposes of continuing current
levels of affiliate expenses in this docket.” Id.; see also Closing Statement of CPL Retail Energy, LP at 6-7 (Mar. 24, 2005).
38 As noted by CPL Retail, “[t]he adjudication of affiliate costs in this case has followed a long and twisted path, perhaps unlike any other
in the history of the Commission.” Statement of Position of CPL Retail Energy, LP on the Nonunanimous Stipulation of Affiliate
Costs at 2 (Jun. 13, 2005).
39 See Letter filed by AEP TCC regarding proposed non-substantive corrections at 1-2 (Jul. 21, 2005).
40 Application of Central Power and Light Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and
Public Utility Commission Substantive Rule 25.344, Docket No. 22352, Order (Oct. 5, 2001).
41 Id. at Finding of Fact No. 98; see id., Stipulation and Agreement, at 9-10 (Mar. 26, 2001).
42 Id.
43 P.U.C. SUBST. R. 25.231(b).
44 Direct Testimony of Marshall Nadel, TCC Ex. 22 at 12.
45 In contrast to TCC's proposal, Staff witness Jacobs recommended a funding level of $799,433 annually, while Cities' witness Arndt
recommended an annual funding level of $630,360.
46 Finding of fact 181A and conclusion of law 48A were added by the ALJs in their letter concerning clarifications and changes filed
August 19, 2004. Additionally, conclusion of law 48A is modified to reflect that this amount is includible in TCC's cost of service
rather than its rate base.
47 See 106-107.
48 Rebuttal Testimony of Randall Hamlett, TCC Ex. 67at 51; see also Commission Hearing Tr. at 550 (Mar. 4, 2005).
49 AEP is the parent company of TCC.
50 Petition of American Electric Power Company for Establishment of a Project to Modify Quality of Service Plan and Motion for
Interim State of Plan Provisions, Docket No. 25157, Order (May 5, 2005).
51 PFD at 154.
52 AEP Texas Central Company Compliance Tariff Filing to Provide Competitive Metering Credit Pursuant to P.U.C. SUBST. R. 25.311
Docket No. 28559, Order (Dec. 30, 2003).
53 Rulemaking on Nuclear Decommissioning Funding Following the Sale or Transfer of Nuclear Generating, Project No. 29169, Order
Adopting New § 25.303 (Oct. 6, 2004).
54 Schedule IV-J-2, TCC Ex. 2.2 at 2 of 27.
55 See PFD at 135-36.
56 See Letter from AEP TCC Regarding Non-Substantive Corrections (Jul. 21, 2005); Letter from AEP TCC Regarding Revised Number
Run (Jul. 21, 2005).
57 See Letter from AEP TCC Regarding Nuclear Decommissioning Expenses Findings (Jul. 7, 2005).
End of Document © 2015 Thomson Reuters. No claim to original U.S. Government Works.
© 2015 Thomson Reuters. No claim to original U.S. Government Works. 36
State Office of Administrative Hearings
~1~~ "•"
' •
~'11!""1\ff:'r\
' : "; lj 1:. ~j
7iJ04 JUL - 2 M~ IQ: 0I
PUBLIC urn 1n COHHISSION
Shelia Bailey Taylor FILING CLERK
Chief Administrative Law Judge
July 1, 2004
TO: Stephen Journeay, Director Courier Pick-up
Office of Policy Development
William B. Travis State Office Building
1701 N. Congress, 7th Floor
Austin, Texas 78701
RE: SOAH Docket No. XXX-XX-XXXX
PUC Docket No. 28840
Application ofAEP Texas Central Company for Authority to Change Rates
Enclosed are two copies of the Proposal for Decision (PFD) in the above-referenced case. Please
file-stamp and return a copy to the State Office of Administrative Hearings for our records. Also enclosed
is a disk containing an electronic copy of the PFD. By copy of this letter, the parties to this proceeding are
being served with the PFD.
Please place this case on an open meeting agenda for the Commissioners' consideration. The
statutory deadline was extended in this proceeding to August 6, 2004. It is my understanding that you will
be' notifying me and the parties of the open meeting date, as well as the deadlines for filing exceptions to
the PFD, replies to the exceptions, and requests for oral argument.
Sincerely,
Katherine L. Smith
It~
}" Paul D. Keeper
z. ~l;;;e_j__.
Administrative Law Judge Administrative Law Judge
Enclosure
xc: All Parties of Record (without disk)
William P. Clements Building
Post Office Box 13025 + 300 West 15th Street, Suite 502 + Austin Texas 78711-3025
(512) 475-4993 Docket (512) 475-3445 Fax (512) 475-4994 001
http://www.soah.state.tx.us
03lo
SOAH DOCKET NO. XXX-XX-XXXX
PUC DOCKET NO. 28840
APPLICATION OF AEP TEXAS § BEFORE THE STATE OFFICE
CENTRAL COMPANY FOR § OF
AUTHORITY TO CHANGE RATES § ADMINISTRATIVE HEARINGS
PROPOSAL FOR DECISION
I. INTRODUCTION
A. History and Overview
This is an application by American Electric Power Company (AEP) Texas Central Company
(the Company, TCC, or Applicant) for approval of a change in the rates that it may charge for the
transmission and distribution (T&D) of electricity. The Applicant is a T&D utility that provides
service to a 44,000-square-mile area of south Texas. The service area includes the portion of Texas
from just south of San Antonio to the Mexican border, and from Bay City west to Eagle Pass. Major
cities in the Applicant's service area include Corpus Christi, McAllen, Harlingen, Laredo, and
Victoria. The Applicant provides distribution services to about 785 ,000 electric connections, served
by 28 retail electric providers (REPs). The Applicant's service area has a labor force population of
just over 1 million. 1
AEP, the Applicant's parent company, is one of the largest investor-owned public utility
holding companies in the United States. AEP became active in the Texas electric utility service
market when AEP merged with a Texas electric utility holding company, Central and South West
Corporation (CSW), in June 2000. 2 Prior to the merger, the Applicant was known as Central Power
and Light Co., a name now held by the affiliated REP.3
1
TCC Ex. 4 at 6-7; TSLC/ROSE Ex. 8 at 2.
2
TCC Ex. 4 at 5; Application ofCentral and South West Corporation and American Electric Power Company,
Inc. Regarding Proposed Business Combination, Docket No. 19265, Final Order (Nov. 18, 1999).
3
References in this proposal for decision to the REP will be to "CPL" or "CPL Retail." References in this
proposal for decision to the former name of the Applicant will be to "Central Power and Light Co."
007
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 122
PUC DOCKET NO. 28840
Although Dr. Goodfriend's survey and the portion of her testimony upon which it is based may be
flawed, that criticism does not fit the remainder of her testimony. Therefore, the ALJs recommend
a disallowance of one-half of Dr. Goodfriend's expenses, which reduces Cities' expenses to
$935,595.
The ALJ s also do not find a basis for denying either TCC or Cites their rate case expenses
for appeals to the courts.
T. Miscellaneous Issues
TCC seeks to modify its Business Separation Plan (BSP) allowing it to separate by selling
its generation assets outright, rather than placing them into an affiliated company, for purposes of
determining its stranded costs. This issue appears to be uncontested. Therefore, the ALJ s
recommend that TCC be allowed to modify its BSP to allow it to sell its generation assets, rather
than placing them into an affiliated company.
VII. QUALITY AND RELIABILITY OF SERVICE
A. Quality of Service
1. Dr. Goodfriend's Testimony
The issue of quality of service was raised as a major point of contention by Cities and its
witness, Dr. Sarah Goodfriend. 470 Dr. Goodfriend's thesis was that the introduction of Customer
Choice has had a negative effect upon the quality of service to end-use consumers. Among the
causes of this degradation in quality, according to Dr. Goodfriend, is the fragmentation of the
470
Dr. Goodfriend' s credentials include her having obtained a Ph.D. in economics from the University ofNorth
Carolina and her service with the Commission both as Director of the Economic and Regulatory Policy Division and,
later, as a member of the Commission.
.. 128
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 123
PUC DOCKET NO. 28840
formerly integrated electric utility industry into providers with little direct relation to the ultimate
electric utility customer. According to Dr. Goodfriend, however, PURA contains public policy
controls about the tendency of suppliers to deteriorate service quality as a method of cost-cutting. 471
Dr. Goodfriend identified examples of this statutory recognition in PURA§§ 38.022, 39.101, and
36.052. These three statutes, Dr. Goodfriend asserted, reflect PURA standards that are instructive
for an assessment of retail service quality. 472
PURA (and the regulations adopted pursuant to it) does recognize the need for the control
of quality of service issues. However, much of that authority addresses the relationship between the
end-use customer and its closest link in the Customer Choice system-the REP. The customer
protection rules ofP.U.C. SUBST. R. 25.471-25.492 are among the best examples of the legislature's
and the Commission's efforts at protecting the consumer in its primary utility relationship.
As to Dr. Goodfriend's first two examples, PURA§§ 38.022473 and 39.101, 474 neither serve
the function that she asserts and neither defines a direct statutory basis for evaluation of the
Applicant's performance in this proceeding. 475
However, the third of Dr. Goodfriend's example, PURA§ 36.052, does serve that function.
Specifically, PURA § 36.052 requires the Commission to consider "the quality of the utility's
services" and "the quality of the utility's management" in establishing a reasonable return on
invested capital as part of the PUC's "establishing an electric utility's rates." This proceeding is one
in which the PUC is establishing an electric utility's rates.
471
Cities Ex. 8 at 16.
472
Cities Ex. 8 at 15.
473
Generally, PURA § 38.022 prohibits a utility from engaging in discriminatory practices with regard to
persons that seek to compete with a utility.
474
PURA § 39.1O1 addresses the many consumer protection issues that the Commission later adopted in its
consumer protection rules, P.U.C. SUBST. R. 25.471-25.492.
475
The Applicant's briefaccurately and appropriately identified the problems associated with Dr. Goodfriend' s
reliance upon PURA §§ 38.022 and 39.101 as the statutory foundation for examining quality of service issues.
However, the ALJs note that the Applicant's brief did not address Dr. Goodfriend's reliance upon PURA§ 36.052.
129
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 124
PUC DOCKET NO. 28840
As with many Texas regulatory statutes, PURA § 36.052 is a general grant of legislative
authority. The Commission is given broad power to provide the necessary administrative details.
In response, the Commission has adopted three quality of service rules, found in P.U.C. SUBST.
R. 25.51 ("Power Quality''), 25 .52 ("Reliability and Continuity of Service"), and 25.53 ("Emergency
Operation Plan"). Each of these three rules measure important aspects of a utility's quality of public
service. However, none of them measure the "consumer responsiveness" issues sought by
Dr. Goodfriend or that may reasonably be derived from a fair reading of PURA § 36.052. In the
absence of measures provided by either the statute or by Commission rules adopted from the statute,
Dr. Goodfriend fashioned her own measures from other specific standards within other
Commission's consumer protection rules. 476 Using these measures, Dr. Goodfriend sought to obtain
data by conducting a survey of the utility's consumers with the greatest opportunity to evaluate the
utility's quality of service performance-the REPs within the Applicant's service area.
The universe of potential survey respondents was a bare 26 or 27 REPs, of which only nine
returned completed survey forms. 477 In response to concerns expressed by some REPs,
Dr. Goodfriend preserved the confidentiality of the individual respondents' data. The survey created
a series of procedural issues even before Dr. Goodfriend testified. The Applicant sought to obtain
information about the identities of the respondents, and Cities declined. In response, the Applicant
filed a motion to compel the production or to strike the testimony of Dr. Goodfriend. The ALJ s
ruled that Cities would have to produce the underlying data or deal with the challenge ofidentifying
the non-objectionable portions of Dr. Goodfriend's pre-filed testimony.
The parties agreed to allow Dr. Goodfriend to testify while Cities considered its options, and
Dr. Goodfriend's direct and cross-examination were provisionally admitted into the record.
Eventually, Cities opted to disclose the survey respondents' identities and to relate that information
to the underlying survey response data. By agreement, the Applicant later submitted additional
cross-rebuttal testimony that challenged the accuracy of the survey's underlying data, conclusions,
476
Cities Ex. 8 at 22.
477
Cities Ex. 8 at 25.
,- ' ~ r 130
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 125
PUC DOCKET NO. 28840
and methodology. The Applicant's brief amplified that criticism. The Applicant has sought not only
that the Commission disregard the entirety of Dr. Goodfriend' s survey-based analysis 478 but also that
the Commission disallow the reimbursement of Dr. Goodfriend's portion of Cities' rate case
expenses. 479
These developments were unfortunate. The ALJs consider Dr. Goodfriend's analysis to have
been a good faith effort to bring to the Commission's attention an important issue. That the statute
and the rules did not provide the details by which some quality of service issues could readily be
measured required some creativity in setting those standards and obtaining that data. The ALJs
believe that the provisions of PURA§ 36.052 may reasonably be interpreted to require a survey of
the REPs. Indeed, Dr. Goodfriend reported that surveys are in the planning stages for at least one
other T&D utility and for ERCOT. 480
Nonetheless, the ALJs concur with the Applicant that the survey methodology was seriously
flawed and that conclusions drawn from the data cannot reasonably be supported under current legal
standards. The ALJ s do not conclude that quality of service issues are irrelevant to this proceeding
or that a survey of REPs (or others with opinions) is an inappropriate means of data gathering.
Further, the ALJs' recommendation on this portion of Dr. Goodfriend's analysis does not reflect on
the other portions of her testimony.
2. Other Quality of Service Evidence
Dr. Goodfriend's survey was not the only example of survey evidence on this topic in this
hearing. On cross-examination, the Applicant's witness, Harry Gordon, presented the results of four
quarterly end-use customer surveys. Four thousand residential customers and 3,310 commercial
478
Applicant's Initial Brief at 124.
479
Applicant' Initial Brief at 117.
48
° Cities Ex. 8 at 23.
131
Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008)
2008 WL 727056 (Tex.P.U.C.)
Slip Copy
Application of AEP Texas Central Company for Authority to Change Rates
33309
XXX-XX-XXXX
Texas Public Utility Commission
March 4, 2008
ORDER ON REHEARING
Before Smitherman, Chairman, Parsley and Hudson, Commissioners.
BY THE COMMISSION:
On November 9, 2006, AEP Texas Central Company (TCC) filed an application for authority to change rates pursuant to
PURA, 1 Chapter 36, requesting an increase in base rates that would produce an annual base revenue increase of $62,709,174.
During the course of this proceeding, TCC reduced this amount to approximately $49,952,000. 2 TCC also seeks to terminate
the merger savings and rate reduction riders implemented in Docket No. 19365, 3 further increasing its revenues by $19,988,359
annually. Therefore, the total revenue increase sought by TCC in this proceeding is $69,940,359.
The administrative law judges (ALJs) filed a proposal for decision (PFD) on August 30, 2007. In their PFD, the ALJs recommend
that the Commission approve TCC's application, including termination of the merger savings and rate reduction riders, subject
to the adjustments recommended in the Proposal for Decision (PFD). The recommendations reduce TCC's adjusted test year
total revenue requirements from $581,127,359 to $531,123,478, a reduction of $50,004,479. TCC identified several number-
run adjustments required to implement the ALJs' decision. 4 The Commission ordered Commission Staff to incorporate TCC's
number-run corrections, which resulted in a revenue requirement of $540,707,774 or a reduction of $40,419,575 5 from TCC's
original request. The Commission adopts the PFD issued by the ALJs, including the findings of fact and conclusions of law, with
the number run corrections recommended by TCC in its exceptions to the PFD. 6 Findings of fact 23, 24 and 42 are modified
to reflect Commission Staff's updated number runs.
I. Findings of Fact
Procedural History
1. AEP Texas Central Company (TCC or the Company) is an electric utility operating company and wholly owned subsidiary
of American Electric Power Company (AEP), a public utility holding company.
2. TCC has been functionally unbundled, and its costs have been separated for accounting purposes among Transmission,
Distribution, and Generation functions since the onset of retail competition in 2002.
3. TCC filed its application with the Public Utility Commission of Texas for authority to increase its transmission and
distribution (T&D) rates on November 9, 2006, requesting an overall increase of approximately $62.7 million.
4. As part of its application, TCC gave notice of its intent to terminate approximately $20 million in credits to customers
that are provided by separate riders implemented in connection with the Commission's approval of the AEP/CSW merger in
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Application of Central and Southwest Corporation and American Electric Power Company, Inc. Regarding Proposed Business
Combination, Docket No. 19265 (Nov. 18, 1999).
5. Concurrent with its filing with the Commission, TCC filed a similar petition and statement of intent with each incorporated
city in its service area that has original jurisdiction over its retail rates.
6. Notice of TCC's application was published once a week for four consecutive weeks in newspapers having general circulation
in each county in TCC's service territory and was completed on December 14, 2006.
7. Individual notice of the TCC's application was provided on November 9, 2006, to the Commission Staff and the Office of
Public Utility Counsel (OPC).
8. On October 4, 2006, TCC mailed notice to each municipality in TCC's service area of its intent to change rates charged to
retail electric providers (REPs) and certain end-use customers.
9. On November 8, 2006, TCC mailed notice of its petition and statement of intent to each municipality within TCC's service
area.
10. Individual notice of the TCC's application was provided and completed by November 9, 2006, to all REPs who have been
certified by the Commission and who serve end-use customers in TCC's service area. Notice was provided to all certified REPs.
11. Individual notice of the Application was provided to each party that participated in Application of AEP Texas Central
Company for Authority to Change Rates, Docket No. 28840 (Aug. 15, 2005), TCC's last T&D rate case.
12. The Commission referred this proceeding to the State Office of Administrative Hearings (SOAH) on November 14, 2006.
The Commission issued its Preliminary Order setting forth the issues to be addressed in this proceeding on December 19, 2006.
13. The following parties were granted intervention: Alliance for Retail Markets (ARM); Cities served by TCC (Cities); City of
Garland; Commercial Customer Group (CCG); CPL Retail Energy, L.P. (CPL); Efficiency Texas; Federal Executive Agencies
(Department of the Navy); Occidental Power Marketing, L.P.; OPC; Reliant Energy Retail Services, LLC; South Texas Electric
Cooperative; Sharyland Utilities, L.P.; State of Texas; Texas Cotton Ginners' Association; Texas Industrial Energy Consumers
(TIEC); Texas Legal Services Corporation (TLSC); Texas Ratepayers Organization to Save Energy (Texas ROSE); Texas State
Association of Electrical Workers; Oncor Electric Delivery Company; TXU Energy, Wholesale and Power Companies; and
Wal-Mart Stores Texas, L.P. and Texas Retail Energy LLC (Wal-Mart).
14. TCC timely filed appeals with the Commission of the rate ordinances of the municipalities exercising original jurisdiction
within its service territory. All such appeals were consolidated for determination in this proceeding.
15. TCC's application is based on a test year ending June 30, 2006.
16. On January 26, 2007, TCC filed an update to its rate filing that reduced its overall rate increase request by approximately
$1.6 million.
17. When TCC filed its rebuttal case, it unilaterally decreased its total requested T&D base rate increase to approximately $50
million, a reduction of approximately $12 million from its initial request. This reduction included the impact of the January 26,
2007 update, as well as other reductions agreed to by the Company as a result of changed circumstances since its initial filing,
or based on its review of Commission Staff and intervenor positions.
18. The hearing on the merits commenced on April 12, 2007 and lasted seventeen hearing days, concluding on May 4, 2007.
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19. TCC proposed an effective date of December 14, 2006, for the proposed rates. The effective date was suspended for 150 days
until May 13, 2007. The Company agreed to further extend the effective date in order to allow the ALJs and the Commission
to process the case.
20. On April 17, 2007, TCC filed notice of its intent to put into effect, under bond, the rates set out in attached, filed tariff sheets.
The rates will produce an annual base revenue increase of $50,061,000. TCC stated its intent to implement such bonded rates on
a system-wide basis on or after May 30, 2007, in order to maintain uniform system-wide rates throughout its service territory.
21. On May 15, 2007, the ALJs issued an interim order finding that a bonded rate is a changed rate under the ISA and PURA §
36.110; therefore, TCC is allowed to terminate the merger savings and the rate reduction riders ordered in Docket No. 19265,
upon implementation of bonded rates.
22. On June 27, 2007, the Commission denied an interim appeal of the order identified in the above finding of fact 21, affirming
the ALJs' ruling.
Rate Base
23. TCC's used and useful total transmission plant in service (excluding general and intangible plant in service) is
$912,831,763. 7 TCC's used and useful transmission plant in service net of accumulated depreciation (excluding depreciation
on general and intangible plant in service) is $642,951,403. 8
24. TCC's used and useful total distribution plant in service (excluding general and intangible plant in service) is
$1,446,115,221. 9 TCC's used and useful distribution plant in service net of accumulated depreciation (excluding depreciation
on general and intangible plant in service) is $953,628,481. 10
25. TCC included in rate base a pension prepayment asset of $112.4 million.
26. The pension prepayment asset arises under Generally Accepted Accounting Principles (GAAP) in accordance with
Statement of Financial Accounting Standards No. 87 (SFAS 87) and represents the amount by which the pension fund exceeds
the accumulated pension obligations.
27. Investment income on the pension prepayment asset reduces pension cost calculated under SFAS 87.
28. Accounting in accordance with GAAP requires that both the balance sheet and income statement effects be taken into
account.
29. The pension prepayment asset contains $22.799 million included in construction work in progress (CWIP).
30. Only the non-CWIP portion of the income earned on the pension prepayment asset is reflected in the total pension expense
and the revenue requirement.
31. The pension prepayment asset should not be included in TCC's rate base to the extent that TCC's pension cost is capitalized
to CWIP.
32. The pension prepayment asset of $112.4 million, less the $22.799 million portion included in CWIP, should be included
in rate base.
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33. All of TCC's operations and maintenance (O&M) and administrative and general (A&G) expenses are included in its cash
working capital calculation.
34. The leads and lags in paying these items, which give rise to the amounts recorded in Account 190, have been appropriately
included in the calculation of rate base through this process.
35. Accumulated Deferred Federal Income Tax (ADFIT) of $323.9 million is reasonable and should be included in rate base.
36. In arriving at its adjusted test-year-end rate base, TCC reclassified $7.3 million in transmission projects that were classified
as CWIP and that had not been closed out to plant-in-service as of June 30, 2006 but which were actually providing service
to customers as of that date.
37. TCC also removed from rate base allowance for funds used during construction (AFUDC) of $368,625 related to the
transmission projects that were reclassified.
38. The $7.3 million reclassification of these projects to plant-in-service is reasonable and should be adopted.
39. TCC's construction accounts payable were included in TCC's cash working capital calculation. Accordingly, the leads and
lags associated with these construction accounts payable are appropriately included in the calculation of rate base.
40. Based on findings of fact 72 through 77, TCC's affiliate capital costs assigned to TCC Distribution should be reduced by
$2,454,762, and affiliate capital costs assigned to TCC Transmission should be increased by $211,520.
41. TCC included in rate base $10.2 million in debt restructuring costs related to business separation. TCC also included in cost
of service an annual amortization expense of $914,892 for amortization of these debt restructuring costs over a 15-year period.
42. TCC has a current cash working capital requirement of ($2,341,171), which includes $1,361,010 for transmission;
($2,660,226) for distribution; ($478,450) for metering; and ($563,505) for TDCS. 11
43. TCC's current working capital request reflects a modification of the monthly payment dates from TCC to American Electric
Power Service Corporation (AEPSC) from the actual date of payment (usually the second or third working day after receipt) to
the thirtieth day after receipt of the bill, as authorized by the TCC-AEPSC Service Agreement.
44. TCC must pay additional AEPSC financing costs for delaying payment of its bill from the second or third day until the
thirtieth day after receipt.
45. TCC's own financing costs equal the financing costs charged to it by AEPSC. Thus, TCC will save the same amount of
financing costs that AEPSC will charge it for delaying payments to AEPSC, so TCC will not incur any net increase in finance
charges by delaying payment to AEPSC.
46. For TCC's cash working capital calculation, it is more appropriate to use the mid-point of the service period than the invoice
date in the calculation of third-party expense lead days.
47. Cities' calculation of the third-party payment lead from samples of TCC's third-party invoices is reasonable and should be
adopted, resulting in an additional third-party expense lead period of 2.26 days for distribution and an additional third-party
expense lead period of 5.63 days for transmission.
48. The additional lead days for third-party expenses reduces TCC's request for cash working capital and rate base by $9,314,603.
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49. Beginning with calendar year 2005, TCC was required to implement for financial reporting purposes accounting for legal
asset retirement obligations (AROs) associated with the cost of removal of asbestos from buildings in accordance with SFAS
143.
50. In its filing, TCC incorporated appropriate accounting changes for ratemaking purposes to account for the AROs associated
with the cost of removal of asbestos from buildings in accordance with SFAS 143. This involved the establishment of offsetting
ARO assets and liabilities, the inclusion of SFAS 143 depreciation and accretion in cost of service, and the exclusion of the cost
of removal of asbestos from buildings from the net salvage component of the calculation of depreciation rates for Account 390.
51. TCC's use of SFAS 143 accounting for ratemaking purposes for the cost of removal of asbestos from buildings aligns the
regulatory treatment with GAAP and should be approved.
Return on Equity and Capital Structure
52. A return on equity of 9.96% will allow TCC a reasonable opportunity to earn a reasonable return on its capital investment.
53. TCC's energy conservation efforts, the quality of its services, the efficiency of its operations, and the quality of its
management support a 9.96% return on equity.
54. A 9.96% return on equity is consistent with the level of financial risk associated with TCC's capital structure.
55. A reasonable application of the discounted cash flow, risk premium, and capital asset pricing models supports a return on
equity of 9.96%.
56. TCC presented a revised pro forma cost of debt of 5.8586% based on updated information resulting from the retirement
and refunding of its debt using the proceeds of the securitization approved in Application of AEP Texas Central Company for
a Financing Order, Docket No. 32475, Financing Order (June 21, 2006).
57. The $1,669,612 in debt issuance costs related to Matagorda Navigation District No. 1 Pollution Control Bonds Series 2005
and B in 2005 were not incurred in connection with the issuance of transition bonds and are properly included in the cost of
debt calculation in this docket.
58. TCC could not have included the $1,669,612 in cost of debt in Docket No. 33541, because that docket was a proceeding
expressly designed for addressing only qualified costs.
59. TCC's cost of debt for purpose of this docket is 5.8586%.
60. The appropriate capital structure for purposes of setting rates in this proceeding consists of 60% debt and 40% equity.
61. A 60/40 capital structure is consistent with existing Commission precedent for T&D utilities.
62. A 60/40 capital structure is consistent with current rating agency expectations for TCC.
63. TCC's overall rate of return is as follows:
Component % of Total Capitalization Cost of Capital Rate WACC (%)
Long Term Debt 60.00% 5.8586% 3.5152%
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Common Equity 40.00% 9.9600% 3.9840%
Total 100.00% 7.4992%
Cost of Service
64. AEPSC is the service company for the AEP System. It provides services to AEP's utility companies, including TCC.
65. TCC provided evidence supporting the primary allocation factors used to allocate costs and why such allocation factors
are appropriate for the cost they support for fourteen classes of service involving affiliate transactions between AEPSC and
TCC: customer service, distribution; transmission; external affairs; regulatory; Texas administration; information technology;
business logistics; human resources; finance; accounting and strategic planning; internal support; safety and environmental;
legal; and corporate communications.
66. TCC established cost trends, budget comparisons, benchmark studies, if available, or other proof suggested by the
Commission's rate filing package Guiding Principles to support its level of requested affiliate costs.
67. TCC provided a schedule that shows how each allocator used by TCC is calculated and how often the calculation is updated.
68. The functions performed by AEPSC allow TCC to reduce its costs by capturing economies of scale.
69. AEPSC has been consistently reducing service company costs over the last several years, including costs to TCC.
70. The activities performed for TCC are necessary and provide direct benefits to TCC and its customers in terms of lower
costs and reliable operations.
71. Of the approximately 90 discrete activities that define the full scope of AEPSC services, 19 activities were assessed to
determine the potential for overlap of activities between AEPSC and TCC and other AEP utility subsidiaries. These 19 areas
had activity descriptions that indicated potential similarity. Detailed assessment of these activities established that there was
no duplication between AEPSC and TCC.
72. The manner in which AEPSC charges costs to TCC is properly designed to ensure that the equitable distribution and the
allocation process are generally reasonable, except for the use of TCC's total assets allocator.
73. TCC uses a total assets factor to allocate the cost of certain services provided to itself and to other AEP affiliates by AEPSC.
74. After deregulation pursuant to Senate Bill 7, the Commission quantified TCC's stranded costs, and TCC chose to recover
those costs through the securitization process rather than through a competition charge. The Commission issued financing orders
allowing TCC to issue securitization bonds, providing TCC with the full amount of its stranded costs. Once the Commission
issued the financing orders, TCC placed these regulatory assets on its books, assigned to TCC Distribution.
75. TCC included the regulatory assets noted in the above finding of fact and relating to stranded costs and securitization of
generation assets in Allocator 58, its total assets allocator.
76. The inclusion of regulatory assets in Allocator 58 inflates the allocation of costs charged by AEPSC to the TCC distribution
company.
77. Although TCC is required by accounting standards to include its regulatory assets on its balance sheet, these regulatory
assets are not related to the provision of distribution service and should not be included in TCC's cost of service.
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78. TCC adequately reviews and questions the monthly services bill that it receives from AEPSC.
79. Any corrections requested by TCC or by other AEP affiliates, which AEPSC adopts, are applied to bills for all affiliate
companies. Thus, a correction requested by another affiliate can benefit TCC.
80. TCC's adjustment to account for the creation of a new affiliate, Electric Transmission Texas, LLC (ETT) is reasonable.
81. TCC's adjustment to Allocator 70, Non-Electric Other Accounts Receivable, is reasonable.
82. TCC's inclusion of annual and long-term incentive compensation related to financial incentives in cost of service is
unreasonable because it is not necessary for the provision of T&D utility services.
83. TCC reasonably determined group life insurance expense using an annualized June 2006 amount, with proper adjustments
to cost of service to eliminate the portion of capitalized costs.
84. TCC reasonably determined savings plan (401k) expense using an annualized June 2006 amount, with proper adjustments
to cost of service to eliminate the portion of capitalized costs, as adjusted in its rebuttal testimony.
85. TCC's pension expense of $1,627,376, which reflects a reduction of $456,000 for negative pension expense under SFAS
87 related to former generation employees, is reasonable and necessary.
86. TCC's requested adjusted test-year amount of $5,953,937 for postretirement benefits under SFAS 106, which included
$886,264 in SFAS 106 transition adjustment amortization related to former generation employees, is reasonable.
87. Additional SFAS 106 postretirement benefit costs of $564,736 related to the former generation employees should be included
in cost of service.
88. Total SFAS 106 postretirement benefit costs of $6,518,673 are reasonable and necessary.
89. A catastrophic property damage loss self-insurance program with an annual accrual of $1,300,000 and a target reserve
amount of $13 million is in the public interest.
90. TCC's distribution O&M expenses, with the removal of the payment to the Public Utilities Board of Brownsville from
distribution station maintenance expense, are reasonable and necessary.
91. TCC's transmission O&M expenses are reasonable and necessary.
92. TCC's request to recover the amount of its calendar year 2006 energy efficiency costs is known and measurable because
TCC has used the actual 2006 costs to calculate its energy efficiency goal to be achieved by January 1, 2008.
93. For energy efficiency cost recovery, it is more reasonable to use costs incurred in a calendar year because such recovery
more closely tracks statutory and regulatory energy efficiency goals.
94. It is reasonable for TCC's cost of service to include $6,334,949 in energy efficiency costs, as reflected in its calendar year
2006 costs.
95. TCC's proposed net salvage values for all FERC accounts are reasonable and appropriate estimates of future net salvage
recoveries.
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96. In its application, TCC submitted a depreciation study based on plant-in-service as of December 31, 2005. This study
reduced TCC's depreciation rates relative to the rates adopted by the Commission in Docket No. 28840.
97. TCC accepted Cities' recommended service life and survivor curves for two FERC accounts and net salvage for one FERC
account. Differences exist between TCC and Cities and/or Commission Staff with respect to service life and survivor curves
for seven FERC accounts and with respect to net salvage for 20 FERC accounts.
98. TCC's service life and survivor curves, as modified by the above finding of fact, are reasonable and should be adopted for
all FERC accounts, except FERC accounts 365, 368, 371, and 373.
99. Commission Staff's recommendations should be adopted regarding the survivor curves (but not its proposed net salvage
values), and the resultant depreciation rate should be adopted for FERC accounts 365, 368, and 371.
100. Cities' recommendation regarding the survivor curve and depreciation rate for FERC account 373 is reasonable and should
be adopted.
101. TCC properly removed net proceeds from 1999 and 2005 building sales from consideration of net salvage value regarding
FERC Account 390, because the net salvage received from sales of various buildings in those years were not generated in the
ordinary course of TCC's business.
102. The inflation embedded in TCC's historical information will likely be experienced in the future.
103. TCC's historical information regarding cost and retirements of its assets properly imposes costs on the customers who
benefit from the use of those assets.
104. The depreciation rates requested by TCC as set forth in TCC Exhibit 66 are reasonable and should be approved for all FERC
accounts except FERC accounts 365, 368, 371, and 373. TCC's depreciation rates should be applied to the adjusted plant-in-
service as of June 30, 2006, in order to calculate the reasonable and necessary depreciation accrual expense for cost of service.
105. The survival curves and resultant depreciation rates recommended by Commission Staff (but not its net salvage values)
are reasonable and should be approved for FERC accounts 365, 368, and 371. The depreciation rates resulting from the survival
curve recommended by Commission Staff should be applied to the adjusted plant-in-service as of June 30, 2006, in order to
calculate the reasonable and necessary depreciation accrual expense for cost of service in FERC accounts 365, 368, and 371.
106. The survival curve and resultant depreciation rate requested by Cities is reasonable and should be approved for FERC
Account 373. The depreciation rate resulting from the survival curve requested by Cities as set forth in TCC Exhibit 66 should
be applied to the adjusted plant-in-service as of June 30, 2006, in order to calculate the reasonable and necessary depreciation
accrual expense for cost of service in FERC account 373.
107. Regarding sales of certain buildings in FERC Account 390, TCC removed from its depreciation study the proceeds from
sales in 1999 and 2005, along with the associated costs of removal, and the original costs of the buildings.
108. The approach TCC used regarding sales of buildings in FERC Account 390 is reasonable, comports with the applicable
accounting requirements, and provides the full benefit of the sale, including the gain, to customers, through reduction of rate
base and associated reduction of the depreciation accrual.
109. TCC experienced 50% or higher net salvage results for FERC Account 390 in six of 22 years (1984-2005) included in
its depreciation study.
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110. After 1999, 2005 was the first year in which TCC received net gains from salvage of buildings in FERC Account 390
that exceeded 50%.
111. The last year that a net salvage rate of greater than 50% occurred for FERC Account 390 was 1994.
112. TCC's net salvage results for 1999 and 2005 from sales of buildings are not likely to recur regularly on the same scale.
113. As part of its implementation for ratemaking purposes of SFAS 143 ARO accounting for the legal obligations related to
costs of removal of asbestos from buildings, TCC included an accretion expense of $73,000, which substitutes for the cost of
removal of asbestos previously included in the cost of removal for depreciation purposes.
114. Because it is reasonable to implement for ratemaking purposes SFAS 143 ARO accounting for the legal obligations related
to costs of removal of asbestos from buildings, the related accretion amount is reasonable and necessary.
115. TCC appropriately collected late payment charges in compliance with the existing tariff, using reasonable accounting
practices.
116. During the test year, TCC performed transmission-related construction services, engineering, procurement, and other
related construction services for the Lower Colorado River Authority (LCRA) on lines that will be owned by LCRA.
117. TCC is exiting the third-party construction business; thus, it reduced its test year margins (revenues less expenses) of $3.3
million down to $789,714, as a known and measurable adjustment to miscellaneous revenues.
118. TCC's adjustment to miscellaneous revenues to account for the decrease in third-party margins is reasonable, known, and
measurable.
119. TCC is a member of an affiliated group eligible to file a consolidated federal income tax return.
120. The amount of the fair share of consolidated federal income tax savings allocated to TCC is $1,901,184 before gross up
and $2,924,898 after gross up.
121. Ad valorem property taxes in the amount of $27,853,898 are reasonable and necessary expenses.
122. The transmission cost of service (TCOS) included in the final distribution cost of service should be synchronized with the
transmission rates applied to the TCC distribution function based on the TCOS established for the TCC transmission function
as a result of this case.
123. TCC's historical actual bad debt cost for the test year of $138,776 should be included in cost of service.
124. TCC's proposal to include $328,009 in rates for business and economic dues was unsupported by the preponderance of the
evidence because some dues may have included legislative advocacy or lobbying expenses.
125. It is reasonable to sever from this proceeding issues related to Cities' and TCC's recovery of rate case expenses.
Load Research
126. In Application of AEP Texas Central Texas Company for Authority to Change Rates, Docket No. 28840 (Aug. 15, 2005),
TCC was ordered to file TCC-specific load research data in its next rate case.
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127. TCC filed company-specific load research data in this case.
128. TCC employed industry-accepted standard load research practices in developing the load research samples and demand
estimates, which accurately represent the TCC rate class populations.
129. The overall result of TCC's load research study is a reasonable estimate of class demands for use in allocating costs in
this case.
130. The changed load characteristics result from class usage changes.
131. The final numbers produced by TCC's load research study consistently represent the customers that moved from the non-
interval data recorder (IDR) class to the IDR class as if they were members of the IDR class for the entire test year.
Cost-of-Service Study
132. In Docket No. 28840, the Commission's Order required TCC to perform a new distribution field study. TCC completed
that study and used its results to allocate demand related distribution costs in the cost-of-service study used in this docket.
133. The cost-of-service studies performed by TCC were performed in a manner that is consistent with that used in TCC's most
recent rate case, are reasonable, and should be approved.
134. It is appropriate to use a 100% demand allocator for distribution accounts 364 through 368.
135. The data in the cost-of-service study supporting the development of charges for IDR metered customers, the schedules,
and workpapers collectively support the changes proposed by TCC for IDR metered customers.
136. All customers within a class pay the same metering charge, regardless of the type of meter they use.
137. IDR-metered customers receive a higher Customer Charge than non-IDR-metered customers in the same class, primarily
due to the complexity of preparing the IDR-metered customer's bill.
Rate Design
138. TCC's rate design uses the same customer classes ordered by the Commission in Docket No. 22344, Order No. 40.
139. TCC's proposed textual changes and changes to the standard allowance values in the Facilities Extension Schedule are
unopposed and are reasonable.
140. TCC's proposed pilot program for front-of-the-lot subdivisions, as modified by Commission Staff, is reasonable.
141. TCC's request to continue to provide facilities rental services under the Distribution Voltage Facilities Rental Service and
System Integral Facilities Rental Service tariff schedules, as updated in this proceeding, until January 1, 2011, is unopposed
and is reasonable.
142. The increases assigned to each of the generic rate classes are the result of moving each rate class to unity (i.e., an equalized
rate of return or full recovery of allocated costs).
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143. Applying an across-the-board increase when actual cost data is available is contrary to Commission precedent, unjustified,
and should be rejected.
144. An adjustment to the revenue allocation for the intra-class functions is neither necessary nor appropriate.
145. Modification of the customer service, metering, and distribution function revenue requirements unjustifiably strays from
the equalized cost-of-service study.
146. TCC's proposed changes to the customer charges are based on cost, are consistent with Commission precedent, and should
be approved.
Riders
147. TCC's proposed Municipal Franchise Fee Adjustment-City (MFFA-C) rider would be used to reflect a change to a specific
municipality's franchise fee.
148. Under the proposed MFFA-C rider, municipal franchise fee adjustment that applies to a specific municipality would be
applied to bills of retail customers who are located within the specific city's municipal limits.
149. TCC's proposed Rider MFFA-C should be rejected as it would create confusion with potentially over 100 different rates.
150. Having different rates in each municipality in TCC's service territory is contrary to the Commission's desire for uniform,
simple rates.
151. The Commission has a pending rulemaking to change the energy efficiency rules in Amendments to Energy Efficiency
Rules and Templates, Project No. 33487, which was put on hold pending proposed legislation.
152. It is premature to adopt a new method of energy efficiency cost recovery, such as the rider TCC proposed in its application,
until the Commission adopts new rules, as required by recent legislation.
Discretionary Service Fees
153. Discretionary service fees are billed to the REPs or distribution end-use retail customers for the cost of performing a
specific distribution service requested by the REP or end-use retail customer.
154. Discretionary service fees are charged to the party that causes the cost to be incurred so that other parties not requiring
the service do not have to pay for the cost through base rates.
155. All TDUs must offer the discretionary services defined in the Standardized Discretionary Services Section of the Tariff.
156. TCC's proposed discretionary service fees are based on the cost to perform each discretionary service.
157. TCC's proposed discretionary fees, including the disconnect and reconnect fees, are reasonable and should be approved.
Tariff Formatting and Language
158. Several areas in TCC's filed Standardized Discretionary Services portion of its tariff do not conform to the pro forma tariff
approved in Project No. 29637.
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159. The formatting changes recommended by Commission Staff should be made in order to comply with the Commission's rule.
160. Commission Staff's recommended changes to the proposed Broken Meter Seal and After Hours Temporary Removal fees
should be made.
161. Commission Staff's recommended language changes to Section 6.2.3.3.7, Meter Enclosure Seal Breakage, should be
approved.
Termination of the ISA Riders
162. Pursuant to the ISA entered in Docket No. 19265, the merger savings and rate reduction riders related to the merger of
AEP and Central and Southwest Corporation (CSW) terminate with a change in TCC's rates.
163. TCC was allowed to terminate the Docket No. 19265 merger savings and rate reduction riders upon its filing of bonded
rates, effective May 30, 2007.
164. TCC should continue to be allowed to terminate the Docket No. 19265 merger savings and rate reduction riders upon the
entry of a final order in this proceeding that changes TCC's rates.
II. Conclusions of Law
1. TCC is an electric utility as defined by PURA § 31.002, and, therefore, it is subject to the Commission's jurisdiction under
PURA §§ 32.001, 33.051, and 36.102.
2. TCC is a T&D utility as defined in PURA § 31.002(19).
3. SOAH has jurisdiction over all matters relating to the conduct of the hearing in this case, including the preparation of a
Proposal for Decision, pursuant to PURA § 14.053 and TEX. GOV'T CODE ANN. § 2003.049(b).
4. TCC provided adequate notice of this proceeding in compliance with P.U.C. PROC. R. 22.51.
5. Pursuant to PURA § 33.001, each municipality in TCC's service area that has not ceded jurisdiction to the Commission has
jurisdiction over the Company's application, which seeks to change rates for distribution services within each municipality.
6. The Commission has jurisdiction over an appeal from a municipality's rate proceeding pursuant to PURA § 33.051.
7. PURA § 36.110 authorizes a utility to put changed rates, not to exceed its proposed rates, into effect in all areas in which the
utility sought to change its rates under bond if the Commission fails to make its final determination before the 151st day after the
date that the proposed change would otherwise have gone into effect had the operation of the proposed rates not been suspended.
TCC's proposed effective date for its proposed rates was December 14, 2006, because TCC was authorized to implement a
changed rate under bond effective with usage beginning on May 14, 2007, subject to refund, because the Commission did not
make its final determination of rates on or before May 13, 2007.
8. The effective date of the change in rates approved in this case was extended to be consistent with P.U.C. SUBST. R. 25.241(i)
and by agreement of TCC, consistent with P.U.C. PROC. R. 22.33(c).
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Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008)
9. The rates approved in this proceeding are based on original cost, less depreciation, of property used and useful to TCC,
consistent with PURA § 36.053.
10. TCC's treatment of its debt restructuring costs conforms to the determinations the Commission made regarding these costs
in its orders in Application of Central Power and Light Company for Approval of Unbundled Cost of Service Rate Pursuant
to PURA § 39.201 and Commission Substantive Rule 25.344, Docket No. 22352 (Oct. 5, 2001) and Docket No. 28840 (Aug.
15, 2005), should be approved.
11. PURA § 36.065(a) provides that electric utility rates shall include “expenses for pensions and other postemployment
benefits, as determined by actuarial or other similar studies in accordance with generally accepted accounting principles, in an
amount the regulatory authority finds reasonable.”
12. TCC's requested pension expense, which accounts for negative pension expense under SFAS 87 related to former generation
employees, is in accordance with PURA § 36.065.
13. TCC's requested adjusted test-year amount of postretirement benefits under SFAS 106, which included a transition
adjustment amortization related to former generation employees, is in accordance with PURA § 36.065.
14. GAAP, with respect to pension cost, are determined in accordance with SFAS 87 and SFAS 88.
15. P.U.C. SUBST. R. 25.231(c)(2)(D) prohibits including in rate base the portion of TCC's pension prepayment asset
capitalized to CWIP.
16. Inclusion in rate base of TCC's approved pension prepayment asset and offsetting accumulated deferred income taxes
comports with GAAP and PURA § 36.065.
17. No modification would be proper to the rate base treatment or to the 15-year amortization to cost of service of the debt
restructuring costs TCC incurred in connection with business separation ordered in Docket Nos. 22352 and 28840.
18. The return on equity and overall return authorized in this proceeding are consistent with the requirements of PURA §§
36.051 and 36.052.
19. PURA § 39.302(4) allows “the costs of issuing, supporting, and servicing transition bonds and any costs of retiring and
refunding the electric utility's debt and equity securities in connection with the issuance of transition bonds” to be included in
qualified up-front costs of securitization. Costs in the amount of $1,669,612 that TCC incurred in issuing Matagorda Navigation
District No. 1 Pollution Control Bonds Series 2005 and B in 2005 were not incurred in “retiring and refunding. . . [TCC's] debt
and equity securities in connection with the issuance of transition bonds,” which occurred in late 2006.
20. The costs in the amount of $1,669,612 initially incurred in issuing Matagorda Navigation District No. 1 Pollution Control
Bonds Series 2005 and B in 2005 are properly included in TCC's cost of debt calculation. P.U.C. SUBST. R. 25.231(c)(1)(C)(i).
21. TCC's decisions to retire and refund debt using the proceeds of the securitization were prudent under the prudence standard
articulated in Application of Gulf States Utilities Company to Change Rates, Docket No. 7195, 14 P.U.C. Bull. 1943, 1969-1970,
2429 (CoL 14) (May 16, 1998).
22. For ratemaking purposes, P.U.C. SUBST. R. 25.231(c)(1)(C)(i) requires the cost of debt to be “the actual cost of debt at the
time of issuance, plus adjustments for premiums, discounts, and refinancing and issuance costs.”
23. The affiliate expenses included in TCC's rates are consistent with the requirements of PURA § 36.058.
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24. PURA § 36.065(a) authorizes an unbundled transmission and distribution utility to include in rates the “pension and other
postemployment benefits” related to the employees of its predecessor's generation function.
25. As used in PURA § 36.065(a), “pension and other postemployment benefits” (OPEB) includes pension costs under SFAS
87, postretirement benefits under SFAS 106, and postemployment benefits under SFAS 112.
26. Pursuant to P.U.C. SUBST. R. 25.231(b)(1)(H), OPEB shall be included in an electric utility's cost of service for ratemaking
purposes based on actual payments made.
27. PURA § 36.064 permits a utility to self-insure “potential liability or catastrophic property loss, including windstorm, fire,
and explosion losses, that could not have been reasonably anticipated and included under operating and maintenance expenses.”
The Commission shall approve a self-insurance plan under that section if it finds the coverage in the public interest, the plan,
considering all of its costs, is a lower cost alternative to purchasing commercial insurance, and ratepayers receive the benefits
of the savings.
28. A catastrophic property damage loss self-insurance program with an annual accrual of $1,300,000 and a target reserve
amount of $13 million is in accordance with PURA § 36.064 and P.U.C. SUBST. R. 25.231(b)(1)(G).
29. PURA § 36.060 requires the use of a consolidated tax savings (CTS) adjustment when computing an electric utility's federal
income taxes.
30. PURA §§ 36.061 and 36.062 and P.U.C. SUBST. R. 25.231(b)(2)(A) disallow recovery of legislative advocacy expenses
included in professional or trade association dues.
31. PURA § 39.903(g) no longer applies to TCC, which is subject to competition.
32. TCC's proposed level of energy efficiency funding complies with PURA § 39.905(f).
33. P.U.C. SUBST. R. 25.342(f)(1)(D)(ii)(III) requires a utility to “credit all revenues received . . . during the test year after
known and measurable adjustments are made to lower the revenue requirement” of the T&D utility. TCC's proposal to make a
known and measurable change to its test year margins of $3.3 million and then reduce its revenue requirement by the adjusted
margin of $789,714 complies with this requirement.
34. TCC's proposed rate design and cost allocation are consistent with the requirements of PURA §§ 36.003 and 36.004.
35. Termination of the rider credits associated with the Commission's order in Docket No. 19265, contemporaneous with
implementation of bonded rates in this proceeding, is consistent with the provisions of PURA § 36.110 and with the express
language of the Integrated Stipulation and Agreement approved by the Commission in Docket No. 19265.
III. Ordering Paragraphs
The proposal for decision prepared by the SOAH ALJs is adopted to the extent consistent with this Order.
1. TCC's application is granted to the extent provided in this Order.
2. All issues relating to the recovery of Cities' and TCC's rate case expenses are severed from this proceeding and consolidated
with Proceeding to Consider Rate Case Expenses Severed from Docket No. 33310 (Application of AEP Texas North company
for Authority to Change Rates, Docket No. 34301 (pending)).
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3. TCC shall file tariff sheets consistent with this Order no later than 20 days after receipt of this Order. The compliance tariff,
and all filings related to it, shall be filed in Tariff Control Number 35093, and shall be styled: Compliance Tariff of AEP Texas
Central Company Pursuant to Final Order in P.U.C. Docket No. 33309, (Application of AEP Texas Central Company for
Authority to Change Rates). The filing shall include a transmittal letter stating that the tariffs attached are in compliance with
the order, giving the docket number, date of the order, a list of tariff sheets filed, and any other necessary information. No later
than 10 days after the date of the tariff filings, Commission Staff shall file its comments recommending approval, modification,
or rejection of the individual sheets of the tariff proposal. Responses to the Commission Staff's recommendation shall be filed
no later than 15 days after the filing of the tariff. The Commission shall by letter approve, modify, or reject each tariff sheet,
effective the date of the letter.
4. Pursuant to PURA § 36.110(d) TCC shall (1) refund or credit bills for money collected under the bonded rates put into effect
on or after May 30, 2007 in excess of the base rate revenue increase ordered in this docket; and (2) include interest on that
money at the current approved Commission approved interest rates. TCC shall file in Tariff Control Number 35093 calculations
supporting the amounts and a tariff to implement the refund or credit.
5. The tariff sheets shall be deemed approved and shall be become effective upon the expiration of 20 days from the date of
filing, in the absence of written notification of modification or rejection by the Commission. If any sheets are modified or
rejected, TCC shall file proposed revisions of those sheets in accordance with the Commission's letter within 10 days of the
date of that letter, and the review procedure set out above shall apply to the revised sheets.
6. Copies of all tariff-related filings shall be served on all parties of record.
7. All other motions, requests for entry of specific findings of fact and conclusions of law, and any other requests for general
or specific relief, if not expressly granted, are denied.
SIGNED AT AUSTIN, TEXAS the 4th day of March 2008.
Final Order
Schedule I
Revenue Requirement
COMPANY NAME AEP TEXAS CENTRAL COMPANY
TEST YEAR END 30-Jun-06
Test Year Total Company Adjustments Company Adjusted Test Recommended Adjust. Final Order Adjusted
To Test Year Year Total Electric To Co. Request Total Electric
(a) (b) (c) (d) (e)=(c)+(d)
REVENUE
REQUIREMENT
Operations & Maintenance 296,033,365 (36,179,627) 259,853,738 (14,328,513) 245,525,225
Depreciation & 96,502,951 (20,891,707) 77,611,244 (2,781,840) 74,829,404
Amortization Expense
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Taxes Other Than Income 80,617,871 (277,099) 80,340,772 (4,416,323) 75,924,449
Taxes
Federal Income Tax 58,197,809 (21,306,539) 35,036,738 (8,096,772) 26,940,967
Return on Invested Capital 205,700,718 (77,415,253) 128,285,485 (10,797,736) 117,487,730
TOTAL REVENUE 739,052,714 (156,070,225) 581,127,968 (40,420,183) 540,707,774
REQUIREMENT
MINUS. OTHER (38,539,566) (38,539,566) (38,539,566)
REVENUE
TOTAL ADJUSTED 700,513,148 (156,070,225) 542,588,392 (40,420,183) 502,168,208
REVENUE
REQUIREMENT
Schedule II
TABULAR OR GRAPHIC MATERIAL SET FORTH AT THIS POINT IS NOT DISPLAYABLE
Schedule III
Invested Capital
Test Year Total Company Adjustments Company Adjusted Test Recommended Adjust. Final Order Adjusted
To Test Year Year Total Electric To Co. Request Total Electric
(a) (b) (c) (d) (e)=(c)+(d)
INVESTED CAPITAL
Plant in Service 2,658,106,172 6,080,094 2,664,186,266 (2,243,242) 2,661,943,024
Accumulated Depreciation (867,692,603) 613,007 (867,079,596) 0 (867,079,596)
Net Plant in Service 1,790,413,589 6,693,101 1,797,106,870 (2,243,242) 1,794,563,428
Construction Work in 0 0 0 0
Progress
Plant Held for Future Use 0 0 0 0
Working Cash Allowance 6,605,495 0 6,605,495 (8,942,063) (2,336,568)
Materials and Supplies 21,796,582 (6,015,953) 15,780,609 0 15,780,809
Prepayments 114,759,964 0 114,759,964 (22,799,000) 91,980,984
Regulatory Assets 1,686,675,388 (1,665,490,091) 21,185,297 0 21,185,297
SFAS 109 Reg. Liability (30,411,435) 0 (30,411,435) (30,411,435)
Deferred Federal Income (1,022,891,875) 698,972,101 (323,919,774) 0 (323,919,774)
Taxes
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Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008)
Customer Advances for 0 0 0 0
Construction
Customer Deposits 688,850 0 688,850 0 688,850
Asset Retirement (1,201,634) 9,402 (1,192,232) 0 (1,192,232)
obligations
Investment Tax Credits (116,069) 0 (116,069) 0 (116,069)
TOTAL INVESTED 2,566,318,815 (965,831,440) 1,600,487,375 (33,964,305) 1,586,503,070
CAPITAL
RATE OF RETURN 8.0154% 8.0154% 7.5000%
RETURN ON INVESTED 205,700,718 128,285,465 117,487,730
CAPITAL
Schedule IV
Taxes Other Than FIT
Test Year Total Company Adjustments Company Adjusted Test Recommended Adjust. Final Order Adjusted
To Test Year Year Total Electric To Co. Request Total Electric
(a) (b) (c) (d) (e)=(c)+(d)
TAXES OTHER THAN
FIT
Ad Valorem Taxes 30,985,808 953,313 31,939,121 (4,123,063) 27,816,058
Payroll Taxes 3,302,653 157,097 3,459,750 0 3,459,750
Sales and Use (557,545) 1,042,850 485,305 485,305
Federal Excise\ St. Lic. 1,009 0 1,009 1,009
Municipal Franchise 41,044,325 (396,142) 40,646,183 40,646,183
Taxes
Franchise Tax 5,841,621 (5,841,621) 0
Gross Margin Taxes 0 3,809,404 3,809,404 (293,280) 3,516,144
TOTAL TAXES OTHER 80,617,871 (277,098) 80,340,772 (4,416,323) 75,924,449
THAN INCOME TAXES
Final Order Schedule II-B-1
TABULAR OR GRAPHIC MATERIAL SET FORTH AT THIS POINT IS NOT DISPLAYABLE
Final Order - Schedule II-B-5
TABULAR OR GRAPHIC MATERIAL SET FORTH AT THIS POINT IS NOT DISPLAYABLE
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Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008)
TABULAR OR GRAPHIC MATERIAL SET FORTH AT THIS POINT IS NOT DISPLAYABLE
Final Order Schedule II-B-1
TABULAR OR GRAPHIC MATERIAL SET FORTH AT THIS POINT IS NOT DISPLAYABLE
Final Order Schedule II-B
TABULAR OR GRAPHIC MATERIAL SET FORTH AT THIS POINT IS NOT DISPLAYABLE
Footnotes
1 Public Utility Regulatory Act, TEX. UTIL. CODE ANN. §§ 11.001 - 64.158 (Vernon Supp. 2007) (PURA).
2 TCC Ex. 78, RWH-1R.
3 See Application of Central and Southwest Corporation and American Electric Power Company, Inc. Regarding Proposed Business
Combination, Docket No. 19365, Integrated Stipulation and Agreement (Nov. 18, 1999).
4 AEP Central Company's Exceptions to the Proposal for Decision and Request for Number Running Corrections, Attachment E at
87-91 (Sept. 20, 2007).
5 See generally Commission Staff Final Number Run - Final Order - Schedule 1 - Total Revenue Requirement - Column Total for
Final Order Adjusted Total Electric (Feb. 5, 2008).
6 See generally Corrected Page to the Proposal for Decision and Request for Number Running (Sept. 20, 2007).
7 See Docket No. 33309 - Final Order Number Run - (Transmission Model) Schedule II-B-1, Rate Base Accounts - Plant Test Year
Ending 6/30/2006 - Total Transmission Distribution Plant Gross (Filed February 5, 2008)
8 Id.- Schedule II-B-5 - Total Transmission - Distribution Plant - Net
9 Id. (Distribution Model) Schedule II-B-1
10 Id. (Distribution Model) Schedule II-B-5
11 See - P.U.C. Docket No. 33309 - Final Number Runs - Schedule IIB - Summary of Rate Base - Cash Working Capital (Reference
Schedule II-B-9) Page 1 of 1 (February 5, 2008).
End of Document © 2015 Thomson Reuters. No claim to original U.S. Government Works.
© 2015 Thomson Reuters. No claim to original U.S. Government Works. 18
PUC DOCKET NO. 34800
SOAH DOCKET NO. XXX-XX-XXXX
APPLICATION OF ENTERGY §
GULF ST ATES, INC. FOR §
AUTHORITY TO CHANGE RATES §
AND TO RECONCILE FUEL §
COSTS §
ORDER
1
This order addresses the application of Entergy Gulf States, Inc. (EGSI) for
authority to change rates and reconcile fuel costs. The docket was processed in accordance
with applicable statutes and Public Utility Commission of Texas rules. EGSI,
Commission Staff, the Office of Public Utility Counsel (OPC), the Community
Associations of the Woodlands (CATW), the Entergy Texas, Inc. Service Area Cities'
Steering Committee (Cities), the State of Texas, Texas Industrial Energy Consumers
(TIEC), Texas Legal Services Center (TLSC), Texas Ratepayers' Organization to Save
Energy (Texas ROSE), Wal-Mart Stores Texas, LLC , through their duly authorized
representatives (Wal-Mart) (collectively, signatories) filed a stipulation and settlement
agreement that resolves all of the issues in this proceeding. The Kroger Company and TX
Energy, LLC did not sign the stipulation and do not oppose it. Consistent with the
stipulation, EGSI's application is approved.
The Commission adopts the following findings of fact and conclusions of law:
I. Findings of Fact
Procedural History
1. On September 26, 2007, EGSI filed an application for approval of: ( 1) base rate
tariffs and riders designed to collect a total non-fuel revenue requirement for the
1
On December 31, 2007, EGSI jurisdictionally separated pursuant to * 39.452( e) of the Public Utility
Regulatory Act (PURA), TEX. UTIL. CODE ANN. Title 2 and Entergy Texas, Inc. (ETI) succeeded to EGSI's certificate of
PUC Docket No. 34800 Order Page 2of15
SOAH Docket No. XXX-XX-XXXX
Texas retail jurisdiction of $605 million; (2) a set of proposed tariff schedules
presented in the Electric Utility Rate Filing Package for Generating Utilities (RFP)
accompanying EGSI's application; (3) a request for final reconciliation of EGSI's
fuel and purchased power costs for the reconciliation period from January 1, 2006
to March 31, 2007, as well as deferred costs from prior proceedings; and (4) certain
waivers to the instructions in RFP Schedule V accompanying EGSI's application.
2. The 12-month test year used in EGSI's application ended on March 31, 2007.
3. EGSI provided notice by publication for four consecutive weeks before the
effective date of the proposed rate change in newspapers having general circulation
in each county of EGSI's Texas service territory. EGSI also mailed notice of its
proposed rate change to all of its customers. Additionally, EGSI timely served
notice of its statement of intent to change rates on all municipalities retaining
original jurisdiction over its rates and services.
4. The following parties were granted intervenor status in this docket: OPC, Alliance
for Retail Markets (ARM), CATW, Cities, Kroger Company, State, TIEC, TLSC,
Texas ROSE, TX Energy, LLC, and Wal-Mart.2 Commission Staff was also a
participant in this docket.
5. On October 1, 2007, the Commission referred this case to the State Office of
Administrative Hearings (SOAH) for processing.
6. EGSI appealed the rate decisions adopted by the Cities of Chester, Woodville,
Ames, Dayton, Devers, Liberty, New Waverly, Riverside, Trinity, Bedias,
Bremond, Caldwell, Calvert, Franklin, Madisonville, Somerville, Patton Village,
Cut and Shoot, Willis, Plum Grove, Shepherd, Oak Ridge North, Normangee,
Daisetta, Hardin, Corrigan, Groveton, Anderson, Kosse, North Cleveland,
Woodloch, Midway, Panorama Village, Taylor Landing, Rose Hill Acres, China,
Hearne, Bevil Oaks, Colmesneil, Kountz, Nome, Lumberton, and Todd Mission.
convenience and necessity for its Texas retail jurisdiction. For continuity and ease of reference, EGSI, Commission
Staff, and intervenors have continued to make reference to EGSI for purposes of pleadings in this docket.
2
OPC, ARM, Cities, Kroger Company, State, and TIEC were granted party status on October 22, 2007. See
Prehearing Conference Tr. at 6.
PUC Docket No. 34800 Order Page 3of15
SOAH Docket No. XXX-XX-XXXX
7. As provided for in Order Nos. 3, 9, 12, 14, and 23, the SOAH administrative law
judges (ALJs) consolidated EGSI's appeals of the rate decisions adopted by the
cities in Finding of Fact No. 6.
8. Cities participated in this case representing the Cities of Beaumont, Bridge City,
Conroe, Groves, Houston, Huntsville, Navasota, Nederland, Orange, Pine Forest,
Pinehurst, Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake,
Vidor, and West Orange. These municipalities have adopted rates consistent with
the stipulation discussed below.
9. The Commission established in its Order on Appeal of Order No. 8 an effective
date for EGSI's proposed rate change of September 26, 2008.
10. On April 8, 2008, the State filed a motion for partial summary decision regarding
the continued applicability of the 20% base rate discount for state institutions of
higher education under § 36.351 of the Public Utility Regulatory Act, TEX. UTIL.
CODE ANN.§§ 11.001-66.016 (Vernon 2007 & Supp. 2008) (PURA).
11. On July 16, 2008, the SOAH ALJs issued a proposal for decision (PFD)
recommending that the Commission grant the State's April 18, 2008 motion for
partial summary decision.
12. On August 15, 2008, the Commission entered an order adopting the PFD on the
State's motion for partial summary decision.
13. The Commission entered an order on November 4, 2008, extending the effective
date ofEGSI's proposed rate change until November 27, 2008.
14. Commission Staff, State, and TIEC filed a non-unanimous stipulation (NUS) on
May 19, 2008. EGSI and certain other parties filed a separate NUS on May 20,
2008. 3 The EGSI NUS was opposed by Commission Staff, State, and TIEC. A
hearing was held on both NUSs on June 23 through July 2, 2008.
15. At Open Meetings on October 23 and November 5, 2008, the Commission
considered a PFD from the SOAH ALJ s which recommended resolution of the rate
PUC Docket No. 34800 Order Page 4of15
SOAH Docket No. XXX-XX-XXXX
case through adoption of the EGSI NUS. On November 7, 2008, the Commission
issued its order on remand rejecting the PFD and remanding the docket to SOAH
for a hearing on the merits of EGSI's original application.
16. During the November 5, 2008 Open Meeting, EGSI agreed to extend the statutory
jurisdictional deadline in this docket to March 2, 2009. EGSI subsequently agreed
to extend the statutory jurisdictional deadline to March 16, 2009. 4
17. The SOAH ALJs granted ARM's motion to withdraw as an intervenor on
December 2, 2008, pursuant to Order No. 49.
18. The hearing on the merits on remand took place on December 3 and 4, 2008, and
December 8 through December 12, 2008. The hearing was recessed on
December 12, 2008, in order to allow the parties to work on concluding a
settlement.
19. On December 16, 2008, the signatories submitted a settlement term sheet to reflect
their agreement in principle resolving all outstanding issues regarding EGSI's
application, including those issues raised by the Commission in its November 7,
2008 order on remand.
20. On December 16, 2008, the signatories submitted an agreed motion to implement
interim rates.
21. On December 19, 2008, the SOAH ALJs filed Order No. 52, granting interim
approval of rates consistent with the settlement term sheet, effective with bills
rendered on and after January 28, 2009, for usage on and after December 19, 2008.
22. On February 5, 2009, the signatories submitted a stipulation resolving all
outstanding issues in this docket.
23. On February 10, 2009, the SOAH ALJs filed Order No. 56, returning this docket to
the Commission.
3
The EGSI NUS was subsequently amended on June 27, 2008.
4
EGSI letter filed February 18, 2009.
PUC Docket No. 34800 Order Page 5of15
SOAH Docket No. XXX-XX-XXXX
Description of the Stipulation and Settlement Agreement
24. The signatories agree that EGSI will institute an overall mcrease in base rate
revenues of $46. 7 million.
25. The signatories agree to a reasonable return on equity for EGSI of 10.00%.
26. The signatories agree that the cost of service underlying the base-rate revenue
increase does not include any unreasonable or unjust expenses.
27. The signatories agree that EGSI will implement a rate-case-expense rider to recover
$2.3 million per year for three years. The rate-case expenses will be allocated to
customer classes based on total base-rate revenues. The rates established under the
rate-case expense rider will be determined based on energy consumption in
kilowatt-hours (kWh), except for the Large Industrial Power Service (LIPS)
customer class, whose rates will be set on a kilowatt (kW) basis.
28. The Signatories agree to leave the mechanisms for recovery of EGSI's municipal
franchise-fee riders unchanged as a result of this docket.
29. The Signatories agree that EGSl's proposed Market Value Energy Rider (MYER)
will not be offered as a result of this docket.
30. The signatories agree that the Incremental Purchased Capacity Recovery Rider
(IPCR) will expire contemporaneously with the implementation of rates approved
in Order No. 52.
31. The signatories agree that the base-rate revenue increase, the rate-case expense
rider and the municipal franchise-fee riders addressed in the stipulation became
effective for bills rendered on and after January 28, 2009 for usage on and after
December 19, 2008, as approved in Order No. 52.
32. The signatories reached the following specific agreements regarding rate design as
a part of the overall resolution of this docket:
a. Supplemental Short Term Service (SSTS). Rate Schedule SSTS will
terminate six months after a final, appealable order approving the
stipulation is issued by the Commission in this docket. Beginning with the
PUC Docket No. 34800 Order Page 6of15
SOAH Docket No. XXX-XX-XXXX
base rates implemented as a result of this stipulation, EGSI will bill SSTS
usage as follows: (SSTS charges+ LIPS charges)/2.
b. Interruptible Service (IS). Rate Schedule IS will be modified as follows:
1. 30-minute notice service is eliminated;
ii. The credit for 5-minute notice service 1s reduced to $3.75/kW-
month;
111. The credit for no-notice service is reduced to $4.88/kW-month;
1v. The credits shall be applied to the· LIPS and LIPS-Time of Use
(TOU) tariffs (current High Load Factor Service (HLFS) and Large Power
Service (LPS) customers will be transferred to LIPS); and
v. Rate Schedule IS remains closed to new business.
c. Competitive Generation Service. EGSI's competitive generation-service
proposal shall not be withdrawn, but shall be severed from this docket and
addr('<::<::ed in a separate docket wherein the Commission will (a) exercise its
authority to approve, reject, or modify EGSI's proposal; and (b) address
reCOV' • any costs unrecovered as a result of the implementation of the
,J
\.J ~ 'neons Electric Service Charges. No change shall be made to
Miscellaneous Electric Service Charges.
e. Lighting Class Rates. Lighting-class rates for all lighting fixtures shall be
designed in a manner so that each fixture is charged a uniform base-rate
percentage increase as established for the entire lighting class.
f. Additional Facilities Charge (AFC). Rate Schedule AFC, governing
additional-facilities charge, will be designed to result in a reduction to
1.49%, with the resulting revenue reduction allocated among those
customer classes with AFC revenue based on the percentage of AFC
revenues in each customer class.
PUC Docket No. 34800 Order Page 7of15
SOAH Docket No. XXX-XX-XXXX
g. Economic as Available Power Service/Standby Maintenance Service.
No substantive changes shall be made as a result of this docket to: (a) Rate
Schedule EAPS, governing Economic-as-Available Power Service; or (b)
Rate Schedule SMS, governing Standby Maintenance Service.
h. Interconnection Terms and Conditions. No changes shall be made as a
result of this docket to EGSI's terms and conditions regarding costs for
interconnection of customers.
L Electric Extension Policy. No changes shall be made as a result of this
docket to EGSI's electric extension policy.
J. Large Interruptible Power Service. The signatories stipulate that the
contract demand ratchet provisions in Rate Schedule LIPS will be retained;
provided, however, that the billing demand provision contained in
Paragraph V of Rate Schedule SSTS will no longer apply to customers
taking service under Rate Schedule LIPS after Rate Schedule SSTS
terminates.
33. The signatories agree to the class-cost allocation set forth in Attachment A to the
stipulation and further agree that this allocation is reasonable.
34. The signatories agree to a River Bend nuclear generating station 20-year life
extension adjustment to EGSI's calculation of nuclear depreciation and
decommissioning costs effective January 1, 2009.
35. The signatories agree that EGSI will reduce depreciation expense related to EGSI's
steam production plants by the amount of $2,731,478 on a total Texas retail basis
effective January 1, 2009.
36. The signatories agree that EGSI will present a new depreciation study as part of its
next base-rate case, or by January 5, 2010, whichever is earlier.
37. The signatories agree that the base-rate increase, rate riders, and associated rate
design and class-cost allocation agreed to in the stipulation are reasonable and are
PUC Docket No. 34800 Order Page 8of15
SOAH Docket No. XXX-XX-XXXX
reflected in the rate schedules approved by Order No. 52 and revised by errata
filings on December 22, 2008, January 27, 2009, and March 5, 2009.
38. The signatories agree that EGSI will fund its Public Benefit Fund at an annualized
amount of $2 million.
39. In order to include a greater portion of the eligible population in the Public Benefit
Fund program, EGSI agrees to use its best efforts to contract for and implement an
automatic enrollment program. EGSI's automatic enrollment program will be
modeled upon the matching procedures used by other Texas utilities to identify
eligible customers and will be implemented within 30 days of the Commission's
filing of the final order in this case.
40. The signatories agree that EGSI will amend its low-income energy-efficiency
program on a trial basis as specified in the stipulation.
41. The signatories agree that the amendment of EGSI' s low-income energy-efficiency
program does not increase base rates to recover uncollected expenses associated
with revenues billed under EGSI's energy-efficiency rider approved in Docket
No. 35626.5
42. The signatories agree to a fuel disallowance of $4.5 million, booked in the month
of a final Commission order approving the application, consistent with the
stipulation.
43. The signatories agree to adopt Commission Staffs position on the following
resolution of fuel-related matters set out in Commission Staffs pre-filed direct
testimony: (a) recovery of sulfur dioxide (S02) and nitrous oxide (NOx) emissions
revenues recorded in Account 411.8 and expenses recorded in Account 509 will be
allowed as eligible fuel expense going forward until further order of the
.
Commission realigning such costs; (b) special circumstances should be granted to
treat the costs of natural-gas call options incurred during the reconciliation period
5
Application of Entergy Texas, Inc. for Approval of an Energy Efficiency Cost Recovery Factor
(EECRF) Pursuant to PURA§ 39.905(b) and P.UC. Subst. R. 25.181(/), Docket No. 35626, Order (Aug. 14,
2008).
PUC Docket No. 34800 Order Page 9of15
SOAH Docket No. XXX-XX-XXXX
as eligible fuel expense; (c) good cause exists to sever and defer the River Bend
performance-based ratemaking (PBR) calculation for the final seven months of the
reconciliation period to EGSI's next fuel reconciliation proceeding; and (d) the
River Bend PBR plan should terminate in light of EGSI's jurisdictional separation.
Evidence Supporting the Stipulation and Agreement
44. Considered in light of (a) the pre-filed testimony by the parties entered into
evidence, and (b) the additional evidence and testimony presented by the parties
during the course of the hearing on the merits on EGSI's application, the stipulation
is the result of compromise from each party, and these efforts, as well as the overall
result of the stipulation viewed in light of the record evidence as a whole, support
the reasonableness and benefits of the terms of the stipulation.
45. The evidence addressed in finding of fact 44 demonstrates that the rates, terms, and
conditions resulting from the stipulation are just and reasonable and consistent with
the public interest when the merits of the issues contested by Commission Staff and
intervenors are considered.
46. The stipulated revenue requirement does not include any amounts for financial-
based incentive compensation.
47. To the extent that affiliate costs are included in the stipulated revenue requirement
and fuel expense, they are reasonable and necessary for each class of affiliate costs
presented in EGSI' s application.
48. To the extent that affiliate costs are included in the stipulated revenue requirement
and fuel expense, the price charged to EGSI is not higher than the prices charged by
the supplying affiliate for the same item or class of items to its other affiliates or
divisions, or a non-affiliated person within the same market area or having the
same market conditions.
49. The Texas retail revenue requirement in the stipulation does not include any of the
following expenses, whether allocated or direct-billed to EGSI: legislative
advocacy expenses; entertainment; charitable contributions; advertising expense to
promote the increased consumption of electricity or to promote the image of the
PUC Docket No. 34800 Order Page 10of15
SOAH Docket No. XXX-XX-XXXX
electric utility industry; advertising products marketed by other affiliates; civil
penalties or fines; any other expenses listed in PURA §§ 36.061, 36.062, and
36.063; payments made to cover costs of an accident, equipment failure, or
negligence at a utility facility owned by a person or governmental body not selling
power inside the State of Texas (except those made under an insurance or risk-
sharing arrangement executed before the date of loss); the costs for processing a
refund or credit under PURA § 36.11 O; any profit or loss that results from the sale
of merchandise not integral to providing utility service; construction work in
progress in rate base; or plant held for future use in rate base.
50. EGSI's current supplemental short-term service, Schedule SSTS, should be
terminated within six months after the filing of a final, appealable Commission
order in this docket, as provided for in the stipulation.
51. It is reasonable to modify EGSI's current interruptible service, Schedule IS, in
accordance with the terms and conditions of the stipulation.
52. It is reasonable in light of the compromise reached in the stipulation for no
substantive modifications to be made to EGSI's economic as-available power
service, Schedule EAPS, or standby maintenance service, Schedule SMS.
53. The depreciation and decommissioning adjustments for nuclear production assets
agreed to in the stipulation and consistent with Louisiana rate treatment are
reasonable.
54. The depreciation adjustments to EGSl's steam production assets agreed to in the
stipulation are reasonable.
55. The increase in storm cost accruals provided for in the stipulation is reasonable.
56. The low-income programs provided for in the stipulation are reasonable.
57. EGSI's energy-efficiency costs are recovered through a rider approved by the
Commission in Docket No. 35626.
58. The PBR plan for the River Bend nuclear generating station contemplates an
annual calculation of penalties and rewards. Good cause exists to sever and defer
PUC Docket No. 34800 Order Page 11of15
SOAH Docket No. XXX-XX-XXXX
the PBR calculation for the final seven months of the reconciliation period to
EGSI's next fuel reconciliation proceeding.
59. It is reasonable to terminate the application of the PBR plan to the River Bend
operations on and after January 1, 2008 when Entergy Texas, Inc. no longer has an
ownership interest in River Bend.
60. EGSI is entitled to a special circumstances exception for the cost of the natural-gas
call options because they resulted in increased reliability of supply and reduced fuel
expense.
61. The class allocation methodologies described in the stipulation are reasonable.
62. The total level of invested capital in the Texas retail revenue requirement 1s
reasonable.
63. The EGSI stipulation proposes to collect the existing incremental franchise fees of
the Cities of Beaumont, Port Arthur, and Conroe as a municipal franchise-fee rider.
The Commission has reviewed its finding in paragraph ILE of its remand order of
November 7, 2008 and determines that the existing incremental franchise fees were
the result of franchise agreements adopted subsequent to the passage of PURA
§ 39.456.
II. Conclusions of Law
1. EGSI is a public utility as that term is defined in PURA § 11.004( 1) and an electric
utility as that term is defined in PURA § 31.002(6).
2. The Commission exercises regulatory authority over EGSI and jurisdiction over the
subject matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101,
33.002, 33.051, 36.001-36.111, 36.203, 39.452, and 39.455.
3. SOAH had jurisdiction over matters related to the conduct of the hearing and the
preparation of a proposal for decision in this docket, pursuant to PURA § 14.053
and TEX. Gov'T CODE ANN. § 2003.049.
PUC Docket No. 34800 Order Page 12of15
SOAH Docket No. XXX-XX-XXXX
4. This docket was processed in accordance with the requirements of PURA and the
Texas Administrative Procedure Act. 6
5. EGSI provided notice of its application in compliance with PURA§ 36.103, P.U.C.
PROC. R. 22.5l(a), and P.U.C. SUBST. R. 25.235(b)(l)-(3).
6. This docket contains no remaining contested issues of fact or law.
7. The stipulation, taken as a whole, is a just and reasonable resolution of all the
issues it addresses, results in just and reasonable rates, terms and conditions, is
supported by a preponderance of the credible evidence in the record, is consistent
with the relevant provisions of PURA, and is consistent with the public interest.
8. EGSI has properly accounted for the amount of fuel and IPCR-related revenues
collected pursuant to the fuel factor and Rider IPCR during the reconciliation
period.
9 The revenue requirement, cost allocation, revenue distribution, and rate design
implementine: the stipulation result in rates that are just and reasonable, comply
•• 1~ ratemaking provisions in PURA, and are not unreasonably discriminatory,
prcfrr :tial, t.. ..;ial.
1 ;~
\)ever'-' .•1 c'0SI's proposed competitive generation service into a separate
·ket :::iL ~it r, ',,,addressed separately is reasonable.
EGS1 ,:. ~mi 'cd to a special circumstances exception under P.U.C. SUBST. R.
25.236(a)(6) for :he cost of natural gas call options.
12. Consistent with the stipulation, good cause exists to treat EGSl's emissions
revenues and expenses referenced in finding of fact 43 as eligible fuel expense on a
going-forward basis until further order of the Commission realigning such costs.
13. Based on the evidence in this docket, the overall total invested capital through the
end of the test year meets the requirement in PURA§ 36.053(a) that electric utility
rates be based on the original cost, less depreciation, of property used by and useful
to the utility in providing service.
6
TEX. GOV'T. CODE ANN. Chapter 2001(Vernon2000 and Supp. 2007).
PUC Docket No. 34800 Order Page 13of15
SOAH Docket No. XXX-XX-XXXX
14. The Commission has reviewed its finding in paragraph ILE of its remand order of
November 7, 2008 and determines that because the existing incremental franchise
fees were the result of franchise agreements subsequent to the passage of PURA
§ 39.456, they qualify as new franchise agreements and are therefore in compliance
with PURA§ 39.456 when recovered as a municipal franchise-fee rider.
15. The final resolution of the instant docket does not impose any conditions,
obligations, or limitations on EGSI's right to file a base-rate proceeding and obtain
rate relief in accordance with PURA.
16. Consistent with the stipulation, EGSI has met its burden of proof in demonstrating
that it is entitled to the agreed upon level of Texas retail base-rate and rider
revenue.
17. Consistent with the stipulation and PURA, EGSI has met its burden of proof in
demonstrating that the rates are just and reasonable.
III. Ordering Paragraphs
In accordance with these findings of fact and conclusions of law, the Commission
issues the following orders:
1. Consistent with the stipulation, EGSI's application for authority to (a) change its
rates; (b) reconcile its fuel and purchased power costs for the Reconciliation Period
from January 1, 2006 to March 31, 2007, as well as deferred costs from prior
proceedings; and (c) for other related relief is approved.
2. Consistent with the stipulation, the rates, terms, and conditions described in this
order are approved.
3. Consistent with the stipulation, the tariffs and riders approved on an interim basis
by Order No. 52 and revised by errata on December 22, 2008, January 27, 2009,
and March 5, 2009, are approved.
PUC Docket No. 34800 Order Page 14of15
SOAH Docket No. XXX-XX-XXXX
4. Consistent with the stipulation, EGSI shall implement the low-income programs
described in this order.
5. Consistent with the stipulation, EGSI's Competitive Generation Services tariff is
severed from this docket and shall be addressed in Application of Entergy Texas,
Inc.for Approval of Competitive Generation Services Tariff, Docket No. 36713.
6. Consistent with the stipulation, EGSI's storm-cost accruals shall be increased by $2
million for a total accrual of $3.65 million annually beginning January l, 2009,
which amount will be incorporated in revenues recovered through base rates.
7. Consistent with the stipulation, EGSI shall terminate rate schedule SSTS and Rider
IPCR.
8. Consistent with the stipulation, EGSI shall adjust depreciation and
decommissioning expense related to the River Bend nuclear generating station and
depreciation expense related to EGSI's steam production assets.
9. Consistent with the stipulation, EGSI shall submit a new depreciation study.
10. Consistent with the stipulation, the Rider IPCR and fuel costs, including coal-
related costs deferred from prior proceedings are reconciled and approved through
March 31, 2007.
11. EGSI shall adjust its fuel over/under recovery balance consistent with the findings
in this order.
12. The entry of this order consistent with the stipulation does not indicate the
Commission's endorsement of any principle or methodology that may underlie the
stipulation. Neither should entry of this order be regarded as precedent as to the
appropriateness of any principle or methodology underlying the stipulation.
13. All other motions, requests for entry of specific findings of fact, conclusions of
law, and ordering paragraphs, and any other requests for general or specific relief,
if not expressly granted in this order, are hereby denied.
PUC Docket No. 34800 Order Page 15of15
SOAH Docket No. XXX-XX-XXXX
SIGNED AT AUSTIN, TEXAS the _ _ day of March 2009
PUBLIC UTILITY COMMISSION OF TEXAS
~
/.
B ITHERMAN, CHAIRMAN
DONNA L. NELSON, COMMISSIONER
q.\cadm\orders\final\34000\34800fo2.doc
Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725...
2009 WL 4724725 (Tex.P.U.C.)
Slip Copy
Application of Oncor Electric Delivery Company, LLC for Authority to Change Rates
35717
XXX-XX-XXXX
Texas Public Utility Commission
November 30, 2009
ORDER ON REHEARING
Before Smitherman, Chairman, Nelson and Anderson, Jr., Commissioners.
BY THE COMMISSION:
This Order addresses the application of Oncor Electric Delivery Company, LLC for authority to change its rates. On June 27,
2008, Oncor filed its first application with the Public Utility Commission of Texas for a rate change since it was unbundled
on January 1, 2002. Oncor originally requested a total net increase of $275 million, of which $45 million represented the net
increase associated with transmission service, and $230 million represented the net increase associated with the retail delivery
service. Oncor revised its revenue requirements on August 11, 2008, in its 45-day update to the rate filing package. 1 As updated,
Oncor's system-wide adjusted rate increase would yield $253,468,000 of increased revenue.
On June 2, 2009, the State Office of Administrative Hearings (SOAH) administrative law judges (ALJs) issued a proposal for
decision in which they recommended an overall rate increase for Oncor of $30,274,392. The Commission adopts in part and
rejects in part the proposal for decision issued by the ALJs in this proceeding, including the findings of fact and conclusions of
law. For the reasons discussed in this Order, the Commission determines that Oncor's appropriate system-wide adjusted rates
will lead to a revenue increase of $115,061,510. 2
I. PROCEDURAL HISTORY
Oncor filed its petition and rate filing package on June 27, 2008. On July 1, 2008, the Commission referred this case to SOAH.
An order was issued suspending the effective date of tariff changes and setting a prehearing conference. On August 6, 2008,
the Commission filed a preliminary order listing the issues to be addressed in this proceeding. On November 20, 2008, Oncor
requested that the issues concerning the costs incurred in presenting this rate case be moved to a separate docket. The matter
was severed into Application of Oncor Electric Delivery Company, LLC for Rate Case Expenses Pertaining to Docket No.
35717, Docket No. 36530.
The hearing on the merits convened before SOAH ALJs Henry Card and Catherine Egan on January 13, 2009, and continued
until February 9, 2009. At the close of the evidentiary hearing, Oncor announced on the record that it agreed to extend the
jurisdictional deadline to July 15, 2009. 3 The record remained open for the filing of briefs. On March 27, 2009, the parties
filed their reply briefs and the record closed. Number running began on May 12, 2009 with Staff returning the final numbers to
the ALJs on May 22, 2009. The parties requested that the ALJs file the PFD by June 2, 2009.
Exceptions to the PFD and replies to exceptions were filed. Subsequently, on July 1, 2009, the ALJs filed a letter recommending
changes to certain findings of fact. Accordingly, findings of fact 8, 15, 24, 41, 43, 49, 51, 118, 119, and 203 are modified
to reflect the recommendations made by the SOAH ALJs. Finding of fact 14 is not modified in response to the ALJs' letter
because, as discussed below, this finding is deleted in accordance with Chairman Smitherman's memorandum responding to
motions for rehearing.
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The Commission considered this matter at six Open Meetings: July 2, 2009, July 30, 2009, August 13, 2009, October 8, 2009,
October 22, 2009, and November 5, 2009. At the July 2, 2009 Open Meeting, Oncor agreed to extend the jurisdictional deadline
to August 31, 2009. Oncor implemented its new rates on September 17, 2009 based on the Commission's August 31, 2009 Order.
Motions for rehearing were filed by the State of Texas, Oncor Delivery Company, LLC., Alliance of TXU/Oncor Customers,
Office of Public Utility Counsel, Steering Committee of Cities, Texas Industrial Energy Consumers, on September 21, 2009.
Commission Staff and Texas Industrial Energy Consumers filed responses to the motions for rehearing on September 30, 2009.
On October 8, 2009, the Commission issued an order extending time to act on motions for rehearing to the maximum time
allow by law.
At the October 22, 2009 Open Meeting, the Commission raised the issue of what applicability, if any, does the Texas Supreme
Court's holding in Suburban Utility Corporation v. Public Utility Commission of Texas 4 have on the federal income tax issues in
this proceeding. The Suburban court held that a subchapter S corporation 5 “is entitled to a reasonable cost of service allowance
for federal income taxes actually paid by its shareholders on [the utility's] taxable income or for taxes it would be required to pay
as a conventional corporation, whichever is less.” 6 The Commission requested briefing on the Suburban case in its October
22, 2009 Open Meeting and a briefing order was issued that day. Responses were filed October 29, 2009 and the Commission
addressed the issue during its November 5, 2009 Open Meeting.
New findings of fact 35B, 35C, and 35D are added to reflect this additional procedural history.
Additionally, Chairman Smitherman filed a memorandum on October 22, 2009 wherein he proposed twelve modifications in
response to Oncor's motion for rehearing. These modification are adopted by the Commission. Accordingly, findings of fact 14,
35, 36, 66, 70, 112, 133, and 134 are deleted and replaced with new findings of fact 14A, 35A, 36A, 66A, 70A, 112A, 133A,
and 134A; and ordering paragraph 7 is modified to properly reflect or clarify the Commission's decision as discussed in the
Chairman's memorandum. New findings of fact 128B and 174A and new conclusion of law 19B are discussed later in this Order.
II. DISCUSSION
A. Cash Working Capital (CWC)
The Commission disagrees with the ALJs' finding that Oncor's requested cash working capital (CWC) should be reduced by
$2,453,665 to remove Oncor's allowance for expenses covering employee home-purchase plans and employee home loans for
the purchase of energy-efficiency items and appliances. The Commission agrees with Oncor's position that P.U.C. SUBST.
R. § 25.231(c)(2)(B)(iii)(IV)(e) specifically provides that working cash funds like those Oncor proposed should be included
in the CWC calculations. 7 The Commission further agrees that Oncor's overall level of employee compensation, including
employee benefits, is designed to be competitive and is reasonable and necessary to allow the Company to attract qualified
and experienced personnel required to provide safe and reliable electric service. 8 The Commission finds that the expenses are
reasonable and necessary and that Oncor should have the discretion to offer these options as part of the compensation program
for Oncor employees. The Commission therefore reverses the recommendation in the PFD 9 and allows Oncor to recover the
$2,453,665 in its CWC allowance.
Finding of fact 71 is deleted and new finding of fact 71A is added to reflect the Commission's decision.
B. Plant Held for Future Use (PHFU)
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The ALJs found that Oncor's proposed plant held for future use (PHFU) should be reduced by $12,639,442 because Oncor has
not provided a credible plan that the properties are going to be placed in service within ten years. The Commission disagrees.
Oncor requested a PHFU level of $17,110,015. The Alliance of TXU/Oncor customers (ATOC) contested this number and
identified several parcels totaling $12,639,442 that should be removed from the PHFU because they had continuously moving
in-service dates. The Commission finds that Oncor presented a credible plan for these parcels and that companies that are in
Oncor's position need to have flexibility to move items in and out of their plans.
Findings of fact 73 and 74 are deleted and new findings of fact 73A, 73B and 74A are added to reflect the Commission's decision.
C. Capgemini Energy (CGE) Charges to Oncor
The ALJs recommended the disallowance of $5,673,205.90 in Capgemini Energy (CGE) charges to Oncor based on the
determination that there was a “possibility that the $88 million included some disputed charges,” and the concern that Oncor did
not prove the reasonableness of additional resource charges (ARC) representing that amount. The Commission reverses the PFD
to modify the amount disallowed to $1,433,094.47. The Commission is persuaded by Oncor's arguments that the disallowed
$5,673,205.90 was based on the ALJs' incorrect determination of the record. The Commission agrees with Oncor that there is no
record evidence to support the conclusion that the disallowed $5,673,205.90 represented disputed charges. The $1,433,094.47
reflects Oncor's acknowledgement that it was credited $16,008,942.33 in the separation agreement with CGE for disputed and
undisputed charges and that the $1,433,094.47 disallowance is Oncor's estimate of the amount of CGE charges that should be
disallowed associated with the test-year. 10
Finding of fact 111 is deleted and new finding of fact 111A is added to reflect the Commission decision to modify the disallowed
amount.
D. Account Code 365 - Distribution Overhead Conductor
On the issue of net salvage value for Account 365, Distribution Overhead Conductors, the ALJs found the preponderance of the
evidence supports that a negative 40% net salvage rate would be appropriate as argued by ATOC. Oncor argued that because the
average net salvage value for the last 10 years was negative 54%, a negative 55% net salvage was appropriate as a conservative
estimate of the ongoing removal cost in this account. 11 Commission Staff advocated a negative 53% net salvage based on
a gross salvage of 5% and cost of removal of 58% for 1998 through 2007. 12 ATOC also noted that Oncor had experienced
three or four of the worst storms in its history between 2004 and 2007, which would have driven up the cost of removal. The
Commission finds that the preponderance of the evidence weighs in favor of the net salvage values of negative 54% as proposed
by both Oncor and Commission Staff and reverses the PFD on this point.
Finding of fact 124 is deleted and new finding of fact 124A is added to reflect the Commission's decision.
E. Suburban Holding
In Suburban Utility Corporation v. Public Utility Commission of Texas, 13 the Texas Supreme Court held that Suburban Utility,
a subchapter S corporation, 14 “is entitled to a reasonable cost of service allowance for federal income taxes actually paid
by its shareholders on [the utility's] taxable income or for taxes it would be required to pay as a conventional corporation,
whichever is less.” 15 Oncor argued that because the actual taxes-paid doctrine was subsequently disavowed by the supreme
court, 16 the only viable portion of the Suburban holding required that its tax expense be calculated as if it were a conventional
corporation. 17 All the other parties argued that the holding in Suburban was still valid and requires that Oncor's tax expense
be based on the actual tax expense paid by Oncor's shareholders. 18
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The Commission agrees with the supreme court that there is no such thing as actual taxes in a ratemaking proceeding. 19 As the
court noted, rates are based on historic test-year amounts, but those amounts are adjusted and modified during the rate setting
process, or are based on assumptions. 20 In addition, although not mentioned by the court, the amount of income tax expense
as typically calculated is directly related to the return on equity set by the Commission, a return that the utility will almost
certainly never obtain-either missing it on the high side or the low side. Thus, “[t]he income tax calculation is no different than
other elements of utility ratemaking.” 21 In setting rates, the Commission has considerable discretion.
Consequently, the Commission concludes that, under Suburban, it must make an allowance for taxes but that, under GTE-
Southwest and subsequent cases, it has discretion to determine the appropriate method and amount. The Commission recognizes
that PURA limits its discretion. For example, the Commission cannot consider disallowed expenses in setting rates; 22 the rates
it sets must be just and reasonable, 23 but cannot be unreasonably preferential or discriminatory; 24 and the rates must provide
“overall revenues . . . that will permit the utility a reasonable opportunity to earn a reasonable return on the utility's invested
capital .. . in excess of the utility's reasonable and necessary operating expenses.” 25 Even with these statutory limitations, the
Commission has considerable discretion.
Oncor is a limited liability corporation (LLC) organized under Delaware law. It is taxed as a partnership under federal law
and is therefore not currently eligible to file a consolidated tax return with Energy Future Holdings (EFH). 26 Additionally, the
Commission determines Oncor's status to be that of a ring-fenced utility that has entered into a tax sharing agreement with EFH
and its affiliates that requires Oncor to function as a stand-alone company. The tax sharing agreement was created in October
2007 in an effort to insulate Oncor from the liability related to EFH and its affiliates. The Commission concludes that Oncor
should be treated as a stand-alone company.
Because the Commission determines that Oncor should be treated as a stand-alone and ring-fenced company, the Commission
concludes that Oncor's tax expense should be calculated as if it were a conventional corporation. This treatment will afford
Oncor with a reasonable amount for tax expense, including federal income tax and other state taxes. Further, while the record
is not fully developed on this point, it appears that the amount allowed for federal income tax expense would not differ greatly
from the expense that would be allowed using the tax rates of Oncor's shareholders considering only the income and expenses
resulting from Oncor's operation as a utility. 27
Even though the tax expense allowed by the Commission will not differ in amount from the amount requested by Oncor under its
tax-sharing agreement, the Commission emphasizes that it is not basing its decision on the tax-sharing agreement between Oncor
and Energy Future Holdings Corporation (EFH). The Commission has never been expressly asked to consider and approve
that agreement, it has not previously approved that agreement, and it is not doing so here. While this agreement provides some
benefits to isolate Oncor from its shareholders, neither Oncor nor any other utility can bind the Commission to establish a tax
expense in a rate proceeding through a bilateral contract that has not been approved by the Commission. .
F. Consolidated Tax Savings Adjustment (CTSA)
The Commission reverses the ALJs' determination that it was appropriate for Oncor to include a consolidated tax savings
adjustment (CTSA) in its federal income tax expense calculations. The Commission is required-unless it is shown to be
reasonable not to do so-to calculate a utility's income tax expense “as though a consolidated return had been filed and the utility
had realized its fair share of the savings resulting from that return, if:” (1) the utility is a member of an affiliated group eligible
to file a consolidated return; and (2) it is advantageous for the utility to do so. 28 The Commission finds that Oncor is not
currently a member of an affiliated group eligible to file a consolidated tax return; and therefore, the provisions of PURA §
36.060 do not apply to it.
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The Commission's CTSA decision in this proceeding is not based on Oncor's tax-sharing agreement with EFH and its affiliates.
Rather, it is limited to the Commission's determination that the statutory requirements to include a CTSA are not met.
To reflect the Commission's decisions regarding tax expenses, finding of fact 128 is deleted and new findings of fact 128A-F
are added. Findings of fact 129 and 130 are deleted consistent with the Commission's finding that a consolidated tax savings
adjustment is not applicable to Oncor. Additionally, conclusion of law 19 was deleted and replaced with new conclusions of
law 19A-D to reflect the Commission's legal conclusion on this point.
G. State and Local Taxes - Texas Gross Margin Tax
The Commission reverses the ALJs determination that Oncor must compute its gross margin tax as an affiliate. Consistent with
the Commission's decision regarding taxes, the Commission finds that Oncor is not a member of an affiliated group and Oncor
should calculate its Texas gross margin tax on a stand-alone. Further, the Commission notes that its decision is not based on
the tax-sharing agreement.
To reflect the Commission's decision on the Texas gross margin tax issue, finding of fact 132 is deleted and new finding of
fact 132A is added.
H. State and Local Taxes - Municipal Franchise Fees
The Commission disagrees with the ALJs' interpretation of PURA § 33.008 and reverses the ALJs' findings and conclusions
regarding municipal franchise fees. Oncor requested recovery of municipal franchise fees totaling $253,884,976. Commission
Staff challenged this amount and recommended a reduction of $5,696,931. 29 According to Commission Staff, Oncor is not
entitled to recover the 5% increase in the franchise fee rate that it agreed to pay pursuant to an agreement with Cities. 30
The Commission agrees with Commission Staff's interpretation that PURA § 33.008(b) specifies how to calculate municipal
franchise fees owed by a utility to municipalities within its service territory. 31 Since Oncor agreed to pay its municipalities 5%
more than the 2005 effective rate calculated pursuant to PURA § 33.008(b), it is not an expense that is reasonable and necessary
to provide service to the public. 32 The Commission also notes its concern over allowing ratepayers who reside outside of the
Cities' jurisdiction to pay for franchise fees calculated in an agreement to which their city or municipality was not a party.
Finding of fact 133 is deleted and new finding of fact 133A is added to reflect the Commission's decisions regarding municipal
franchise fees.
I. Automated Meter Recovery
Regarding the issue of automated meter recovery, the ALJs determined that 41.82% of Oncor's investment in automated meters
should not be recovered. Oncor requested the inclusion of $93,185,786.07 in plant-in-service for its powerline carrier (PLC)
and broadband-over-powerline carrier (BPL) meters. Commission Staff, ATOC, and Cities argued that Oncor's purchase and
installation of automated meters between 2004 and the adoption of the advanced metering system (AMS) rule on May 30, 2007
was partly or entirely imprudent, and recommended disallowing all or part of that investment.
Oncor pointed to national and state legislative initiatives that Oncor believed supported and encouraged its deployment of
advanced metering systems and Oncor's continued deployment of its PBL and PLC meters. 33 Additionally, Oncor cited a
discussion among Commissioners Hudson, Parsley, and Smitherman at the Commission's May 8, 2007 Open Meeting in which
the Commissioners strongly encouraged the deployment of BPL meters. 34 The Commission agrees with Oncor's position
and finds that Oncor did have significant encouragement from the Commission in deploying both PLC and BPL meters. The
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Commission further finds that Oncor acted prudently and in accordance with the information they had at the time. Therefore,
the Commission allows Oncor to recover the full costs of its BPL and PLC meters.
To give effect to the Commission's decisions regarding automated metering, findings of fact 141, 144, 145, 147, 149, 150,
151, 152 and 153 are deleted and new findings of fact 141A, 153A, and 153B are added. Additionally, conclusion of law 21 is
deleted and new conclusion of law 21A is added to reflect the Commission's legal conclusion regarding the prudence standard
set out in Application of Gulf States Utilities for Authority to Change Rates, Docket No. 6525 (Oct. 15, 1986).
J. Creation of Primary Substation Rate Class
The Commission disagrees with the ALJs' recommendation to deny Oncor's request to create a new primary substation rate
class 35 and approves the creation of a new primary-greater-than-10-kW substation tariff. This new service affects about 50
primary substation customers, mostly industrial customers, receiving voltage from, or near, a substation. These customers
construct and maintain the distribution facilities themselves. The only distribution facilities required by Oncor to provide this
service are the distribution substation facilities. Additionally, the service is virtually identical to the service provided to current
wholesale customers from Oncor's existing XMFR tariff. The Commission notes that Oncor implemented its current rates on
September 17, 2009. Those rates reflect the Commission's August 31, 2009 Order which did not provide for the primary-greater-
than-10-kW substation tariff. Therefore, rate adjustments required to reflect the Commission's decision on rehearing shall be
prospective from the date of the final order in this proceeding. Findings of fact 155, 156 157, 158, 159, and 160 are deleted
and new findings of fact 155A, 156A, 157A, 158A, 159A, 160A, and 160B are added to reflect the Commission's decisions
regarding the creation of a new primary substation rate class.
K. Cost Allocation - Direct Assignment of Cost to Wholesale Customers
The PFD indicates that Oncor should maintain data adequate for the direct assignment of costs to those wholesale classes and
to prepare a cost-of-service study using direct assignment for those classes in its next rate case. 36 The Commission clarifies
this point so as to order Oncor to maintain data adequate for direct assignment of costs to wholesale classes. However, the
Commission believes that the direct assignment of such costs should be conducted in a broader forum than a rate-setting
proceeding.
Findings of fact 173 and 174 are deleted and replaced with new findings of fact 173A and 174A to clarify the Commission's
position regarding direct assignment of costs to wholesale classes of customers.
In addition to the changes addressed above, the Commission notes that other minor, non-substantive corrections and
modifications to the ALJs' proposed findings of fact and conclusions of law were made.
III. FINDINGS OF FACT
Introduction and Procedural History
1. Oncor Electric Delivery Company, LLC (Oncor), formerly TXU Electric Delivery Company, is an investor-owned electric
utility within the Electric Reliability Council of Texas (ERCOT) system.
2. Oncor provides transmission and distribution electrical services in the northeast to central and west Texas, including the
Dallas-Fort Worth Metroplex area. Oncor delivers electricity to three million meters that reach close to seven million consumers
in 401 cities and 91 counties in Texas.
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3. Oncor is the largest transmission and distribution utility (T&D) company in Texas and is the sixth largest T&D in the United
States.
4. As part of the unbundling cost of service hearings, in 2001, Oncor's costs of services were separated for accounting purposes
between its transmission and distribution functions and its rates were set among various classifications.
5. On February 25, 2007, Oncor's former parent company, TXU Corp., entered into an Agreement and Plan of Merger with Texas
Energy Future Holding Limited Partnership (TEF) and Texas Energy Merger Sub Corp (Merger Sub) (the merger agreement).
6. Pursuant to the merger agreement, TEF acquired TXU Corp and changed TXU Corp.'s name to Energy Future Holdings
Corporation (EFH).
7. Oncor became a wholly owned subsidiary of Oncor Electric Delivery Holdings Company LLC, which is a member of the
EFH system of companies.
8. On October 10, 2007, Oncor entered into a tax sharing agreement (the tax sharing agreement) with EFH in an effort to insulate
Oncor from the liabilities related to EFH and its affiliates.
9. The tax sharing agreement benefits both Oncor's shareholders and ratepayers.
10. The Commission approved the merger agreement in Joint Report and Application of Oncor Electric Delivery Company and
Texas Energy Future Holding Limited Partnership Pursuant to PURA 14.101, Docket No. 34077 (April 24, 2008).
11. On November 5, 2008, EFH sold 19.95% of Oncor to investors from Canada and Singapore for $1,254,000,000.
12. In 2008, Oncor became a Delaware Limited Liability Corporation.
13. On June 27, 2008, Oncor filed its application with the Public Utility Commission of Texas for authority to increase its
transmission and distribution rates to achieve an increase in revenue of approximately $275 million.
14. DELETED.
14A. Oncor revised its proposed revenue requirements in its 45-day update to the rate filing package (August 11, 2008), its
Supplemental Direct Testimony (October 3, 2008), it's Rebuttal Testimony (December 23, 2008) and its Omnibus errata Filing
(January 9, 2009), and is now requesting increased revenue of approximately $253,468,000.
15. Of this amount, retail distribution service revenues would increase approximately $210,000,000, and transmission revenues
would increase approximately $44,000,000.
16. Concurrent with its filing with the Commission, Oncor filed a similar petition and statement of intent with each incorporated
city in its service area that has original jurisdiction over its retail rates.
17. Oncor provided notice by publication once a week for four consecutive weeks before the effective date of the proposed rate
change in newspapers having general circulation in each county in Oncor's service territory.
18. Individual notice of Oncor's application was provided to the Commission Staff and the Office of Public Utility Counsel
on June 27, 2008.
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19. On June 27, 2008, Oncor sent a copy of its petition and statement of intent by hand-delivery to each municipality within
Oncor's service area with original jurisdiction.
20. Oncor timely served notice by either hand-delivery or over-night delivery of its complete rate filing package and compact
disc to all authorized representatives of the parties in Petition by Commission Staff for a Review of the Rates of TXU Electric
Delivery Company, Docket No. 34040 (June 30, 2008).
21. On June 27, 2008, Oncor mailed notice of its petition and statement of intent to all authorized representatives of the parties
in Joint Report and Application of Oncor Electric Delivery Company and Texas Energy Future Holdings Limited Partnership
Pursuant to PURA § 14.101, Docket No. 34077 (April 24, 2008).
22. On June 27, 2008, Oncor mailed notice of its petition and statement of intent to all Retail Electric Providers (REPs) who
have been certified by the Commission and who serve end-use customers in Oncor's service area and to all entities listed in the
Commission's transmission matrix in Docket No. 35011.
23. The Commission referred this proceeding to SOAH on July 1, 2008. On August 6, 2008, the Commission issued its
preliminary order setting forth the issues to be addressed in this proceeding.
24. The following entities were granted intervenor status in this case: Alliance of TXU/Oncor Customers (ATOC); Steering
Committee of Cities (Cities); International Brotherhood of Electrical Workers Local 69 (IBEW); Lee Smith; Alliance for Retail
Markets (ARM); Texas Industrial Energy Consumers (TIEC); Denton Municipal Electric; State of Texas; Occidental Power
Marketing, L.P.; Office of Public Utility Counsel; Texas Association for Marketers (TEAM); Tex-La Electric Cooperative
of Texas, Inc.; Rayburn Country Electric Cooperative; City of Garland; Texas Legal Services Corporation/Texas Ratepayers
Organization to Save Energy (TLSC/TxRose); TXU Energy Retail; Kroger Company; Reliant Energy Retail Services, LLC;
Nucor Steel-Texas (Nucor); Environmental Defense Fund (EDF); the Commercial Group; and Centerpoint Energy Houston.
25. Oncor timely filed appeals with the Commission of the rate ordinances of the municipalities exercising original jurisdiction
within its service territory. All such appeals were consolidated for determination in this proceeding.
26. On September 11, 2008, State moved for partial summary disposition regarding Oncor's request to modify its base rate
discount for state institutions of higher learning.
27. The Administrative Law Judge (ALJ) issued a proposal for decision addressing State's motion for partial summary
disposition on November 13, 2008, recommending that the Commission grant State's motion.
28. On January 30, 2009, the Commission partially rejected the ALJ's recommendation and issued an Order ruling against
State finding also that Oncor was not allowed to provide the 20% discount to institutions of higher education at the expense
of ratepayers.
29. On February 17, 2009, State filed a request to reconsider the order with the Commission.
30. Commission Advising and Docket Management refused to ballot the Commissioners on State's motion because State's
request for reconsideration was untimely filed.
31. State filed a motion for leave to late file its motion for reconsideration on February 17, 2009. The Commissioners voted
not to hear State's motion.
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32. On January 2, 2009, Oncor's request that its rate case expenses be severed from this docket was granted. The severed matter
was assigned Application of Oncor Electric Delivery Company LLC for Rate Case Expenses Pertaining to PUC Docket No.
35717, Docket No. 36530.
33. Oncor's application is based on the test year ending December 31, 2007.
34. The hearing on the merits began on January 13, 2009, and lasted seventeen hearing days, concluding on February 9, 2009.
35. DELETED.
35A. Oncor's proposed effective date for the proposed rates was suspended by the SOAH ALJs for 150 days. Oncor agreed
to further extend the effective date for its proposed rates until July 15, 2009, and then again until August 31, 2009, to allow
sufficient time for the ALJs and the Commission to process the case.
35B. Oncor implemented its new rates on September 17, 2009, based on the Commission's August 31, 2009, Final Order.
35C. Motions for rehearing were filed on September 21, 2009, and on October 8, 2009, the Commission issued an order
extending time to act on motions for rehearing to the maximum time allow by law.
35D. The Commission issued an order requesting briefings on the Suburban case after the October 22, 2009 Open Meeting,
and subsequent to receiving responses from the parties, considered the issue in the November 5, 2009 open meeting.
Rate Base
36. DELETED.
36A. Oncor's T&D capital investments in the amount of $7,881,760,603 net plant in service (including investments currently
being recovered through Oncor's transmission cost of service), were used and useful, and reasonable and necessary, and should
be approved.
37. Accumulated Deferred Federal Income Taxes (ADFIT) represent a timing difference in the amortization or depreciation of
an asset that differs from the tax amortization or depreciation.
38. ADFIT operates as a reduction to the rate base, or invested capital, upon which the rate of return may be applied.
39. Oncor withdrew its proposed adjustment to ADFIT for liberalized depreciation expenses.
40. Oncor's ADFIT amounts should be adjusted to increase Oncor's ADFIT by $50,228,784 to reverse Oncor's reduction to the
ADFIT for liberalized depreciation.
41. Oncor's ADFIT includes a $43,539,628 deferred tax asset for its current and non-current alternative minimum tax (AMT)
credits, thereby increasing the rate base.
42. To ensure that some federal income taxes are paid each year, federal income tax (FIT) returns must be calculated two ways
each year, the regular tax return method and the AMT method.
43. The current income tax is paid based on the taxing method (regular tax or AMT) that yields the highest tax liability. Taxes
paid on an AMT basis generate AMT credits that can be used to offset future regular taxable liability.
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44. During the test year, Oncor did not file its own tax return, but instead prepared its FIT records and forwarded them to EFH,
the holding company, and EFH filed a consolidated tax return.
45. The EFH consolidated group had to file its tax returns under the AMT method from 1992 to 2008 causing Oncor's AMT
credits to accumulate.
46. As a result of the tax savings agreement entered into on October 10, 2007, Oncor prepared and calculated its FIT return
as though it is a stand-alone corporation.
47. Unless expressly provided for in PURA, the Commission rules, or approved in a Commission order, agreements between
a regulated utility and its parent company do not alone dictate how rates are set.
48. Oncor's tax sharing agreement is not binding on the Commission.
49. Ratepayers paid Oncor's FIT expenses calculated at the regular tax rate irrespective of how Oncor, or EFH, actually paid
the IRS and irrespective of what tax method was used by EFH to calculate the taxes.
50. FIT expenses must be normalized so that the tax effects of income and expenses are recognized at the same time that the
related income and expenses are incurred.
51. AMT credits (deferred tax asset) represent a prepayment of regular federal income taxes.
52. The accumulated AMT credits represent a cost to Oncor for its participation in the EFH consolidated group that should
not be charged to the ratepayers.
53. Oncor's AMT credits totaling $43,539,628 should be removed from its ADFIT balance.
54. In June 2006, the Financial Accounting Standard Board (FASB) issued Financial Interpretation 48 (FIN 48), “Accounting
for Uncertainty in Income Taxes,” requiring companies to identify each uncertain tax position by evaluating the tax position
on its technical merits to determine whether the tax position, and the corresponding deduction, is more-likely-than not to be
sustained by the Internal Revenue Service (IRS).
55. FIN 48 became effective on January 1, 2007, and requires companies with uncertain tax positions to remove the amount
from the ADFIT and record it as a potential liability with interest to better reflect the company's financial condition.
56. During the test year, Oncor conducted a FIN 48 analysis and determined that $96,972,460 did not meet the FIN 48 standard.
Oncor reclassified the tax benefit from an ADFIT to a non-current reserve that accrues the IRS prescribed interest.
57. The Commission requires a utility to use the Federal Energy Regulatory Commission (FERC) chart of accounts in preparing
its rate filing package.
58. Recognizing the competing needs between financial reporting unrelated to ratemaking, and reporting for ratemaking, FERC
issued a policy statement in May 2007 stating that utilities are not to follow FIN 48 for financial accounting and reporting
submitted to FERC.
59. The IRS may not audit or reverse Oncor's position as to the tax deductions identified as FIN 48 deductions and moved
into the FIN 48 reserve.
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60. Oncor may not have to pay the IRS the FIN 48 deductions of $96,972,460; and therefore, they should be added back into
the ADFIT for ratemaking purposes.
61. Oncor properly included its ADFIT assets for pension, other postemployment benefits (OPEBs), and FAS 112 liabilities
in its ADFIT balance.
62. Investor-owned electric utilities may include a reasonable allowance for cash working capital (CWC) in the rate base as
determined by a lead-lag study conducted in accordance with the Commission's rules.
63. In Oncor's last rate case, the Commission approved CWC of a negative $73,955,000. In this rate case, Oncor requested a
positive CWC allowance of $1,370,010.
64. CWC represents the amount of working capital, not specifically addressed in other rate base items, that is necessary to fund
the gap between the time expenditures are made and the time corresponding revenues are received.
65. Oncor's calculation of its lead days for vegetation management (a positive 123.22) was unreasonable in that Oncor estimated
that the service period for tree trimming and other vegetation management extended a year beyond when the trees were trimmed.
66. DELETED.
66A. The service period for non-labor, other-third-party expenses is the actual period in which the services are provided and
therefore Oncor's expense lead days for vegetation management should be a negative 36.02.
67. Oncor's CWC for vegetation management expenses is $1,163,317, not the $12,397,196 requested.
68. Oncor's request for a negative 11.75 lead days for its pension expenses is reasonable.
69. Oncor's payment of the invoice for a year-long meter maintenance contract was not a prepayment and was properly included
in Oncor's CWC allowance.
70. DELETED.
70A. Commission Staff's recommendation regarding the calculation of lead days related to the State Gross Margin Tax should
be adopted and the amount of lead days should be changed from Oncor's proposed positive 46.42 days to a negative 319.58
lead days.
71. DELETED.
71A. Oncor's inclusion of $2,453,665 in its CWC allowance for expenses covering employee home purchase plans and employee
loans for the purchase of energy-efficiency items and appliances is reasonable and should be approved.
72. Oncor's decision to withdraw from the accounts receivable financing program was financially reasonable and in the best
interest of the ratepayers.
73. DELETED.
73A. Oncor's plant held for future use (PHFU) proposed in its rate base included PHFUs for which Oncor had a credible plan
for use within a ten-year period.
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73B. Companies in Oncor's position need to have flexibility to move items in and out of their plans.
74. DELETED.
74A. Oncor's proposed PHFU level of $17,110,015 is reasonable and should be granted.
75. Oncor included in its regulatory assets $20,274,840.00, the costs it incurred in restructuring efforts undertaken in 2004 and
2006 to reduce labor and related costs, and requested that it be amortized over a five-year period, $4,054,968 per year.
76. While Oncor's restructurings efforts may have reduced its O&M expenses and capital spending, Oncor did not use these
savings to defray costs associated with the restructuring.
77. Oncor's restructuring expenses were not incurred in the test year, were not authorized by PURA or a Commission rule or
preapproved by the Commission, and the recovery of which were not shown to be essential to its financial integrity.
78. Oncor's restructuring expenses undertaken in 2004 and 2006 to reduce labor and related costs in the amount of $20,274,840
are not regulatory assets and should not be included in Oncor's rate base.
79. Oncor's request to include in its rate base as regulatory assets $46,975,122 for deferred pension costs and $37,906,425 for
deferred OPEB costs was reasonable and should be adopted.
80. Oncor properly included $50,809,942 as the cost of materials and supplies in its rate base.
81. Oncor's prepayments of $79,974,656 were reasonable and should be included in its rate base.
Return on Equity and Capital Structure
82. A return of equity of 10.25% will allow Oncor a reasonable opportunity to earn a reasonable return on its capital investment.
83. Oncor's energy conservation efforts, the quality of its services, the efficiency of its operations, and the quality of its
management support a 10.25% return on equity.
84. A reasonable application of the discounted case flow model, capital asset pricing model, risk premium study, and comparable
earnings study support a return on equity of 10.25%.
85. A 10.25% return on equity is consistent with the level of financial risk associated with Oncor's capital structure.
86. Oncor's revised cost of debt, 6.97%, is reasonable.
87. The appropriate capital structure for Oncor is 60% long-term debt and 40% common equity.
88. Oncor has used this capital structure since 2002.
89. The capital structure of 60% and 40% is consistent with Commission precedent for T&D utilities.
90. Oncor's overall rate of return is as follows:
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COMPONENT CAPITAL STRUCTURE COST OF CAPITAL WEIGHTED AVG COST OF
CAPITAL
LONG-TERM CAPITAL 60.00% 6.97% 4.18%
COMMON EQUITY 40.00% 10.25% 4.10%
TOTAL 100.00% 8.28%
Cost of Service
91. Oncor included in its cost of service $19,573,479 for incentive compensation paid to its employees in the test year.
92. Incentive compensation based on financial measures or goals is of more immediate benefit to shareholders.
93. Of the amount Oncor requested for incentive compensation, $5,082,326 should be removed because it is related to financial
measures that are unreasonable and unnecessary for the provision of T&D utility services.
94. Oncor reasonably calculated overtime expenses for the test year that are representative of its current and future work
demands.
95. Oncor's one-time allocation of the pension and OPEB obligations, assets, and liabilities to comply with PURA § 36.065
were reasonable.
96. Oncor's FAS 87 pension costs for its qualified plan in the amount of $21,072,201 and for its nonqualified in the amount
of $4,185,542 were reasonable and necessary.
97. Oncor's FAS 106 OPEB costs of $40,964,443 were reasonable and necessary.
98. Oncor's self-insurance plan with its threshold levels is in the public interest, is a lower cost alternative to purchasing
commercial insurance, and provides its ratepayers the benefit of the savings.
99. In computing rates, liability insurance for self-insured utilities does not include liability coverage for intentional torts or
for employee misconduct such as discrimination.
100. A liability and catastrophic property damage loss self-insurance program with an annual accrual of $ 33,284,430.45 and
a target reserve of $66,568,860.90 is in the public interest.
101. The annual amortization figure calculated to cover Oncor's self-insurance reserve deficit over the next seven years is
$20,417,612.29.
102. Oncor's affiliate entities, specifically EFH Corporate Service Company, EFH Properties Company, Luminant Generation
Company LLC, Current Communications of Texas, L.P., TXY Energy Retail Company LLC, TXU Receivable Company, EFH
Vermont Insurance Company, and EFH CG Holdings Company L.P., provided services to Oncor during the test year.
103. After adjustments agreed to during the hearing, Oncor requested affiliate-related O&M expenses of $21,734,501.
104. Oncor's affiliate-related expenses should be reduced by an additional $2,008,538, leaving remaining expenses of
$19,725,963.
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105. Oncor's affiliate-related O&M expenses of $19,725,923 were reasonable and necessary and were not higher than charges
to a third party or other affiliate for the same class of items.
106. During the test year, Oncor outsourced several business functions to Capgemini Energy LP (CGE) including information
technology, customer care, revenue management, supply chain, finance and accounting, and human resources.
107. Oncor's contract with CGE used a combination of fixed and variable pricing, with the fixed pricing, called “Base Charge”
being used for a predetermined scope and volume of services called the “In-Scope Baseline Services.”
108. For services provided beyond the in-scope baseline services, Oncor paid CGE additional fees in the form of additional
resource charges (ARCs) and project charges. If Oncor used fewer in-scope services than the baseline, it received a credit in
the form of reduced resource credits (RRCs).
109. Oncor requested recovery of $88,468,803 in the test year for CGE costs.
110. During the test year Oncor terminated its contract with CGE because Oncor was dissatisfied with that relationship and
entered into a termination agreement.
111. DELETED.
111A. The total disputed ARC and project charges for the test year were $1,433,094.47. These charges should be disallowed
making $87,035,705.53 the reasonable amount of outsourced expenses for 2007.
112. DELETED.
112A. It is reasonable for Oncor's cost of service to include $53,578,615 in energy-efficiency expenses for the test year.
113. Oncor's and its predecessors' depreciation rates have not been changed in 15 years.
114. The net salvage component for Oncor's transmission assets has remained unchanged for 15 years.
115. Except to the extent set forth in the findings of fact below, Oncor's depreciation analysis was the most thorough and reliable.
116. Oncor's proposed service lives are reasonable and should be used to set depreciation rates, except as set forth in the findings
of fact below.
117. Oncor's land rights and easements associated with transmission lines and transmission substations (FERC Account 350)
have an average service life of 100 years, not the 70 years proposed by Oncor.
118. The average service life for Oncor's distribution substations (FERC Account 362) is 50 years as recommended by
Commission Staff, not the 48 years proposed by Oncor.
119. The average service life of Oncor's distribution poles, towers, and fixtures (FERC Account 364) is 41 years as proposed
by ATOC, not the 38 years proposed by Oncor.
120. Net salvage value is the amount received for retired property (salvage) minus the cost to remove and sell the property.
121. Oncor's proposed net salvage values are reasonable and should be used to set depreciation rates, except as set forth below.
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122. The net salvage value of negative 33% for Oncor's T&D Structures and Equipment (FERC account 352/361) is the most
reasonable of those proposed and should be adopted.
123. The net salvage value of a negative 34% for Oncor's Transmission Towers and Fixtures (FERC account 354) is the most
reasonable and should be adopted.
124. DELETED.
124A. The net salvage value of negative 54% for Oncor's distribution overhead conductor (FERC account 365) is reasonable
and should be adopted.
125. The net salvage value of negative 50% for Oncor's distribution underground conduit (FERC account 366) is reasonable
and should be adopted.
126. The net salvage value of negative 5% for Oncor's distribution underground conductor (FERC account 367) is reasonable
and should be adopted.
127. The prudent portion of Oncor's meter investment should be depreciated over an 11-year period.
128. DELETED.
128A. Oncor is not currently a member of an affiliated group eligible to file a consolidated federal income tax return.
128B. Oncor is a ring-fenced utility that has entered into a tax sharing agreement with EFH and its affiliates that requires Oncor
to function as a stand-alone company.
128C. The Commission has neither addressed nor approved the tax-sharing agreement Oncor entered into with EFH and its
affiliates.
128D. It is appropriate to treat Oncor as a stand-alone, conventional corporation for the purpose of determining its tax expenses.
128E. It is appropriate to determine Oncor's federal income tax expense included in its revenue requirement as if it were a
stand-alone, conventional corporation.
128F. The Commission is not determining Oncor's federal income tax expense on the basis of its tax-sharing agreement with
EFH.
129. DELETED.
130. DELETED.
131. Ad valorem property taxes as proposed by Oncor are reasonable and necessary expenses.
132. DELETED.
132A. Texas gross margin taxes in the amount of $17,338,957 are reasonable and necessary expenses.
133. DELETED.
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133A. Municipal franchise fees in the amount of 241,841,439 are reasonable and necessary expenses.
134. DELETED.
134A. Payroll taxes in the amount of $11,458,074 are reasonable and necessary expenses.
135. Under the Advanced Metering System (AMS) deployment plan approved in Oncor Electric Delivery Company LLC's
Request for Approval of Advanced Metering System (AMS) Deployment Plan and Request for AMS Surcharge, Docket No.
35718 (August 29, 2008), Oncor is scheduled to replace virtually all its existing conventional and automated meters with
advanced digital meters by the end of 2012.
136. The AMS surcharge proceeding was conducted in accordance with P.U.C SUBST. R. 25.130, which was adopted effective
May 30, 2007.
137. Some form of automated metering has been available for twenty years or so. In 2004, however, Oncor began an initiative
to replace its existing conventional meters with automated meters.
138. To implement its goal, Oncor chose three kinds of meters and associated infrastructures: powerline carrier (PLC),
broadband over powerline (BPL), and radio frequency (RF). PLC meters have been deployed in some of Oncor's less densely
populated service areas; BPL meters have been deployed in some more densely populated service areas. RF meters had not
yet been deployed at the end of the test year.
139. Oncor has about 590,000 automated meters currently operating on its system. The Company also has many conventional
meters still in place.
140. The Commission initiated its advanced metering rulemaking on July 26, 2005. The first workshop took place in September
2005 and a second in October 2005, with the Commission soliciting written comments to its questions on advanced metering
on December 21, 2005.
141. DELETED.
141A. The AMS rule contains a waiver provision in § 25.130(g)(1)(C), which encompasses those PLC and BPL meters installed
by Oncor that did not meet all of the functionality requirements.
142. In May 2007, after adoption of the final AMS rule, Oncor ceased purchasing PLC and BPL meters and canceled a pending
order for BPL meters.
143. The advanced meters are significantly technologically superior to the automated BPL meters, and presumably to the PLC
meters as well.
144. DELETED.
145. DELETED.
146. Oncor intended to avail itself of the AMS rule's surcharge provisions, as shown by its participation throughout the
rulemaking process.
147. DELETED.
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148. A prudent manager would not necessarily have ceased the automated metering program after the September 2005
workshop.
149. DELETED.
150. DELETED.
151. DELETED.
152. DELETED.
153. DELETED.
153A. Oncor's automated meter investment should be allowed.
153B. Oncor had significant encouragement from the Commission to deploy both PLC and BPL meters.
154. Oncor's payment of $632,088 in cost paid to original-jurisdiction cities to reimburse them for their costs in appearing
before the Commission and ERCOT in various regulatory matters are not reasonable and necessary operating expenses and
cannot be recovered from ratepayers.
Cost Allocation and Rate Design
155. DELETED.
155A. Oncor's proposed creation of a primary substation rate class consists of customers that provide their own distribution
wires service.
156. DELETED.
156A. It is reasonable to establish the primary substation rate class for customers that take service directly out of a substation.
157. DELETED.
157A. Primary substation rate class service is designed to impose the cost that this rate class imposes on the system.
158. DELETED.
158A. Distribution customers should be permitted to avoid some distribution costs they do not impose on the system because
these customers' hook up to the distribution system is at the substation.
159. DELETED.
159A. The ownership of private distribution lines distinguishes a primary substation rate class customer from a primary or
secondary distribution customer.
160. DELETED.
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160A. A primary substation rate class customer does not own the initial transformation equipment located at the substation that
transforms electricity from transmission voltage to a distribution voltage.
160B. Oncor's proposed addition of a primary substation rate class is reasonable and is approved.
161. For wholesale points of delivery (PODs) at a distribution substation, know as transformation service, Oncor offers Rate
XFMR. For wholesale PODs on a distribution feeder line, known as distribution line service, Oncor offers Rate DLS.
162. In its cost-of-service study, Oncor allocated distribution costs to its wholesale customers based on system average costs,
including the costs of its retail distribution system.
163. Oncor's cost-of-service study yielded increases of 88.66% for Rate XFMR and 147.37% for Rate DLS at Oncor's proposed
rate increase level.
164. Oncor proposed to cap those increases at 50% for each class to mitigate rate shock, and to distribute the missing revenues
among the other customer classes, except for its proposed primary substation class.
165. In Texas Utilities Electric Company Filing In Compliance With Subst. R. 23.67, Docket No. 15638 (Aug. 20, 1997), the
Commission approved rates for Tex-La that was based on direct assignment.
166. In Docket No. 15638, the Commission concluded that direct assignment for the wholesale classes produced rates that were
not unreasonably preferential, prejudicial, or discriminatory and that did not violate the principle of comparability.
167. In Docket No. 15638, the Commission stated that wholesale rates, however they are calculated, should not include costs
that are strictly for providing retail service.
168. The facilities and costs for providing transformation service are the same, regardless of whether the customer is a wholesale
or a retail customer.
169. Differences between wholesale and retail customers, including the wholesale customers' requirement to provide their own
distribution facilities and the requirements for fair competition between the wholesale customers and Oncor, justify different
treatment for those customers.
170. Although direct assignment would clearly be more difficult than the use of system-average costs, those difficulties are not
particularly onerous or insurmountable.
171. Although Oncor's accounting system cannot identify the precise cost of individual items, such as individual poles, to
perform a direct assignment study, Oncor can apply average costs to particular sections or components of its system.
172. In general, Oncor's backstanding capability, at least for Tex-La, does not consist of looped feeder lines, but of redundant
transformers at substations providing the wholesale service.
173. DELETED.
173A. Direct assignment of costs may be considered for wholesale rate classes.
174. DELETED.
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174A. Oncor should be ordered to maintain data adequate for the direct assignment of costs to those wholesale classes and to
prepare a direct assignment study for those classes for consideration in a future project to evaluate whether direct assignment
should be used for allocating costs to the wholesale classes of customers or for consideration in Oncor's next rate proceeding.
175. The evidence in this case is inadequate to set rates based on direct assignment.
176. Rate XFMR and Rate DLS should be allocated the system-average rate increase in this case.
177. Oncor's calculation of its transmission rate based on the average of ERCOT coincident peak demand for the months of
June, July, August, and September (4CP) is reasonable and should be approved.
178. Accounts 364 through 368 should be allocated based on class non-coincident peak (NCP) demand.
179. The costs of major account representatives should not be directly assigned.
180. Costs associated with economic development should be allocated using the customer allocation factor as proposed by
Oncor.
181. Oncor's proposed allocation of rental revenues should be used in this proceeding.
182. Oncor should reallocate rental revenues according to their sources in the cost-of-service study in its next rate proceeding.
183. Oncor requested a weather normalization adjustment to adjust kilowatt-hour sales, class demands, and the associated
revenue for those classes whose electricity usage was affected by abnormal weather conditions.
184. Oncor properly relied on its hourly weather information to determine the minimum and maximum temperatures of the day.
185. Oncor properly applied the adjustments to classes affected by the abnormal weather conditions. Oncor's weather
normalization adjustments should be adopted without change.
186. Power factor is the ratio between the amount of energy supplied (kVA) and the actual amount of energy used (kW) to
measure the amount of wasted energy.
187. Commercial/industrial customers that fail to improve their power factors to 95% within a reasonable period of time are
charged for additional billing demands in accordance with Application Of TXU Electric Company For Approval Of Unbundled
Cost Of Service Rate Pursuant To PURA § 39.201 and Public Utility Commission Substantive Rule § 25.344, Docket No. 22350
(Oct. 4, 2001).
188. Oncor has experienced a decrease in billing demands as a result of customers' actions to improve their power factor that
should be reflected in the ratemaking through the proposed adjustment to avoid overstated revenues.
189. Demand ratchets have a substantial impact on the rates paid by customers with a maximum annual demand load of 20 kW
or less (low loads) despite their having little ability to manage their energy consumption.
190. Oncor's proposal to waive the demand ratchet provisions for customers with maximum annual demand load of 20 kW or less
is reasonable and should be adopted because low load customers, such as youth sports associations, non-profit organizations,
churches, and small business owners, usually use electricity during off-peak hours and weekends and on a seasonal basis.
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191. Oncor's proposal to waive the demand ratchet provisions for all municipally-owned loads should not be adopted because
it is unreasonably preferential and is not based on usage but is instead based solely on the identity of one group, municipalities.
192. The lighting class is unique in the combination of the public good it performs and its demand characteristics.
193. Oncor's proposal to limit a rate increase to the unmetered lighting service to 10% is reasonable and in the best interest
of the public and should be approved.
194. Oncor's proposed franchise fee cost recovery factor rider (FFCRF) allows Oncor recovery of any incremental costs for
increases to a specific municipality's franchise fee rate directly from the customers in that municipality every time a city raises
its franchise fees.
195. Oncor's proposed Rider FFCRF should be rejected because it will create confusion with potentially over 100 different
rates, is contrary to the Commission's policy to maintain uniform and simple rates, and discourages competition.
196. Oncor's proposed underground facilities cost recovery factor rider (UFCRF) allows Oncor to recover the increased costs
associated with installing underground facilities directly from the city's customers.
197. Oncor's proposed Rider UFCRF should be rejected because it is inconsistent with the Commission's policy to maintain
uniform, simple rates, and allows cities to allocate costs rather than the Commission.
198. Oncor proposed street light maintenance cost recovery factor rider (SLM) allows a city to pay for non-standard light
maintenance services through a charge on customers within the city requesting this service.
199. Cities have the right to request non-standard light maintenance service through Oncor's discretionary charges.
200. Rider SLM creates non-uniform rates and allows Oncor to charge customers the cost of non-standard light maintenance
performed in cities within its service territory, and therefore should be rejected.
201. Oncor requests approval of an energy-efficiency cost recovery factor rider (EECRF) to recover the costs of its 2009 energy-
efficiency programs through a monthly customer charge on a per customer per class basis.
202. Rider EECRF is designed on the basis of cost causation because each class is allocated energy-efficiency costs for the
benefits it receives, and these costs are uniformly imposed on the customers within that class.
203. Oncor's energy-efficiency program costs are recovered and adjusted annually and do not vary by energy usage or other
variables.
204. Oncor's proposed Rider EECRF allows Oncor to recover all of its energy-efficiency program costs in a timely manner in
conformance with the Commission rules that allow a utility to recover its energy-efficiency costs through a monthly customers
charge, and should be approved.
205. Considering the Commission's January 30, 2009 order in this case regarding the motion for partial summary judgment,
Oncor should not be required to continue offering Rider SCUD.
206. Oncor's nuclear decommissioning charge rider (NCF) should not be reallocated.
207. Oncor proposed to continue offering several existing retail discretionary services, with certain modifications and additions,
which are billed to the party that incurs the cost.
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208. Oncor's proposed discretionary fees are reasonable and should be approved.
209. Several items in Oncor's specific terms and conditions and tariff language required certain changes to clarify the terms,
specifically:
a. Retail Tariff Section 6.1.2.2.4, should include the revised sentence:
Company may, at its option and at its expense, relocate any Company-owned or non-Company-owned Meter.
b. Retail Tariff Sections 6.1.2.2.7 should be modified to read:
If Retail Customer desires Delivery System service that involves non-standard facilities as described in Section 6.1.2.2.1.2 of
this Tariff, Retail Customer pays Company prior to Company's construction of non-standard facilities the total estimated cost
of all non-standard facilities less the cost of standard facilities to meet Retail Customer's request.
210. No changes should be made to Section 4.5.7 of the Tariff for Transmission Service.
211. Commission Staff's recommended changes to Oncor's proposed Tariff for Retail Delivery Service and the Pro-forma Tariff
for Retail Delivery Service should be approved.
IV. CONCLUSIONS OF LAW
1. Oncor is an electric utility as defined by PURA § 31.002, and, therefore, it is subject to the Commission's jurisdiction under
PURA §§ 14.001, 32.001, 33.001, 33.002, 33.051, 35.004, and 36.102.
2. Oncor is a T&D utility as defined in PURA § 31.002(19).
3. SOAH has jurisdiction over all matters relating to the conduct of the hearing in this case, including the preparation of a
Proposal for Decision, pursuant to PURA § 14.053 and TEX. GOV'T CODE ANN. § 2003.049(b).
4. Oncor has the burden of proving that the rate change it is requesting is just and reasonable pursuant to PURA § 36.006.
5. Oncor provided adequate notice of this proceeding in compliance with P.U.C. PROC. R. 22.51.
6. Pursuant to PURA § 33.001, each municipality in Oncor's service area that has not ceded jurisdiction to the Commission has
jurisdiction over the Company's application, which seeks to change rates for distribution services within each municipality.
7. The Commission has jurisdiction over an appeal from a municipality's rate proceeding pursuant to PURA § 33.051.
8. The effective date of the change in rates approved in this case was extended to be consistent with P.U.C. SUBST. R. 25.241(i)
and by agreement of Oncor, consistent with P.U.C. PROC. R. 22.33(c).
9. Oncor's overall revenues approved in this proceeding permit Oncor a reasonable opportunity to earn a reasonable return on its
invested capital used and useful in providing service to the public in excess of its reasonable and necessary operating expenses
in compliance with PURA § 36.052.
10. The rates approved in this proceeding are based on original cost, less depreciation, of property used and useful to Oncor
in providing service, consistent with PURA § 36.053.
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11. The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059 and P.U.C. SUBST. R. 25.231(c)
(2)(C)(i).
12. PURA § 36.065(a) provides that electric utility rates shall include “expenses for pensions and other postemployment
benefits, as determined by actuarial or other similar studies in accordance with generally accepted accounting principles, in an
amount the regulatory authority finds reasonable.”
13. Oncor's requested ADFIT asset for its pension plan, OPEBs and FAS 112 ADFIT liabilities were properly included in its
rate base is in accordance with PURA § 36.065.
14. Including the cash working capital (CWC) approved in this proceeding within Oncor's rate base is consistent with P.U.C.
SUBST. R. 25.231(c)(2)(B)(iii)(IV) which allows a reasonable allowance for CWC be included in the rate base.
15. The return on equity and overall rate of return authorized in this proceeding are consistent with the requirements of PURA
§§ 36.051 and 36.052.
16. The affiliate expenses approved in this proceeding and included in Oncor's rates are consistent with the requirements of
PURA § 36.058.
17. PURA § 36.064 permits a utility to self-insure against “potential liability or catastrophic property loss, including windstorm,
fire, and explosion losses, that could not have been reasonably anticipated and included under operating and maintenance
expenses.” The Commission shall approve a self-insurance plan under that section if it finds the coverage is in the public
interest, the plan, considering all of its costs, is a lower cost alternative to purchasing commercial insurance, and ratepayers
receive the benefits of the savings.
18. Oncor's liability or catastrophic property loss self-insurance program as modified and approved is in accordance with PURA
§ 36.064 and P.U.C. SUBST. R. 25.231(b)(1)(G).
19. DELETED.
19A. PURA § 36.060 does not apply to Oncor as it is not currently a member of an affiliated group eligible to file a consolidated
tax return.
19B. As a ring-fenced utility, Oncor's fair share of the tax savings is $0.
19C. Even though Oncor is a pass-through entity and not liable for federal income taxes, the Commission is required to include
an amount for such taxes in its cost of service. Suburban Utility Corp. v. Public Utility Commission, 652 S.W.2d 358, 364
(Tex. 1983).
19D. Establishing Oncor's federal income tax expense as if it were a stand-alone, conventional corporation will result in rates
that are just and reasonable.
20. Oncor's proposed energy-efficiency expenses and programs comply with PURA § 39.905.
21. DELETED.
21A. Oncor's purchase of automated meters after December 2005 met the prudence standard set out in Application of Gulf
States Utilities for Authority to Change Rates, Docket No. 6525 (Oct. 15, 1986).
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22. Direct assignment of costs to Oncor's wholesale classes is consistent with PURA § 36.003(b), other sections of PURA, and
the Commission's Substantive Rules.
23. Oncor's rates, as approved in this proceeding, are just and reasonable in accordance with PURA § 36.003.
V. ORDERING PARAGRAPHS
1. The Proposal for Decision prepared by the SOAH ALJs is adopted to the extent consistent with this Order.
2. Oncor's application is granted to the extent provided in this Order.
3. Oncor shall file tariffs consistent with this Order in Compliance Tariff Pursuant to Final Order in PUC Docket No. 35717
(Application of Oncor Electric Delivery Company, LLC for Authority to Change Rates), Docket No. 37677 within 20 days
of the date of this Order. No later than 10 days after the date of the tariff filings, Commission Staff shall file its comments
recommending approval, modification, or rejection of the individual sheets of the tariff proposal. Responses to the Commission
Staff's recommendation shall be filed no later than 15 days after the filing of the tariff. The Commission shall by letter approve,
modify, or reject each tariff sheet, effective the date of the letter.
4. The tariff sheets shall be deemed approved and shall become effective upon the expiration of 20 days from the date of filing,
in the absence of written notification of modification or rejection by the Commission. If any sheets are modified or rejected,
Oncor shall file proposed revisions of those sheets in accordance with the Commission's letter within 10 days of the date of that
letter, and the review procedure set out above shall apply to the revised sheets.
5. Copies of all tariff-related filings shall be served on all parties of record.
6. Oncor shall perform a direct assignment study for the wholesale classes and provide that study to the Commission in at future
project to evaluate direct assignment of costs for wholesale classes or for consideration to assign wholesale costs according to
that study in its next rate proceeding.
7. Oncor shall allocate revenues from rentals according to their sources in the cost-of-service study in its next rate proceeding.
8. All other motions, requests for entry of specific findings of fact and conclusions of law, and any other requests for general
or specific relief, if not expressly granted, are denied.
SIGNED AT AUSTIN, TEXAS the 30th day of November 2009.
I respectfully dissent on the consolidated tax savings adjustment issue, but otherwise join in the Commission's decisions on
all other issues.
I respectfully dissent on the automated meter recovery issue and the creation of a primary substation rate class issue, but
otherwise join in the Commission's decisions on all other issues.
Footnotes
1 Petition and Statement of Intent of Oncor Electric Delivery Company LLC (June 27, 2008), Oncor Initial Brief at 11 (March 4, 2009);
Oncor Exhibits 1-6.
2 Description of Attendant Impacts and Number Running Schedules, Version 2, Scenario 1 (Aug. 10, 2009).
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3 Tr. Vol. 17 at 3292-3293 (Feb. 9, 2009).
4 Suburban Util. Corp. v. Pub. Util. Comm'n, 652 S.W.2d 358 (Tex. 1983).
5 See 26 U.S.C. § 1361.
6 652 S.W.2d at 364.
7 Oncor's Exceptions to the Proposal for Decision at 32 (June 16, 2009).
8 Id. at 31.
9 PFD at 43.
10 Oncor's Exception to the Proposal for Decision at 86.
11 Dane A. Watson Direct Testimony, Oncor Ex. 15, Attachment DAW-2 at 65.
12 Nara Srinivasa Revised Direct Testimony, Staff Ex. 8A at 58.
13 Suburban Util. Corp. v. Pub. Util. Comm'n, 652 S.W.2d 358 (Tex. 1983).
14 See 26 U.S.C. § 1361.
15 652 S.W.2d at 364.
16 See Pub. Util. Comm'n v. GTE-Southwest, Inc., 901 S.W.2d 401, 408-12 (Tex. 1995).
17 Oncor's Response to Order Requesting Briefing at 3-4 (Oct. 29, 2009).
18 See, e.g., Commission Staff's Response to Order Requesting Briefing at 2 (Oct. 29, 2009).
19 901 S.W.2d at 411, “tax expenses will always be a hypothetical amount.”
20 Id.
21 Id.
22 PURA § 36.062(4); 901 S.W.2d at 411.
23 PURA § 36.003(a).
24 Id. § 36.003(b), (c).
25 Id. § 36.051.
26 PFD at 184.
27 See Oncor's Response to Order Requesting Briefing at 12-13; see also Moyston v. New Mexico Pub. Serv. Comm'n, 412 P.2d 840,
849-50, 63 P.U.R.3d 522, ___ (N.M Ctt. App. 1966) (discussing a similar tax treatment in Re Southern Union Gas Company, 36
P.U.R.3d 60 (1960), on remeand, 40 P.U.R.3d (N.M. Pub. Serv. Comm'n 1961)).
28 PURA § 36.060(a) (emphasis added).
29 Mary Jacobs Direct Testimony, Commission Staff Ex. 5 at 26-27.
30 Id.
31 Id.
32 Tr. Vol. 7 at 1241-1242 (Jan. 23, 2009).
33 Oncor's Initial Post Hearing Brief at 192-3 (Mar. 27, 2009).
34 Id. at 199-200.
35 PFD at 214.
36 PFD at 223, 224.
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APPLICATION OF ENTERGY TEXAS, INC. FOR..., 2010 WL 5240342...
2010 WL 5240342 (Tex.P.U.C.)
Slip Copy
APPLICATION OF ENTERGY TEXAS, INC. FOR AUTHORITY
TO CHANGE RATES AND RECONCILE FUEL COSTS
PUC Docket No. 37744
SOAH Docket No. XXX-XX-XXXX
Texas Public Utility Commission
December 13, 2010
ORDER
Before Smitherman, Chairman, Nelson, and Anderson Jr., Commissioners.
BY THE COMMISSION:
This Order addresses the application of Entergy Texas, Inc. (ETI) for authority to change rates and reconcile fuel costs. ETI,
Commission Staff, the Office of Public Utility Counsel (OPUC), the Steering Committee of Cities Served by ETI (Cities), 1
Texas Industrial Energy Consumers (TIEC), The Kroger Company (Kroger), and Wal-Mart Stores Texas, LLC and Sam's East,
Inc. (collectively Wal-Mart), through their duly authorized representatives entered into and filed a stipulation and settlement
agreement that resolves all of the issues in this proceeding except the issues related to ETI's proposal for competitive generation
service. Cottonwood Energy, L.P. and the State of Texas agencies and institutions of higher education (State Agencies) did not
join but do not oppose the stipulation.
The Commission severed the competitive generation service issues into Docket No. 38951 2 in Order No. 14.
The Commission adopts the following findings of fact and conclusions of law:
I. Findings of Fact
Procedural History
1. On December 30, 2009, ETI filed an application requesting approval of (1) base rate tariffs and riders designed to collect an
overall revenue requirement of $1,758.4 million, which includes a total non-fuel retail revenue requirement of $838.3 million
(base rate revenues of $486 million plus revenue from riders of $352.3 million); (2) a set of proposed tariff schedules presented
in the Electric Utility Rate Filing Package for Generating Utilities (RFP) accompanying ETI's application; (3) a request for final
reconciliation of ETI's fuel and purchased power costs for the reconciliation period from April 1, 2007 to June 30, 2009; and
(4) certain waivers to the instructions in RFP Schedule V accompanying ETI's application.
2. The 12-month test year employed in ETI's filing ended on June 30, 2009.
3. ETI provided notice by publication for four consecutive weeks before the effective date of the proposed rate change in
newspapers having general circulation in each county of ETI's Texas service territory. ETI also mailed notice of its proposed
rate change to all of its customers. Additionally, ETI timely served notice of its statement of intent to change rates on all
municipalities retaining original jurisdiction over its rates and services. ETI also published one-time supplemental notice by
publication in newspapers and by bill insert.
4. The following parties were granted intervenor status in this docket: OPUC, Cities, Cottonwood, Kroger, State Agencies,
TIEC, and Wal-Mart. Commission Staff was also a participant in this docket.
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5. On January 4, 2010, the Commission referred this case to the State Office of Administrative Hearings (SOAH) for processing.
6. On February 19, 2010, the ALJs issued Order No. 3, which approved an agreement between ETI, Staff, Cities, State Agencies,
OPUC, TIEC, Kroger, and Wal-Mart, to (1) establish an interim rate increase of $17.5 million annually above ETI's then-
existing base rates commencing with service rendered on and after May 1, 2010 subject to true-up and refund for service
rendered prior to September 13, 2010 to the extent final overall rates established by the Commission amounted to less than
a $17.5 million rate increase; (2) extend the jurisdictional deadline by which the Commission must issue a final order on the
Company's rate request from July 5, 2010 to November 1, 2010; (3) establish a September 13, 2010 effective date for rates
such that, notwithstanding the extension of the jurisdictional deadline, the final overall rates established by the Commission
would relate back to service rendered on and after September 13, 2010; (4) require ETI to publish supplemental notice, once in
newspapers and by a bill insert, setting forth the effect of its proposed rate change in terms of the percentage increase in non-
fuel revenues; and (5) establish a procedural schedule and discovery deadlines for this proceeding. Order No. 3 also granted Mr.
Kurt Boehm's motion for admission pro hac vice as counsel for Kroger and ETI's February 3 and February 11, 2010 petitions
for review of cities' ordinances and motions to consolidate with respect to the rate decisions adopted by the Cities of Ames,
Anderson, Bedias, Bevil Oaks, Bremond, Caldwell, Calvert, Chester, China, Colmesneil, Corrigan, Cut and Shoot, Daisetta,
Dayton, Devers, Franklin, Groveton, Hardin, Hearne, Iola, Kosse, Kountze, Liberty, Lumberton, Madisonville, Midway, New
Waverly, Normangee, Nome, Patton Village, Plum Grove, Riverside, Rose Hill Acres, Somerville, Taylor Landing, Todd
Mission, Trinity, and Woodville.
7. On June 14, 2010, the ALJs issued Order No. 6 granting Staffs June 1, 2010 motion and severing rate case expense issues to
Docket No. 38346. 3 Through Order No. 6, the ALJs also granted ETI's March 12, April 29, and May 17 petitions for review and
motions to consolidate with respect to the rate decisions adopted by the Cities of Anahuac, Beaumont, Bridge City, Cleveland,
Conroe, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Panorama Village, Pine
Forest, Pinehurst, Port Arthur, Port Neches, Roman Forest, Rose City, Shenandoah, Shepard, Silsbee, Sour Lake, Splendora,
Vidor, West Orange, Willis, Woodbranch Village, and Woodloch.
8. The hearing on the merits commenced on July 13, 2010 and was immediately recessed in order to facilitate settlement
negotiations. The hearing was again convened on July 15, 2010, at which time the signatories announced their intent to continue
settlement discussions to resolve all issues related to the Company's application with the exception of those related to ETI's
proposal for competitive generation service (CGS) and associated riders.
9. On August 6, 2010, the signatories submitted the stipulation resolving all outstanding issues regarding the Company's
application with the exception of those related to ETI's CGS proposal. Under the stipulation, ETI will be allowed to implement
base rate tariffs and riders designed to collect an overall revenue requirement of $1,614.9 million, 4 which includes a total non-
fuel retail revenue requirement of $694.9 million (base rate revenues of $599 million plus revenue from riders of $95.9 million).
The signatories also submitted, on August 6, 2010, an agreed motion to revise interim rates and to consolidate the severed
rate-case expense docket. The interim rates requested in the agreed motion mirrored the final rates proposed for Commission
approval in the stipulation. The agreed motion further requested that the ALJs consolidate with the instant proceeding Docket
No. 38346, related to severed Docket No. 37744 rate case expense issues, and admit the parties' pre-filed exhibits into evidence.
10. On July 16 and July 20, 2010, the ALJs held the hearing on the merits with respect to ETI's CGS proposal.
11. On August 9, 2010, the ALJs issued Order No. 12, granting approval of revised interim rates for usage on and after August
15, 2010.
12. On October 5, 2010, the ALJs issued a proposal for decision regarding issues related to ETI's CGS proposal.
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13. On October 5, 2010, the ALJs issued Order No. 13, ordering the consolidation of Docket No. 38346, related to severed rate-
case expense issues, into the instant proceeding, admitting evidence, and returning this docket to the Commission consistent
with the agreed motion filed on August 6, 2010.
14. The Commission considered this Docket at the November 10, 2010 and December 1,2010 open meetings.
15. On November 30, 2010 ETI filed an unopposed motion to sever the competitive CGS issues from the settled issues in
this docket. The Commission granted the motion at the December 1, 2010 open meeting and the Commission's decision was
memorialized in Order No. 14 issued on December 3, 2010. The CGS issues were severed into Docket No. 38951 in Order
No. 14.
Description of the stipulation and Settlement Agreement
16. The signatories to the settlement stipulated that ETI should be allowed to implement an initial overall increase in base-
rate revenues of $59 million for usage on and after August 15, 2010. The signatories further stipulated that they would request
approval of interim rates by the ALJs presiding or by the Commission, as necessary, to ensure timely implementation of this
initial rate increase. The signatories further stipulated that ETI should be allowed to implement an additional overall increase
in base-rate revenues of $9 million on an annualized basis effective for bills rendered on and after May 2, 2011, the first billing
cycle for the revenue month of May.
17. The signatories agreed that ETI's authorized return on equity shall be 10.125% and its weighted average cost of capital
shall be 8.5209%.
18. The signatories stipulated that the amount of rate increase authorized under finding of fact 16 includes rate-case expenses
and contemplates their full amortization in 2010, and that this amount constitutes the full and final recovery of all rate-case
expenses relating to Docket No. 37744.
19. The signatories stipulated to the amount of transmission and distribution invested capital by function as of June 30, 2009
as set out in attachment 1 to the stipulation.
20. The signatories stipulated that the Company's proposed purchased-power recovery rider will not be approved in this docket,
and purchased capacity costs will be included in base rates.
21. The signatories stipulated that the Company's proposed transmission cost recovery factor (TCRF) will not be approved
in this docket. The signatories stipulated to the baseline values as shown in attachment 2 to the stipulation to be used in the
Company's request, if any, for a TCRF in a separate proceeding.
22. The signatories agreed that ETI's proposed cost-of-service adjustment rider and formula rate plan will not be approved in
this docket.
23. The signatories stipulated that the Company's proposed renewable-energy-credit rider will not be approved in this docket,
and the Company's renewable-energy-credit costs shall be recovered in base rates. The signatories further stipulated that a
transmission customer that opts out pursuant to P.U.C. SUBST. R. 25.1730(j) shall receive a credit that offsets the amount of
renewable-energy-credit costs that are recovered in base rates from the transmission customer.
24. The signatories agreed that ETI's proposed remote-communications-link rider should be approved as filed by the Company.
25. The signatories agreed that ETI's proposed market-valued-energy-reduction service rider will not be approved in this docket.
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APPLICATION OF ENTERGY TEXAS, INC. FOR..., 2010 WL 5240342...
26. The signatories reached the following specific agreements regarding rate design as a part of the overall resolution of this
docket:
a. Rate Schedule IS. Rate Schedule IS will be opened to new business In the Company's next base-rate case, the amount of
interruptible credits recoverable from Texas retail customers shall be limited to an increase of $1 million more than the amount
requested in this docket (or a total of $6.8 million); provided, however, that in the next rate case, the Company may request
an exception to this limitation upon a showing that the test-year credit amount in excess of the $6.8 million cap is both cost
effective and necessary to meet the Company's generation reserve margin requirement. The signatories further agreed that the
Company will not offer additional interruptible service if the availability of total interruptible service supplied by the Company
under all interruptible service riders exceeds 5% of the projected aggregate Company peak demand unless the additional level
of interruptible service offered in excess of the 5% cap is both cost effective and necessary to meet the Company's generation
reserve margin requirement. To the extent that the credit amount or participation level exceeds the limitations described in this
paragraph and the Company includes test-year credits over the $6.8 million credit-amount cap or additional participation in
excess of the 5% participation-level cap in its next rate case, the Company shall have the burden to prove whether those test-
year credits or participation levels meet the standards established in this paragraph for inclusion in the test year. The standards
in this paragraph are in addition to any requirements in PURA for inclusion of costs in rates. The signatories further agreed to
the Schedule IS revisions shown on attachment 3 to the stipulation.
b. Rate Schedule IHE. The signatories agreed that no change shall be made to rate schedule IHE in this docket.
c. Lighting Class Rates. The signatories stipulated that the language under the paragraph relating to rate group C in rate schedule
SHL will be revised to reflect that, where the Company agrees to install facilities other than its standard street light fixture
and lamp as provided under Rate Group A, a lump sum payment will be required, based upon the installed cost of all facilities
excluding the cost of the standard street light fixture and lamp, and the customer will be billed under rate group A.
e. Electric Extension Policy. The signatories agreed to the line-extension terms and conditions as reflected in attachment 4 to
the stipulation.
f. Life-of-Contract Demand Ratchet. The signatories agreed that the life-of-contract demand ratchet provision in rate schedules
Large Industrial Power Service, Large Industrial Power Service-Time of Day, General Service, General Service-Time of Day,
Large General Service, and Large General Service-Time of Day shall be excluded from rate schedules in ETFs next rate case.
The signatories further stipulated that the foregoing rate schedules will be revised so that the life-of-contract demand ratchet
provision shall not be applicable to new customers and shall not exceed the level in effect on August 15, 2010 for existing
customers.
g. Residential Customer Charge. The signatories agreed that the residential customer charge shall be increased to $5.00.
h. Non-Sufficient Funds Charge. The signatories agreed that the non-sufficient funds charge shall be increased to $15.00.
27. The signatories agreed to the class cost allocation set forth in attachment 5 to the stipulation.
28. The signatories stipulated that the appropriate allocation between ETI's wholesale and retail jurisdictions of baseline values
and costs to be included in a TCRF is to be addressed in the proceeding, if any, in which ETI seeks approval of a TCRF.
29. The signatories stipulated that no party waives its right to address in any subsequent proceeding the appropriate treatment
for Texas retail ratemaking purposes of power sales between ETI and Entergy Gulf States Louisiana, L.L.C.
30. The signatories reached the following specific agreements regarding fuel-related issues as part of the overall resolution of
this docket:
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APPLICATION OF ENTERGY TEXAS, INC. FOR..., 2010 WL 5240342...
a. Agreed Fuel Disallowance. The Company stipulated to a fuel disallowance of $3.25 million not associated with any particular
issue raised by the signatories. The disallowance will be allocated pro rata with interest over each month of the reconciliation
period and reflected in the refund in Docket No. 38403. 5 The signatories stipulated that the Company's fuel costs shall be
finally reconciled for the reconciliation period of April 1, 2007 through June 30, 2009.
b. Rider IPCR. The signatories agreed that ETI's eligible Rider IPCR costs for the period April 1, 2007 through the date the rider
terminated shall be finally reconciled with a disallowance of $300,000. The signatories further agreed that the under-recovered
balance of Rider IPCR costs shall be booked as fuel expense in the month in which the Commission issues an order adopting
the stipulation; provided, however, that the under-recovered balance shall be allocated to customer classes using A&E4CP.
c. Rough Production Cost Equalization (RPCE) Payments. The signatories agreed that ETI will credit an additional $18.6
million to Texas fuel-factor customers, which the signatories stipulated represents the remaining portion of RPCE payments
ETI received in 2007 that were at issue in Docket No. 35269. 6 The RPCE credit shall be allocated to rate classes based on
loss-adjusted kilowatt hours at plant for calendar year 2006. For customers in the Large Industrial Power Service rate class, the
credit will be refunded based on the customer's actual kWh usage during the billing months of January 2006 through December
2006. Upon issuance of a final order approving the stipulation, the RPCEs shall be credited to customers as a separate one-
month bill credit in the same form as the RPCEA Rider last approved in Docket No. 38098. 7 ETI agreed that it will terminate
all appeals related to Docket No. 35269.
31. The signatories agreed that ETI will continue its accrual of storm-cost reserves at the level of $3.65 million annually and
that this amount shall be subsumed in the base-rate revenue increase described in finding of fact 16 above.
32. The signatories agreed that ETI shall maintain River Bend depreciation rates at current levels, i.e., based on a 60-year life.
River Bend decommissioning costs will be set at $2,019,000 annually, which is based upon a labor-factor escalation rate of
1.67%, an energy-factor escalation rate of 0.25%, and a waste-burial-factor-escalation rate of 1.71%, resulting in an overall
escalation rate of 3.62%, and net investment yields as follows:
Nuclear-Decommissioning-Trust Projected Returns
Tax-Qualified Investment Non-Tax-Qualified Investments
2010 5.475% 5.057%
2011 5.837% 5.236%
2012 6.306% 5.567%
2013 6.304% 5.607%
2014 6.481% 5.896%
2015 6.493% 5.909%
2016 6.412% 5.826%
2017 6.412% 5.830%
2018 6.364% 5.790%
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APPLICATION OF ENTERGY TEXAS, INC. FOR..., 2010 WL 5240342...
2019 6.316% 5.748%
2020 6.268% 5.712%
2021 6.220% 5.670%
2022 2.503% 5.458%
2023 5.817% 5.055%
2024 5.382% 4.628%
2025 5.036% 4.516%
2026-2034 4.920% 4.409%
33. The signatories stipulated that the Company's depreciation rates for non-River Bend production plant, transmission,
distribution, and general plant will remain at current levels and the Company will maintain its accounting records on a
prospective basis for purposes of depreciation accrual, depreciation reserve, retirements, additions, salvage, and cost of removal
by FERC account.
Consistency of the Agreement with PURA and the Commission Requirements
34. Considered in light of (1) the pre-filed testimony by the parties entered into evidence and (2) the additional evidence and
testimony admitted during the course of the hearing on the merits on the Company's application, the stipulation is the result of
compromise from each signatory, and these efforts, as well as the overall result of the stipulation viewed in light of the record
evidence as a whole, support the reasonableness and benefits of the terms of the stipulation.
35. The evidence addressed in finding of fact 34 demonstrates that the rates, terms, and conditions resulting from the stipulation
are just and reasonable and consistent with the public interest.
36. The total level of the Texas retail revenue requirement contemplated by the stipulation will allow ETI the opportunity to
earn a reasonable return over and above its reasonable and necessary operating expense.
37. The stipulated revenue requirement is consistent with applicable provisions of PURA chapter 36 and the Commission's rules.
38. To the extent that affiliate costs are included in the stipulated revenue requirement and fuel expense, they are reasonable
and necessary for each class of affiliate costs presented in ETI's application.
39. To the extent that affiliate costs are included in the stipulated revenue requirement and fuel expense, the price charged to
ETI is not higher than the prices charged by the supplying affiliate for the same item or class of items to its other affiliates or
divisions, or a non-affiliated person within the same market area or having the same market conditions.
40. The retail revenue requirement in the stipulation does not include any expenses prohibited from recovery under PURA.
41. A return on equity of 10.125% and a weighted average cost of capital of 8.5209% for ETI should be adopted consistent
with the stipulation.
42. The agreed rate-design provisions and terms and conditions of service included in the stipulation are just and reasonable.
43. The treatment of rate-case expenses described in the stipulation is reasonable.
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APPLICATION OF ENTERGY TEXAS, INC. FOR..., 2010 WL 5240342...
44. The Company's proposed remote-communications-link rider as filed by the Company is reasonable.
45. The depreciation rates agreed to in the stipulation are just and reasonable.
46. The recovery of $2,019,000 annually for decommissioning costs of nuclear production assets based on the factors agreed
to in the stipulation is reasonable.
47. A $3.65 million annual storm cost accrual is reasonable.
48. The class allocation methodologies described in the stipulation are just and reasonable.
49. The fuel and IPCR-related provisions of the stipulation are reasonable.
II. Conclusions of Law
1. ETI is a public utility as that term is defined in PURA § 11.004(1) and an electric utility as that term is defined in PURA
§ 31.002(6).
2. The Commission exercises regulatory authority over ETI and jurisdiction over the subject matter of this application pursuant
to PURA §§ 14.001, 32.001, 32.101, 33.002, 33.051, 36.001-.111, 36.203, 39.452, and 39.455.
3. SOAH has jurisdiction over matters related to the conduct of the hearing and the preparation of a proposal for decision in
this docket, pursuant to PURA § 14.053 and TEX. GOV'T CODE ANN. § 2003.049.
4. This docket was processed in accordance with the requirements of PURA, the Texas Administrative Procedure Act, 8 and
Commission rules.
5. ETI provided notice of its application in compliance with PURA § 36.103, P.U.C. PROC. R. 22.51(a), and P.U.C. SUBST.
R. 25.235(b)(1)-(3).
6. This docket contains no remaining contested issues of fact or law.
7. The stipulation, taken as a whole, is a just and reasonable resolution of all issues it addresses; results in just and reasonable
rates, terms, and conditions; is supported by a preponderance of the credible evidence in the record; is consistent with the
relevant provisions of PURA; and is consistent with the public interest.
8. ETI has properly accounted for the amount of fuel and IPCR-related revenues collected pursuant to the fuel factor and Rider
IPCR.
9. The revenue requirement, cost allocation, revenue distribution, and rate design implementing the stipulation result in rates that
are just and reasonable, comply with the ratemaking provisions in PURA, and are not unreasonably discriminatory, preferential,
or prejudicial.
10. Based on the evidence in this docket, the overall total invested capital through the end of the test year meets the requirement
in PURA § 36.053(a) that electric utility rates be based on the original cost, less depreciation, of property used by and useful
to the utility in providing service.
11. ETI has met its burden of proof in demonstrating that it is entitled to the level of retail base rate and rider revenue set out
in the stipulation.
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APPLICATION OF ENTERGY TEXAS, INC. FOR..., 2010 WL 5240342...
12. ETI has met its burden of proof in demonstrating that the rates resulting from the stipulation are just and reasonable, and
consistent with PURA.
III. Ordering Paragraphs
1. ETI's application seeking authority to change its rates; reconcile its fuel and purchased power costs for the Reconciliation
Period from April 1, 2007 to June 30, 2009; and for other related relief is approved consistent with the above findings of fact
and conclusions of law.
2. Rates, terms, and conditions consistent with the stipulation are approved.
3. The tariffs and riders consistent with the stipulation are approved for the initial and second step rate increases.
4. ETI's request for waivers of RFP instructions (RFP Schedule V) is granted.
5. ETI shall adjust decommissioning expense related to the River Bend Nuclear Generating Station consistent with the terms
of this Order.
6. Neither the stipulation and settlement agreement nor this Order constitutes the Commission's agreement with, or consent to,
the manner in which ETI, or any entity affiliated with ETI, has interacted with any decommissioning trust to which ETI or its
ratepayers have made contributions or provided funds. Furthermore, this Order in no way constitutes a waiver or release of any
conduct, whether or not such conduct occurred before the date of this Order, that may constitute a violation of any provision
of state law, including, without limitation, the rules and regulations of this Commission relating to nuclear decommissioning
trust funds; or prevents the Staff of the Commission from opening an investigation and taking enforcement action relating to
violations of such rules and regulations.
7. Nothing contained in this Order constitutes the consent or approval, explicit or implied, of any modification, amendment or
clarification of any power purchase agreement between ETI and any other Entergy entity relating to the River Bend Station.
Without limiting the foregoing, nothing contained in this Order shall constitute the consent or approval of any modification,
amendment, or clarification of any power purchase agreement between ETI and any other Entergy entity relating to the River
Bend Station, which is made to address any concerns raised by the NRC in its Request for Additional Information regarding
the River Bend Station dated March 11, 2010.
8. The Rider IPCR costs and eligible fuel costs requested by ETI are, consistent with this Order, reconciled through June 30,
2009, and are approved consistent with the stipulation.
9. ETI shall adjust its fuel over/under recovery balance consistent with the findings in this Order.
10. ETI shall file an RPCEA Rider consistent with the above findings of fact and conclusions of law to be effective with the
first billing cycle of the billing month immediately following the effective date of this Order..
11. Because the final approved rates are equal to or higher than the interim rates adopted in Order No. 3, no refund of the interim
rates authorized by Order No. 3 is necessary.
12. The interim rates approved in Order No. 12 are herby approved for the initial step rate increase contemplated by the
stipulation, and ETI shall implement the second step rates for bills rendered on and after May 2, 2011, the first billing cycle
for the revenue month of May.
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APPLICATION OF ENTERGY TEXAS, INC. FOR..., 2010 WL 5240342...
13. Within 30 days of the date of this Order, ETI shall file a clean copy of all of the tariffs and schedules approved in this docket
and a clean copy of the attachments to the stipulation.
14. The entry of this Order consistent with the stipulation does not indicate the Commission's endorsement of any principle or
method that may underlie the stipulation. Neither should entry of this Order be regarded as a precedent as to the appropriateness
of any principle or methodology underlying the stipulation.
15. All other motions, requests for entry of specific findings of fact, conclusions of law, and ordering paragraphs, and any other
requests for general or specific relief, if not expressly granted in this order, are hereby denied.
SIGNED AT AUSTIN, TEXAS the 13 th day of December 2010
Footnotes
1 Steering Committee of Cities is comprised of the Cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Groves, Houston,
Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest, Pinehurst, Port Arthur, Port Neches, Rose
City, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West Orange.
2 Application of Entergy Texas, Inc. for Approval of Competitive Generation Service Tariff (Issues Severed From Docket No. 37744),
Docket No. 38951.
3 Application of Entergy Texas, Inc. for Rate Case Expenses Severed from PUC Docket No 37744, Docket No. 38346.
4 This figure includes fuel at test year prices. If current fuel prices are substituted for test year fuel prices, the overall revenue requirement
figure would be $ 1,504.0 million.
5 Application of Entergy Texas, Inc. to Implement an Interim Fuel Refund, Docket No. 38403, Order (Sept. 16,2010).
6 Compliance Filing of Entergy Texas, Inc. Regarding Jurisdictional Allocation of 2007 System Agreement Payments, Docket No.
35269, Order (Jan. 7, 2009).
7 Application of Entergy Texas, Inc. for Authority to Implement New RPCEA Rate, Docket No. 38098, Order (July 1,2010).
8 TEX. GOV'T CODE ANN. Chapter 2001 (Vemon 2007 and Supp. 2009).
End of Document © 2015 Thomson Reuters. No claim to original U.S. Government Works.
© 2015 Thomson Reuters. No claim to original U.S. Government Works. 9
PUC DOCKET NO. 38339
SOAH DOCKET NO. XXX-XX-XXXX
APPLICATION OF CENTERPOINT § PUBLIC UTILITY COMMISSION
ELECTRIC DELIVERY COMPANY, §
LLC, FOR AUTHORITY TO CHANGE § OF TEXAS
RATES §
ORDER ON REHEARING
1
This Order addresses the application of CenterPoint Electric Delivery Compan~~ LLC,for
.,.Q
authority to change its rates. On June 30, 2010, CenterPoint filed its application with the Public
Utility Commission of Texas requesting authority to increase its transmission and distribution
rates and to reconcile costs related to its advanced metering system (AMS) deployment.
CenterPoint originally requested a total net increase of $110 million: $18 million represented the
net increase associated with transmission service and $92 million associated with retail delivery
service. CenterPoint requested a rate of return on investment of 9.0%, based on a proposed
capital structure having 50-50 ratio of debt to equity; a 6.74% cost of debt; and a return on equity
of 11.25%.
On December 3, 2010, the State Office of Administrative Hearings (SOAH)
administrative law judges (AUs) issued a proposal for decision in which they recommended an
overall rate increase for CenterPoint of $21.483 million. 1 For the reasons discussed in this
Order, the Commission adopts in part and rejects in part the proposal for decision, including
findings of fact and conclusions of law, and determines that CenterPoint's appropriate system-
wide adjusted rates will lead to a retail revenue increase of $14.65 million and an overall revenue
requirement increase of $2.4 million for both retail and wholesale combined.2
1
Proposal for Decision (PFD), Attachment ALJ-3 at I, line 10, column 2 "Difference between ALJs' Rec.
and CNP, current revenues." (Dec. 3, 2010).
2
Revised Number Runs and Associated Workpapers, Attachment Comm-3 AFTER Postage Stamp Update,
at I, line LO, column 2 (Feb. 18, 2011).
000000001
PUC Docket No. 38339 Order on Rehearing Page 22 of47
SOAH Docket No. XXX-XX-XXXX
75A. CenterPoint's overall rate of return is as follows:
CAPITAL WEIGHTED AVG
COMPONENT STRUCTURE COST OF CAPITAL COST OF CAPITAL
LONG-TERM DEBT 55.00% 6.74% 3.71%
COMMON EQUITY 45.00% 10.00% 4.50%
TOTAL 100.00% 8.21%
Cost of Service
76. CenterPoint's test-year total transmission operations and maintenance (O&M) expense in
FERC accounts 560 through 573 as adjusted by the Commission in the amount of
$234.721 million is reasonable and necessary.
77. CenterPoint's test-year total-distribution O&M expense in FERC accounts 580 through
598 as adjusted by the Commission in the amount of $188.132 million is reasonable and
necessary.
78. CenterPoint' s proposed $7 .15 million O&M expenditure related to storm hardening is
reasonable and necessary.
79. CenterPoint's requested total-customer-services-and-information expense of $35.54
million is reasonable and necessary.
80. CenterPoint's Commission-adjusted administrative-and-general-expense request of
$178.178 million is reasonable and necessary.
81. The evidence demonstrates that CenterPoint's short-term incentive compensation plan
(STI) is a reasonable and necessary component of a total compensation package required
to recruit, retain, and motivate employees.
82. CenterPoint's long-term incentive-compensation plan (LTI) is not a reasonable and
necessary component of CenterPoint' s total compensation package.
83. The corporate and financial goals of STI are directly tied to metrics such as customer
service and safety.
000000022
SOAH Docket No. XXX-XX-XXXX
PUC Docket No. 39896
ETI 2011 Rate Case
ETI EXHIBIT NO. 1
DOCKET NO. 39896
APPLICATION OF ENTERGY § PUBLIC UTILITY COMMISSION
TEXAS, INC. FOR AUTHORITY §
TO CHANGE RATES AND § OF TEXAS
RECONCILE FUEL COSTS §
ENTERGY TEXAS, INC.’S STATEMENT OF INTENT AND APPLICATION FOR
AUTHORITY TO CHANGE RATES AND RECONCILE FUEL COSTS
TO THE HONORABLE PUBLIC UTLITY COMMISSION OF TEXAS:
Pursuant to Sections 14.001, 32.001, 32.101, 36.101 through 36.111 and
36.203 through 36.206 of the Public Utility Regulatory Act (“PURA”)1 and
pursuant to applicable Public Utility Commission of Texas (“Commission” or
“PUCT”) Substantive and Procedural Rules, Entergy Texas, Inc. (“ETI” or “the
Company”) respectfully requests that the Commission approve:
(1) base rate tariffs and riders designed to collect a total non-fuel retail
revenue requirement for ETI of approximately $841.9 million;
(2) the complete set of proposed tariff schedules presented in
Schedule Q-8.8 of the Electric Utility Rate Filing Package for Generating
Utilities (“Rate Filing Package” or “RFP”) that accompanies this
Application;
(3) the Company’s request for reconciliation of its fuel and purchased
power costs and fuel factor revenues for the Reconciliation Period from
July 1, 2009 to June 30, 2011, pursuant to P.U.C. SUBST. R. 25.236; and
(4) the waivers to the Rate Filing Package instructions presented in
RFP Schedule V that accompany this Application.
1
TEX. UTIL. CODE ANN. Title 2.
1
2011 ETI Rate Case 1-1
In support of these requests, ETI states:
I. Parties and Jurisdiction
1. ETI is an electric utility, a public utility, and a utility as those terms
are defined in PURA §§ 11.004(1) and 31.002(6).
2. ETI serves retail and wholesale electric customers in Texas. As of
June 30, 2011, ETI served approximately 412,000 Texas retail customers. The
Federal Energy Regulatory Commission (“FERC”) regulates ETI’s wholesale
electric operations.
3. ETI’s business address is 350 Pine Street, Beaumont, Texas
77701. Its mailing address is P.O. Box 2951, Beaumont, Texas 77704-2951. Its
telephone number is (409) 838-6631. ETI’s regulatory affairs office in Austin,
Texas is located at 919 Congress Avenue, Suite 840, Austin, Texas 78701,
telephone number (512) 487-3999, and facsimile number (512) 487-3998.
4. ETI is a wholly-owned subsidiary of Entergy Corporation, which is a
“holding company” pursuant to FERC regulations under the Public Utility Holding
Company Act of 2005.2 Entergy Corporation is the parent company of six other
rate-regulated utilities in the United States in addition to ETI;3 two regulated non-
profit service companies that were established under the authority of the
Securities and Exchange Commission but are now under the oversight of FERC;4
and various other domestic and foreign companies. Entergy Corporation’s
domestic rate-regulated utility operating companies (“Entergy Operating
Companies” or “Operating Companies”) operate an interconnected transmission
and generation system governed by the Entergy System Agreement and
2
18 C.F.R. Part 366.
3
Entergy Arkansas, Inc.; Entergy Gulf States Louisiana, L.L.C.; Entergy Louisiana, LLC;
Entergy Mississippi, Inc.; Entergy New Orleans, Inc.; and System Energy Resources, Inc.
(“SERI”). SERI owns the Grand Gulf nuclear plant and sells its output exclusively to Entergy
Operating Companies other than ETI.
4
Entergy Services, Inc. and Entergy Operations, Inc.
2
2011 ETI Rate Case 1-2
associated Service Schedules MSS-1 through MSS-7,5 which are under FERC’s
exclusive jurisdiction.
5. The Commission has exclusive original jurisdiction over this
Application for service provided to environs customers and to customers within
the corporate limits of those cities within ETI’s service territory that have ceded
their regulatory jurisdiction to the Commission, as well as over the reconciliation
of fuel and purchased power costs, pursuant to PURA §§ 14.001, 32.001,
32.002, 36.101 through 36.111 and 36.203 through 36.206.
6. The Company’s proposed effective date for the rate change is 35
days after the date of the filing of this Application.
II. Authorized Representative, Counsel, and Designation of Service
Location
7. ETI’s authorized representative is Mr. Jack Blakley, Vice President,
Regulatory Affairs–Texas, who may be contacted at ETI’s regulatory affairs office
in Austin, Texas (address, telephone, and facsimile numbers listed in ¶ 3).
8. ETI’s co-lead counsels are:
Steven H. Neinast John F. Williams
Paula Cyr Jay Breedveld
Assistants General Counsel Duggins Wren Mann & Romero,
Entergy Services, Inc. LLP
919 Congress Avenue, One American Center
Suite 701 600 Congress, Suite 1900
Austin, Texas 78701 P.O. Box 1149
(512) 487-3957 telephone Austin, Texas 78767-1149
(512) 487-3958 facsimile (512) 744-9300 telephone
(512) 744-9399 facsimile
5
MSS-1 is the tariff for equalizing the Operating Companies’ generating capability and
ownership cost incidental to such capability. MSS-2 is the tariff for equalizing the Operating
Companies’ investment in bulk transmission plant. MSS-3 is the tariff governing the
exchange of electric energy and the allocation of rough production cost equalization
payments among the Operating Companies. MSS-4 is the tariff governing unit power
purchases between Operating Companies. MSS-5 is the tariff that distributes profits from
sales of energy and power to unaffiliated companies for the joint account of all Operating
Companies. MSS-6 is the tariff that provides a means to distribute the cost of the system
operations center (the system dispatch center). MSS-7 is a tariff providing a procedure for
protecting those Operating Companies that elect to participate therein from incurring higher
fuel and purchased power costs as a result of the merger between Entergy Corporation and
Gulf States Utilities Company.
3
2011 ETI Rate Case 1-3
9. ETI requests that the Commission, the presiding officers, the State
Office of Administrative Hearings, the Commission Staff, and the parties serve all
papers (orders, discovery, motions, etc.) regarding this Application on Mr.
Neinast’s office, as listed in the previous paragraph.
III. Proposed Tariffs
10. ETI’s proposed revisions to its tariffs are provided in RFP Schedule
Q-8.8. ETI’s complete Rate Filing Package is filed contemporaneous with this
Application.
IV. Summary of Filing
11. The prefiled direct testimony of ETI witness Joseph F. Domino
explains the structure of this filing and introduces each of the witnesses. ETI’s
filing addresses: (1) base rates and riders; (2) class cost allocation and rate
design; (3) rate case expenses; and (4) fuel and purchased power reconciliation.
A. Base rate revenue requirement and riders
12. This Application affects all of ETI’s retail electric customers, and
each proposed change is reflected in the proposed revisions to the tariffs that are
provided in RFP Schedule Q-8.8. ETI has presented its revenue requirement
based on an adjusted twelve-month test year ending on June 30, 2011. The
proposed base rates and riders produce an increase of approximately $111.8
million, or 8.09%, over adjusted test year revenues. Excluding fuel costs, the
proposed change produces an increase in revenues of approximately 15.32%.
Please see Attachment A for the details of how the revenue requirement affects
each rate class.
13. The Company’s request includes two new riders for which the
Company seeks Commission approval in this case:
(a) A Purchased Power Recovery Rider (“Rider PPR”), which is
designed to recover all existing purchased capacity costs as well as
future purchased capacity costs. As set in this case, Rider PPR will
4
2011 ETI Rate Case 1-4
recover approximately $272.7 million annually. The Company’s
request includes (1) a mechanism to update the rider annually to
reflect increases or decreases in purchased capacity costs as
incurred by the Company, and (2) the reconciliation of costs
recovered under the rider in the Company’s fuel reconciliation
cases.6
(b) A Renewable Energy Credits Rider (“Rider REC”), which is
designed to recover renewable energy credits costs incurred by the
Company to comply with PURA § 39.904 and P.U.C. SUBST. R.
25.173. As set in this case, the Rider REC rate will recover
approximately $632 thousand.
14. To the extent any of the riders addressed above are not approved,
ETI proposes to recover the associated costs through its base rates or other rate
mechanism designed to recover non-fuel production-related costs.
15. The Company is not proposing a transmission cost recovery factor
or distribution cost recovery factor in this case, but the Company is seeking to
establish baseline values for future use when those two riders are implemented.
16. ETI’s Application affects all of its retail customers and all customer
classes. The increase in rates by rate class is set out in Attachment A. This
application has no effect on the rates of ETI’s wholesale customers.
17. Elements of ETI’s base rate case include the following:
(a) ETI is seeking to establish just and reasonable rates that
reflect its total revenue requirement, including affiliate transaction
payments, non-affiliate operations and maintenance expenses,
federal income tax expense, expenses for taxes other than income,
depreciation and amortization expense, and an authorized rate of
return that reflects a 10.6% return on common equity. The
6
The Company proposes that expenses eligible for reconciliation under Rider PPR also
include credits for Interruptible Service and Competitive Generation Service (“CGS”)
unrecovered costs, as well as fixed charges associated with Toledo Bend and the Southwest
Power Pool Reserve Sharing Group.
5
2011 ETI Rate Case 1-5
Company is also seeking to replenish its property insurance
reserve.
(b) ETI proposes a number of pro forma adjustments to its test
year results, as explained in the direct testimony of Company
witnesses.
(c) ETI is seeking to include in rate base capital additions closed
to plant in service from July 1, 2009 through the end of the test
year.
(d) In regard to affiliate transactions, ETI has divided its affiliate
payments into classes of service and is presenting testimony and
documentary evidence (e.g., discussion of budgeting and cost
control efforts, benchmarking results as available, review of the
costs of major components for each class, and headcount and
historical cost trends) for each class, demonstrating that the affiliate
transaction payments satisfy the standard for recovery set out in
PURA § 36.058. The prefiled direct testimony of ETI witness
Stephanie B. Tumminello explains how the evidence supporting
affiliate payments is organized.
18. To summarize, ETI’s filing proposes that the Commission establish
the Company’s revenue requirement as set out in the Rate Filing Package,
including a determination that the Company has satisfied PURA’s standards for
recovery of affiliate costs. ETI further requests that the Commission approve its
proposed rate riders, and ETI seeks good cause exceptions to the extent
necessary to comply with the Commission’s rules.
B. Class cost allocation and rate design
19. ETI’s filing also addresses cost allocation and rate design. This
includes: (1) inter- and intra-class cost allocation, (2) rate design, and (3) the
tariff schedules in RFP Schedule Q-8.8. The Company is proposing revisions to
its tariffs and rate schedules, including making modifications to eleven schedules,
adding two new rate schedule riders, and discontinuing two riders. The
Company also proposes minor modifications to a number of rate schedules,
6
2011 ETI Rate Case 1-6
which are detailed in the tariff manual on file with the Commission and each
municipality exercising original jurisdiction over Entergy Texas’ rates.
20. The eliminated rate schedule is:
Schedule Description
Rider RPSCOC Renewable Portfolio Standard Calculation
Opt-Out Credit Rider
21. The Company is proposing to make modifications to the following
rate schedules:
Schedule Description
MES Miscellaneous Electric Services
SMC Special Minimum Charge Rider to Schedules
SGS, GS and LGS
ALS Area Lighting Service
AFC Additional Facilities Charges Rider
SQF Rate for purchases From Qualifying Facilities
Less Than Or Equal to 100 KW Distributed
Generators
GS General Service
GS-TOD General Service-Time of Day
LGS Large General Service
LGS_TOD Large General Service-Time of Day
LIPS Large Industrial Power Service
LIPS-TOD Large Industrial Power Service-Time of Day
IS Rider to Schedule LIPS for Interruptible
Service
Agreement for Additional Facilities
DTK Agreement for Installation for Interval Data
Recorder Equipment
Agreement for Electric Service
Terms and Conditions Applicable for Electric
Service
22. In addition to the revenue requirement outlined in ¶ 12 above,
Schedule MES revenues will increase by approximately $911,000 as a result of
the proposed revisions to this rate schedule.
7
2011 ETI Rate Case 1-7
23. The new rate schedules/riders are:
(a) Rider PPR
(b) Rider REC
24. In addition, the production costs associated with the Company’s
CGS program will change as a result of this proceeding.
25. Consistent with the final order in ETI’s last rate case, Application of
Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs,
Docket No. 37744, the life-of-contract demand ratchet provision in rate schedules
Large Industrial Power Service, Large Industrial Power Service-Time of Day,
General Service, General Service-Time of Day, Large General Service, and
Large General Service-Time of Day shall be excluded from those rate schedules.
C. Rate case expenses
26. ETI’s filing also addresses rate case expenses. ETI is seeking to
recover its rate case expenses associated with this docket and any rate case
expenses associated with this docket that it must reimburse to local regulatory
authorities.
D. Fuel and purchased power reconciliation
27. Pursuant to P.U.C. SUBST. R. 25.236, ETI seeks reconciliation of its
fuel and purchased power costs and fuel factor revenues for the Reconciliation
Period. This Application will affect all of ETI’s retail customers taking service
under its fixed fuel factor (“Schedule FF”) by reconciling the fuel and purchased
power costs incurred and the fuel factor revenues received in providing service to
these customers during the Reconciliation Period.
28. During the Reconciliation Period, ETI incurred over $1.3 billion in
retail eligible fuel and purchased power expenses to generate and purchase
electricity, net of certain revenues properly credited to such expenses and other
adjustments. The following tables summarize the calculation, by fuel type, of
ETI’s total eligible fuel and purchased power costs to be reconciled in this
proceeding:
8
2011 ETI Rate Case 1-8
Gas and Oil $ 616,248,686
Emissions Allowances 360,236
Coal* 90,821,317
Total Fuel: $ 707,430,239
Purchased Power Expense 990,041,434
Off System Sales Revenues (376,671,969)
Total Purchased Power: 613,369,465
Total Texas Jurisdictional Fuel Factor Cost:** $ 1,320,799,704
Over-recovery Balance: $ 243,339,353
Sources: Schedules I-16, H-12.4a-g, H-12.5b-e, I-22, and Direct Testimonies of Margaret L.
McCloskey and Greg R. Zakrzewski.
*Includes cost of oil burned for start-up and flame stabilization.
**Amounts may not tie to Schedules due to rounding.
29. ETI’s reconciliation includes interest expense on any over/under-
recovery balance. ETI does not seek to implement a refund or surcharge of
eligible fuel or purchased power costs at the conclusion of this case; rather, ETI
proposes to roll any ending fuel balances forward to serve as the beginning
balance for the next Reconciliation Period.
30. The Company seeks a special circumstances finding to recover as
fuel expense the reversal of a prior FERC-ordered credit in the amount of
$99,715 that was previously included in the Company’s Incremental Purchased
Capacity Recovery Rider (“Rider IPCR”). The credit related to a FERC
proceeding that required the removal of interruptible load from the calculation of
each Operating Company’s responsibility ratio, resulting in ETI receiving a credit
for capacity costs incurred in 2008 that were included in Rider IPCR at that time.
FERC has since reversed its prior position and required the Company to refund
this amount to the other Operating Companies. Louisiana Public Service Corp.
et al. v. Entergy Corp., 135 FERC ¶ 61,218 (2011). Federal law requires that
such a FERC-ordered refund be passed through to retail customers. Id. at P 6.
The Company seeks a special circumstances finding to treat the
repayment to the other Operating Companies as fuel expense to be consistent
with a settlement approved in Docket No. 37744, which treated the residual Rider
IPCR balance as fuel expense. Application of Entergy Texas, Inc., for Authority
9
2011 ETI Rate Case 1-9
to Change Rates and Reconcile Fuel Costs, Docket No. 37744, Final Order at
FoF 30 (Dec. 13, 2010). ETI seeks the same treatment in this case because the
repayment is a residual amount of Rider IPCR costs, except that ETI proposes to
allocate the costs among customer classes on an energy basis in light of the
nominal amount.
31. ETI’s Rate Filing Package demonstrates that: (1) ETI’s fuel and
purchased power expenses were reasonable and necessary expenses incurred
to provide reliable electric service; and (2) to the extent fuel and purchased
power expenses included an item or class of items supplied by an affiliate of ETI,
the price charged by the affiliate satisfies the standard for recovery set out in
PURA § 36.058.
V. Notice
32. ETI will provide notice in accordance with PURA § 36.103, P.U.C.
PROC. R. 22.51(a), and P.U.C. SUBST. R. 25.235. The proposed notice is
provided as Attachment B to this Application.
VI. Municipal Filings
33. Simultaneously with filing this Application with the Commission, ETI
is filing a Statement of Intent to change its rates with all local regulatory
authorities that retain jurisdiction over ETI’s rates to the extent consistent with the
provisions of PURA. Depending on the actions taken by the local regulatory
authorities, ETI may appeal the municipal rate ordinances to the Commission
and request that the Commission consolidate those appeals with this docket and,
if necessary, set the rates that the local regulatory authorities should have set,
pursuant to PURA § 33.054.
VII. Request for Waiver of Rate Filing Package Requirements
34. For the reasons stated in RFP Schedule V, ETI requests that the
Commission waive certain Rate Filing Package filing requirements.
10
2011 ETI Rate Case 1-10
VIII. Confidentiality Provisions
35. Certain of ETI’s fuel and purchased power contracts contain
provisions that require the Company to maintain the confidentiality of these
contracts and data related to these contracts. In addition, certain information
required by the Commission’s Rate Filing Package consists of proprietary,
market-sensitive information that is confidential or highly sensitive data or that
unaffiliated third parties have provided to the Company under agreements
restricting dissemination. Finally, certain components of and documents included
in ETI’s prefiled direct testimony and/or workpapers include confidential and/or
highly sensitive information.
36. To facilitate evaluation of this information by the Commission Staff
and other parties, the Company has prepared a Protective Order that is
contained in RFP Schedule W. ETI requests that the Protective Order (Schedule
W) be adopted for use in this proceeding.
37. Attachment C to this Application presents a complete listing of the
information required to be filed in the Commission’s Rate Filing Package that the
Company designates as confidential or highly sensitive. Pending issuance of a
Protective Order in this case, the confidential or highly sensitive information will
be made available at the Company’s offices, 919 Congress Avenue, Suite 840,
Austin, Texas 78701, telephone number (512) 487-3999, during normal business
hours to parties who execute a confidentiality disclosure agreement.
IX. Conclusion and Request for Relief
For the reasons set out in this Application, the accompanying direct
testimony, and the Rate Filing Package, ETI requests that the Commission: (1)
grant the requested relief to the full extent of the Commission’s jurisdiction; (2)
find that notice of this filing be considered sufficient; and (3) grant ETI such other
relief that it is entitled to receive.
Dated: November 28, 2011.
11
2011 ETI Rate Case 1-11
Respectfully submitted,
Steven H. Neinast
Paula Cyr
Assistants General Counsel
ENTERGY SERVICES, INC.
919 Congress Avenue, Suite 701
Austin, Texas 78701
(512) 487-3957 telephone
(512) 487-3958 facsimile
DUGGINS WREN MANN & ROMERO, LLP
One American Center
600 Congress, Suite 1900
P.O. Box 1149
Austin, Texas 78767-1149
(512) 744-9300 telephone
(512) 744-9399 facsimile
John F. Williams
Jay Breedveld
12
2011 ETI Rate Case 1-12
ATTACHMENT A
ENTERGY TEXAS, INC.
INCREASE BY RATE CLASS WITH RIDERS
FOR THE TWELVE MONTHS ENDING JUNE 30, 2011
Number of Base Revenue Percent
Customers Present Present Total Proposed Proposed Proposed Proposed Total Change To and Riders Change
Test Year Base Rate Rider Present Present Base Rate Rider PPR Rider REC Rider Proposed Proposed Total Percent Total
2011 ETI Rate Case
Rate Class Adjusted Revenue Revenue (1) Fuel Revenue Revenue Revenue (1) Revenue Revenue Fuel Revenue Revenue Change Revenues
(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) (o)
(g)+(h)+(i)
(c)+(d)+(e) +(j)+(k) (l)-(f) (m)]/((c)+(d)) (m)/(f)
Residential
Service 359,707 $ 325,744,455 $ 53,637,192 $ 232,546,816 $ 611,928,463 $ 271,808,430 $ 53,637,192 $ 135,702,041 $ 329,063 $ 232,546,816 $ 694,023,542 $ 82,095,079 21.64% 13.42%
Small
General
Service 30,998 $ 22,562,013 $ 3,867,520 $ 12,957,514 $ 39,387,047 $ 16,969,307 $ 3,867,520 $ 6,003,125 $ 18,335 $ 12,957,514 $ 39,815,801 $ 428,754 1.62% 1.09%
General
Service 19,156 $ 135,404,167 $ 24,363,668 $ 135,331,429 $ 295,099,264 $ 91,350,968 $ 24,363,668 $ 51,554,797 $ 188,900 $ 135,331,429 $ 302,789,762 $ 7,690,498 4.81% 2.61%
Large
General
Service 361 $ 42,430,160 $ 6,949,815 $ 62,652,322 $ 112,032,297 $ 30,269,687 $ 6,949,815 $ 20,247,492 $ 84,677 $ 62,652,322 $ 120,203,993 $ 8,171,696 16.55% 7.29%
Large
Industrial
Power
Service 82 $ 100,482,959 $ 3,825,264 $ 204,909,461 $ 309,217,684 $ 53,366,022 $ 3,825,264 $ 58,342,383 $ 8,451 $ 204,909,461 $ 320,451,581 $ 11,233,897 10.77% 3.63%
Lighting
Service 1,689 $ 7,490,488 $ 3,322,394 $ 3,222,163 $ 14,035,045 $ 8,860,430 $ 3,322,394 $ 829,439 $ 4,559 $ 3,222,163 $ 16,238,985 $ 2,203,940 20.38% 15.70%
Total Retail (2) 411,993 $ 634,114,242 $ 95,965,853 $ 651,619,705 $ 1,381,699,800 $ 472,624,844 $ 95,965,853 $ 272,679,277 $ 633,985 $ 651,619,705 $ 1,493,523,664 $ 111,823,864 15.32% 8.09%
(1) Riders: TTC, HRC, EECRF, RCE, IS, SRC & SCO which are the same for present and proposed
(2) Excludes EAPS and SMS
1-13
Sponsor: Joseph F. Domino Docket No. 39896
Entergy Texas’s Statement of Intent and Application
Attachment B
Schedule T
Page 1 of 3
NOTICE OF RATE CHANGE REQUEST
On November 28, 2011, Entergy Texas, Inc. (“Entergy Texas”) filed its
STATEMENT OF INTENT AND APPLICATION FOR AUTHORITY TO CHANGE
RATES AND RECONCILE FUEL COSTS (“Application”). Entergy Texas filed its
Application with the Public Utility Commission of Texas (“Commission”) and with
those municipal authorities in its service territory that have original jurisdiction
over Entergy Texas’ electric rates.
Statement of Intent to Change Rates and to Reconcile Fuel Costs
Entergy Texas’ filing requests an increase in rates, addresses capital
additions to rate base for the period July 2009 through June 2011, requests that
the Commission reconcile fuel and purchased power expenses incurred during
the period July 2009 through June 2011 (“Reconciliation Period”), and requests
approval of a number of tariffs, cost recovery schedules and riders.
In its Application, Entergy Texas is, among other things:
x Proposing base rate tariffs and riders designed to collect a total
non-fuel retail revenue requirement for ETI of approximately $841.9 million per
year, which is an increase of $111.8 million, or 15.32%, compared to adjusted
retail base rate and rider revenues resulting from the Commission’s Order in
Docket No. 37744. The Company’s proposed rate increase is based on the test
year period of July 1, 2010 through June 30, 2011. This proposal represents an
increase in overall revenues, including fuel, of 8.09%.
x Asking to reconcile fuel and purchased power costs of
approximately $1.3 billion incurred during the Reconciliation Period. The
reconciliation includes interest on any over- or (under)-recovered amounts.
Entergy Texas does not seek to implement a fuel-related refund or surcharge of
its eligible fuel costs in this case; rather, ETI proposes to roll any ending fuel
balances forward to serve as the beginning balance for the next Reconciliation
Period.
Tariff Revisions
Entergy Texas is proposing to add two new rate schedules or riders as
follows:
o A Purchased Power Recovery Rider (“Rider PPR”), which is
designed to recover all existing purchased capacity costs as well as
future purchased capacity costs. As set in this case, Rider PPR will
recover approximately $272.7 million annually. ETI’s request
2011 ETI Rate Case 1-14
Sponsor: Joseph F. Domino Docket No. 39896
Entergy Texas’s Statement of Intent and Application
Attachment B
Schedule T
Page 2 of 3
includes (1) a mechanism to update the rider annually to reflect
increases or decreases in purchased capacity costs as incurred by
the Company, and (2) the reconciliation of costs recovered under
the rider in the Company’s fuel reconciliation cases. The Company
proposes that expenses eligible for reconciliation under Rider PPR
also include credits for Interruptible Service and Competitive
Generation Service unrecovered costs, as well as fixed charges
associated with Toledo Bend and the Southwest Power Pool
Reserve Sharing Group.
o A Renewable Energy Credits Rider (“Rider REC”), which is
designed to recover renewable energy credits costs and related
costs incurred by the Company to comply with PURA § 39.904 and
P.U.C. Subst. R. 25.173. As set in this case, the Rider REC rate
will recover approximately $632 thousand.
To the extent any of the riders described above are not approved, Entergy
Texas proposes to recover the associated costs through its base rates or other
rate mechanism designed to recover non-fuel production-related costs, though
the overall non-fuel revenue increase referenced above will remain the same. In
addition, Entergy Texas is proposing to establish baseline values to use if a
transmission cost recovery factor or distribution cost recovery factor are
implemented in the future.
In addition, Entergy Texas is proposing to modify terms and charges in a
number of its tariff schedules and to discontinue its Renewable Portfolio
Standard Calculation Opt-Out Credit Rider. Proposed changes to Schedule
Miscellaneous Electric Service (“MES”) will increase revenues by approximately
$911,000 in addition to the retail revenue requirement stated above. The
production costs associated with the Company’s proposed Competitive
Generation Service program will also change as a result of this proceeding.
Entergy Texas also proposes minor modifications to a number of rate schedules,
which are detailed in the tariff manual on file with the Commission and each
municipality exercising original jurisdiction over Entergy Texas’ rates.
Effect on Customer Classes
All customers and classes of customers receiving retail electric service
from Entergy Texas will be affected by the proposed rate changes and
reconciliation of fuel and purchased power costs contained in the Application.
The following table shows the effect of the proposed rate increase (inclusive of
riders but exclusive of the increase in Schedule MES revenues) on existing rate
classes:
2011 ETI Rate Case 1-15
Sponsor: Joseph F. Domino Docket No. 39896
Entergy Texas’s Statement of Intent and Application
Attachment B
Schedule T
Page 3 of 3
Number of Percent Change
Customers Test in Non-Fuel Percent Change in
Rate Class Year Adjusted Revenues Total Revenues*
Residential Service 359,707 21.64% 13.42%
Small General Service 30,998 1.62% 1.09%
General Service 19,156 4.81% 2.61%
Large General
Service 361 16.55% 7.29%
Large Industrial
Power Service 82 10.77% 3.63%
Lighting Service 1,689 20.38% 15.70%
Total Retail 411,993 15.32% 8.09%
* including fuel revenues
The effective date of the rate change is January 2, 2012.
Contact Information
Persons with questions or who want more information on this filing may
contact Entergy Texas at Entergy Texas, Inc., Attn: Customer Service—2011
Rate Case, 350 Pine Street, Beaumont, Texas 77701, or call [1-800-368-3749
(select option 1, then press 0, then press 4, then press 3)] during normal
business hours. A complete copy of this application is available for inspection at
the address listed above.
Persons who wish to intervene in or comment upon these proceedings
should notify the Public Utility Commission of Texas as soon as possible, as an
intervention deadline will be imposed. A request to intervene or for further
information should be mailed to the Public Utility Commission of Texas, P.O. Box
13326, Austin, Texas 78711-3326. Further information may also be obtained by
calling the Public Utility Commission at (512) 936-7120 or (888) 782-8477.
Hearing- and speech-impaired individuals with text telephones (TTY) may
contact the commission at (512) 936-7136. The deadline for intervention in this
proceeding is 45 days after the date the application was filed with the
Commission. All communications should refer to Docket No. 39896.
2011 ETI Rate Case 1-16
Application Attachment C
2011 Texas Rate Case
Page 1 of 4
List of Confidential (Protected Material)/ Highly Sensitive (Highly Sensitive Protected
Material) Information
The following is a list of schedules, exhibits and workpapers that are included in this
Application and considered by Entergy Texas, Inc. (“the Company”) to be Confidential
(Protected Material) or Highly Sensitive (Highly Sensitive Protected Material) information, the
protected designation, the reason for protection and a list of the witnesses sponsoring the
Confidential (Protected Material) or Highly Sensitive (Highly Sensitive Protected Material)
information or the schedule to which the information relates. The Company considers the
information listed below to be commercial or financial information or customer specific
information that is exempted from disclosure under the Public Information Act. TEX. GOV’T
CODE ANN. §§ 552.101 and 552.110 (Vernon 2009); TEX. UTIL. CODE § 32.101(c) (Vernon
2009).
DOCUMENT DESIGNATION REASON FOR SPONSOR
PROTECTION
Rate Filing Package
Schedule B-2 Highly Sensitive Proprietary Information Considine, Michael P.
WP/E-2.2 Attachment 3 Highly Sensitive Proprietary Information Trushenski, Ryan S.;
McIlvoy, Karen D.;
Considine, Michael P.
WP/E-2.2 Attachment 4 Highly Sensitive Proprietary Information Trushenski, Ryan S.;
McIlvoy, Karen D.;
Considine, Michael P.
Schedule G-5.1 Confidential Proprietary Information Considine, Michael P.
Schedule G-5.1a Confidential Proprietary Information Considine, Michael P.
Schedule G-7.3 Highly Sensitive Proprietary Information Roberts, Rory L.
WP/G-7.3 Highly Sensitive Proprietary Information Roberts, Rory L.
WP/G-7.13 Highly Sensitive Proprietary Information Roberts, Rory L.;
Considine, Michael P.
Schedule H-5.3b Confidential Proprietary Information Garrison, W. Wayne
Schedule H-6.2c Confidential Proprietary Information Garrison, W. Wayne
Schedule H-7.2 Confidential Proprietary Information Garrison, W. Wayne
Schedule H-7.4 Confidential Staffing Projections Garrison, W. Wayne
Schedule H-12.3c Confidential Proprietary Information Garrison, W. Wayne
Schedule H-13.2 Highly Sensitive Proprietary Information McCulla, Mark
2011 ETI Rate Case 1-17
Application Attachment C
2011 Texas Rate Case
Page 2 of 4
Schedule I-1.2 Highly Sensitive Contractual/Proprietary Jaycox, Devon S.;
Information Zakrzewski, Gregory R.;
Trushenski, Ryan S.;
McIlvoy, Karen D.;
Thiry, Michelle H.
Schedule I-4 Confidential/Highly Contractual/Proprietary Cooper, Robert R.;
Sensitive Information Thiry, Michelle, H.
McIlvoy, Karen D.;
Trushenski, Ryan S.
WP/I-4 Confidential/Highly Contractual/Proprietary Cooper, Robert R.;
Sensitive Information Thiry, Michelle, H.
McIlvoy, Karen D.;
Trushenski, Ryan S.
Schedule I-15 Confidential Contractual/Proprietary Cooper, Robert R.;
Information Trushenski, Ryan S.;
McIlvoy, Karen D.;
Thiry, Michelle H.
WP/I-15 Confidential/Highly Contractual/Proprietary Cooper, Robert R.;
Sensitive Information Trushenski, Ryan S.;
McIlvoy, Karen D.;
Thiry, Michelle H.
Schedule I-16 Highly Sensitive Contractual/Proprietary Trushenski, Ryan S.;
Information McIlvoy, Karen D.;
Zakrzewski, Gregory R.
Schedule I-16.3 Highly Sensitive Contractual/Proprietary Trushenski, Ryan S.;
Information McIlvoy, Karen D.
Schedule I-17.1 Highly Sensitive Contractual/Proprietary Trushenski, Ryan S.;
Information Zakrzewski, Gregory R.
WP/I-21 Confidential Financial Forecasts Thiry, Michelle H.
Schedule K-5 Highly Sensitive Financial Forecasts Barrilleaux, Chris E.;
Considine, Michael P.
Schedule K-6 Highly Sensitive Financial Forecasts Barrilleaux, Chris E. ;
Considine, Michael P.
Schedule K-7 Highly Sensitive Financial Forecasts Barrilleaux, Chris E.
Schedule M-1 Confidential Contractual/Proprietary Considine, Michael P.
Attachment 1 Information
Schedule M-1 Confidential Contractual/Proprietary Considine, Michael P.
Attachment 3 Information
Schedule M-1 Confidential Proprietary Information Considine, Michael P.
Attachment 6
Schedule M-1 Confidential Contractual/Proprietary Considine, Michael P.
Attachment 7 Information
WP2/M-2 Confidential Contractual/Proprietary Considine, Michael P.
Information
Schedule Q-8.1 Highly Sensitive Financial Forecasts Cicio, Patrick J.
Schedule Q-8.2 Highly Sensitive Financial Jaycox, Devon S.
Forecasts/Proprietary
Information
2011 ETI Rate Case 1-18
Application Attachment C
2011 Texas Rate Case
Page 3 of 4
Schedule Q-8.3 Highly Sensitive Proprietary Information Cooper, Robert R.
Schedule Q-8.4 Highly Sensitive Staffing Cooper, Robert R.
Projections/Proprietary
Information
Schedule S-2 Highly Sensitive Proprietary Information NA
Testimonial Exhibits
and Workpapers
(Listed in order by
sponsor)
Testimony pp. 10-12, Highly Sensitive Competitive Information Barrilleaux, Chris E.
14-15, 26 and 28
WP/CEB Testimony 1 Highly Sensitive Competitive Information Barrilleaux, Chris E.
WP/CEB Testimony 2 Highly Sensitive Competitive Information Barrilleaux, Chris E.
WP/CEB Testimony 3 Highly Sensitive Competitive Information Barrilleaux, Chris E.
Exhibit RRC-1 Highly Sensitive Proprietary/Commercially Cooper, Robert R.
Sensitive Information
WP/RRC Testimony 2 Highly Sensitive Proprietary/Commercially Cooper, Robert R.
Sensitive Information
Exhibit KGG-4 Highly Sensitive Compensation Information Gardner, Kevin G.
Exhibit KGG-5 Highly Sensitive Compensation Information Gardner, Kevin G.
Exhibit CNH-9 Confidential Proprietary Information Herrington, Chester N.
Exhibit CNH-12 Confidential Proprietary Information Herrington, Chester N.
Exhibit JMH-4 Confidential Competitively Sensitive Hunter, Joseph M.
WP/JJJ-3 Confidential Competitively Sensitive Joyce, Jay J.
Contractual/Proprietary
Information
Compensation Information
WP/KDM Testimony Highly Sensitive Proprietary Gas Contract McIlvoy, Karen D.
Pricing Information
Exhibit RLR-5 Highly Sensitive Proprietary Information Roberts, Rory L.
Exhibit RLR-6 Highly Sensitive Proprietary Information Roberts, Rory L.
WP/RDS Testimony Highly Sensitive Proprietary Information Sloan, Robert D.
WP/MHT Testimony 1 Highly Sensitive Proprietary/Trade Thiry, Michelle H.
Information
WP/MHT Testimony 2 Highly Sensitive Proprietary/Trade Thiry, Michelle H.
Information
WP/GSW-2 Highly Sensitive Proprietary Information Wilson, Greg S.
2011 ETI Rate Case 1-19
Application Attachment C
2011 Texas Rate Case
Page 4 of 4
I certify that I have reviewed the documents listed above and state in good faith that the
information is exempt from public disclosure under the Public Information Act and merits the
applicable designation of Confidential (Protected) Materials or Highly Sensitive (Highly
Sensitive Protected) Materials detailed in the Protective Order accompanying this Application.
~~~
2011 ETI Rate Case 1-20
SOAH Docket No. XXX-XX-XXXX
PUC Docket No. 39896
ETI 2011 Rate Case
ETI EXHIBIT NO. 8
DOCKET NO. 39896
APPLICATION OF ENTERGY § PUBLIC UTILITY COMMISSION
TEXAS, INC. FOR AUTHORITY §
TO CHANGE RATES AND § OF TEXAS
RECONCILE FUEL COSTS §
DIRECT TESTIMONY
OF
MICHAEL P. CONSIDINE
ON BEHALF OF
ENTERGY TEXAS, INC.
NOVEMBER 2011
2011 ETI Rate Case 3-279
ENTERGY TEXAS, INC.
DIRECT TESTIMONY OF MICHAEL P. CONSIDINE
2011 RATE CASE
TABLE OF CONTENTS
Page
I.  Witness Introduction and Qualifications 1
II.  Purpose of Testimony 2
III.  PURA Sections 36.059 through 36.062 4
A.  Section 36.059 – Treatment of Certain Tax Benefits 5
B.  Section 36.061 – Allowance of Certain Expenses and Section
36.062 – Consideration of Certain Expenses 6
1.  Legislative Advocacy Expenses 6
2.  Charitable Contributions 7
3.  Outside Services 7
4.  Rate Case Expenses 8
5.  Civil Penalties and Fines 8
6.  Disallowed Payments for Costs of Facilities not Selling
Power in the State of Texas 8
7.  Costs of Processing Refunds or Credits 9
IV.  PUC Substantive Rule 25.231(b) 9
V.  Cost of Service 11
A.  Schedule A – Overall Cost of Service 11
1.  Adjustments 13
a)  Local Franchise Tax Adjustment (Adjustment 7) 15
b)  Property Insurance Reserve (Adjustment 8) 15
c)  Margins Tax (Adjustment 9) 16
d)  Income Taxes (Adjustment 10) 16
2011 ETI Rate Case 3-280
e)  Rate Case Expense (Adjustment 11) 18
f)  Trade Association Dues/Legislative Advocacy
(Adjustment 12) 18
g)  Depreciation Expense (Adjustment 13) 19
h)  Depreciation Study Adjustment (Adjustment 14) 19
i)  Hurricane Securitization (Adjustment 15) 20
j)  Miscellaneous Adjustments (Adjustment 16) 21
k)  Interest Synchronization (Adjustment 17) 22
l)  Customer Deposits and ESI Interest Expense
(Adjustment 18) 22
m)  SFAS 106 (Adjustment 19) 23
n)  Pension Expense (Adjustment 20) 24
o)  Payroll Expense (Adjustment 22) 24
p)  Service Schedule MSS-2 Adjustment
(Adjustment 23) 25
q)  Capacity Adjustment (Adjustment 24) 25
r)  Property Tax (Adjustment 25) 26
2.  Trial Balances, Schedule A-4 26
B.  Schedule B - Rate Base and Return 27
1.  Rate Base Adjustments 27
a)  Cash Working Capital (Adjustment 6) 27
b)  Income Tax (Adjustment 10) 28
2.  Schedules B-1.1 through B-2.1 28
C.  Schedule C – Original Cost of Plant 29
D.  Schedule D – Accumulated Depreciation 31
E.  Schedule E – Short-Term Assets and Inventories 33
2011 ETI Rate Case 3-281
F.  Schedule G – Accounting Information 35
1.  Payroll Schedules 35
2.  Pensions and Benefits Schedules 37
3.  Bad Debt Expense Schedule 38
4.  Advertising, Contributions, and Dues Schedules 38
5.  Exclusions from Test Period Schedules 40
6.  Income Tax Schedules 41
7.  Outside Services Schedule 49
8.  Taxes Other Than Income Tax Schedules 50
9.  Factoring Expense Schedule 50
10.  Deferred Expense Information Schedule 50
11.  Below the Line Expenses Schedule 51
12.  Non-Recurring Expense Schedule 51
13.  Rate Case Expense Schedules 52
14.  Monthly O&M Schedules 52
G.  Schedule H – Engineering Information 53
H.  Schedule J – Financial Statements 54
I.  Schedule K – Financial Information 55
J.  Schedule M – Nuclear Plant Decommissioning 57
K.  Schedule P – Class Cost of Service Analysis 58
L.  Schedule S – Test Year Review 58
VI.  Rate Case Expenses 60
VII.  Conclusion 62
2011 ETI Rate Case 3-282
EXHIBITS
Exhibit MPC-1 Listing of Rate Filing Packages Schedules Sponsored
or Co-Sponsored by Michael P. Considine
Exhibit MPC-2 Nuclear Regulatory Commission Letter dated August 9, 2011
2011 ETI Rate Case 3-283
Entergy Texas, Inc. Page 1 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 I. WITNESS INTRODUCTION AND QUALIFICATIONS
2 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
3 A. My name is Michael P. Considine. My business address is 425 West
4 Capitol Avenue, Little Rock, Arkansas 72201. I am employed by Entergy
5 Services, Inc., the service company affiliate of Entergy Texas, Inc. (“ETI”
6 or the “Company”) as a Senior Staff Accountant in the Rate Design and
7 Administration Department.
8
9 Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?
10 A. I am testifying on behalf of Entergy Texas, Inc. (“ETI” or the “Company”).
11
12 Q. DESCRIBE BRIEFLY YOUR EDUCATIONAL BACKGROUND AND
13 PROFESSIONAL EXPERIENCE.
14 A. I received a Bachelor of Science Degree in Professional Accountancy
15 from Louisiana Tech University in 2000. I began my career with Alltel
16 Communications, first as an accountant in the general accounting
17 department, and then as a financial analyst in the financial planning
18 department. In October 2001, I accepted a position as an analyst in the
19 Transmission Business Operations department of Entergy Services, Inc.
20 In this regard, I was responsible for Open Access Transmission Tariff
21 (“OATT”) monthly billings and the development of enhanced billing
22 processes for OATT customers. I transferred to the Rate Design and
2011 ETI Rate Case 3-284
Entergy Texas, Inc. Page 2 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Administration Department in September 2003. In December 2010, I
2 accepted my current position in the Regulatory Accounting Department.
3
4 Q. WHAT ARE YOUR PRINCIPAL AREAS OF RESPONSIBILITY?
5 A. I provide general regulatory support, including the analysis and
6 development of rate design and external allocation factors for use in cost-
7 of-service analyses, for Entergy’s six Operating Companies (Entergy
8 Arkansas, Inc.; Entergy Gulf States Louisiana, L.L.C.; Entergy Louisiana,
9 LLC; Entergy Mississippi, Inc.; Entergy New Orleans, Inc.; and ETI). I am
10 also responsible for preparation and filing of the Company’s monthly Fuel
11 Reports with the Public Utility Commission of Texas (the “Commission”),
12 including the calculation of the monthly over(under)-recovery of fuel
13 expenses.
14
15 II. PURPOSE OF TESTIMONY
16 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
17 A. The purpose of my testimony is to support the Company's per books test
18 year accounting data, capital structure, and certain pro forma adjustments.
19 In addition, I will present ETI’s regulatory treatment of legislative advocacy
20 expenses, advertising expense, donations and contributions, outside
21 services, income taxes, and dues and memberships. I will also address
22 rate case expenses.
2011 ETI Rate Case 3-285
Entergy Texas, Inc. Page 3 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. WHAT TEST YEAR DOES ETI USE IN THIS FILING?
2 A. This filing uses the twelve months ended June 30, 2011.
3
4 Q. DO YOU SPONSOR OR CO-SPONSOR ANY SCHEDULES IN THE
5 RATE FILING PACKAGE (“RFP”) THAT HAVE BEEN FILED IN THIS
6 PROCEEDING?
7 A. Yes, I sponsor or co-sponsor several schedules filed in this proceeding.
8 Exhibit MPC-1 indicates the schedules that I am sponsoring or
9 co-sponsoring with other witnesses. In addition, for convenience, Exhibit
10 MPC-1 shows the titles of all the schedules that I discuss in my testimony.
11 Unless otherwise indicated, the schedules were prepared by me or under
12 my direct supervision and control.
13
14 Q. ON WHAT BASIS WERE THE SCHEDULES THAT YOU JUST
15 MENTIONED PREPARED?
16 A. They were prepared from the books and records of the Company and are
17 accurate summaries of the business records upon which they are based.
18 The schedules have been examined by Deloitte & Touche, our
19 independent auditors. The report of their examination is included in
20 Schedule S of the RFP.
2011 ETI Rate Case 3-286
Entergy Texas, Inc. Page 4 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. ARE THE BOOKS, ACCOUNTS, AND RECORDS OF THE COMPANY
2 MAINTAINED IN A MANNER PRESCRIBED BY THE COMMISSION?
3 A. Yes, they are kept in compliance with the FERC Uniform System of
4 Accounts as prescribed in Section 14.151 of the Public Utility Regulatory
5 Act (“PURA”), and in P.U.C. SUBST. R. 25.72(b)(1), (c)(1), and (e)
6 through (g). The records are maintained in New Orleans, Louisiana as
7 approved by this Commission in Docket No. 13017.
8
9 III. PURA SECTIONS 36.059 THROUGH 36.062
10 Q. SECTIONS 36.059 THROUGH 36.062 OF PURA PROVIDE FOR
11 SPECIFIC TREATMENT OR EXCLUSION OF CERTAIN ITEMS FOR
12 RATEMAKING PURPOSES. DOES THE COMPANY'S FILING COMPLY
13 WITH THESE SECTIONS OF PURA?
14 A. Yes. ETI has fully complied with PURA Sections 36.059 through 36.062.
15 This filing includes only reasonable and necessary costs that are allowed
16 under PURA, and excludes any costs specifically prohibited. Company
17 witness Rory L. Roberts discusses PURA Section 36.060 (consolidated
18 income tax returns) in his testimony. The following discussion addresses
19 the items specifically set out in Sections 36.059, 36.061, and 36.062 of
20 PURA.
2011 ETI Rate Case 3-287
Entergy Texas, Inc. Page 5 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 A. Section 36.059 – Treatment of Certain Tax Benefits
2 Q. HAS THE COMPANY COMPLIED WITH THE TREATMENT OF TAX
3 BENEFITS AS REQUIRED BY SECTION 36.059?
4 A. Yes. Section 36.059 requires:
5 (a) In determining the allocation of tax savings derived from
6 liberalized depreciation and amortization, the investment tax
7 credit, and the application of similar methods, the regulatory
8 authority shall:
9 (1) balance equitably the interests of present and future
10 customers; and
11
12 (2) apportion accordingly the benefits between
13 consumers and the electric or municipally owned
14 utility.
15
16 (b) If an electric utility or a municipally owned utility retains a
17 portion of the investment tax credit, that portion shall be
18 deducted from the original cost of the facilities or other
19 addition to the rate base to which the credit applied to the
20 extent allowed by the Internal Revenue Code.
21 ETI has computed its cost of service in compliance with this
22 provision of PURA and has applied the investment tax credit (“ITC”)
23 balances to the extent allowed by the Internal Revenue Code (“Code”).
24 RFP Schedule G-7.5, Analysis of ITC, illustrates that the Company is
25 amortizing its ITC no more rapidly than ratably, as required by the Code.
2011 ETI Rate Case 3-288
Entergy Texas, Inc. Page 6 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 B. Section 36.061 – Allowance of Certain Expenses and Section 36.062 –
2 Consideration of Certain Expenses
3 1. Legislative Advocacy Expenses
4 Q. PURA PROVIDES THAT LEGISLATIVE ADVOCACY EXPENSES ARE
5 NOT TO BE INCLUDED IN COST OF SERVICE FOR RATEMAKING
6 PURPOSES. DOES THIS FILING INCLUDE LEGISLATIVE ADVOCACY
7 EXPENSES?
8 A. No. All expenditures made by ETI for the purposes of advocating the
9 Company's position to the public with respect to referenda, legislation, or
10 ordinances, or for the purpose of advocating its position on such items
11 before public officials, are excluded from cost of service. The excluded
12 expenses include the costs of the Company lobbyists, as well as the
13 portion of the Company's dues to the Edison Electric Institute (“EEI”) that
14 are used for legislative advocacy purposes. The legislative expenses
15 associated with EEI and the quantification of the EEI dues excluded are
16 addressed later in my testimony. The expenses, other than the EEI dues
17 described above, are recorded in Account 426.4, which is a non-operating
18 expense account (below the line) that is not included in cost of service.
2011 ETI Rate Case 3-289
Entergy Texas, Inc. Page 7 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. ARE THERE ANY LEGISLATIVE ADVOCACY EXPENSES INCLUDED IN
2 PAYMENTS TO AFFILIATED INTERESTS IN THE COMPANY'S
3 REQUESTED COST OF SERVICE?
4 A. No. Although expenses for legislative advocacy are included in the billings
5 from ESI, such expenses have been excluded from ETI's requested cost
6 of service.
7
8 2. Charitable Contributions
9 Q. HAS THE COMPANY INCLUDED CHARITABLE CONTRIBUTIONS IN
10 ITS COST OF SERVICE?
11 A. No.
12
13 3. Outside Services
14 Q. HAS THE COMPANY INCLUDED COSTS FOR OUTSIDE SERVICES IN
15 ITS REQUESTED COST OF SERVICE?
16 A. Yes. Outside services are required for several reasons. Sound business
17 practice and regulatory and legal requirements result in the need for
18 auditing and accounting services. Further, consultants with specialized
19 expertise and outside legal counsel are employed to provide for various
20 specific needs.
2011 ETI Rate Case 3-290
Entergy Texas, Inc. Page 8 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 4. Rate Case Expenses
2 Q. IS THE COMPANY REQUESTING THE INCLUSION IN COST OF
3 SERVICE RATE CASE EXPENSES RELATED TO THIS FILING?
4 A. Yes. As will be discussed later in my testimony, the Company is
5 requesting recovery in cost of service of the rate case expenses
6 associated with this filing.
7
8 5. Civil Penalties and Fines
9 Q. HAS THE COMPANY INCLUDED IN ITS COST OF SERVICE OR RATE
10 BASE ANY CIVIL PENALTIES OR FINES?
11 A. No. These amounts were recorded in non-operating expense accounts
12 (below the line) and are not included in cost of service.
13
14 6. Disallowed Payments for Costs of Facilities
15 not Selling Power in the State of Texas
16 Q. HAS THE COMPANY INCLUDED IN ITS COST OF SERVICE ANY
17 PAYMENTS, EXCEPT THOSE MADE UNDER AN INSURANCE OR
18 RISK-SHARING ARRANGEMENT EXECUTED BEFORE THE DATE OF
19 LOSS, MADE TO COVER COSTS OF AN ACCIDENT, EQUIPMENT
20 FAILURE, OR NEGLIGENCE AT A UTILITY FACILITY OWNED BY A
21 PERSON OR GOVERNMENTAL BODY NOT SELLING POWER INSIDE
22 THE STATE OF TEXAS?
23 A. No.
2011 ETI Rate Case 3-291
Entergy Texas, Inc. Page 9 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 7. Costs of Processing Refunds or Credits
2 Q. HAS THE COMPANY INCLUDED IN ITS COST OF SERVICE ANY COST
3 OF PROCESSING A REFUND OR CREDIT UNDER SECTION 36.110
4 OF PURA?
5 A. No. No such expenses were incurred during the test year.
6
7 IV. PUC SUBSTANTIVE RULE 25.231(B)
8 Q. ARE ADVERTISING EXPENSES INCLUDED IN THE COST OF
9 SERVICE PROPOSED BY THE COMPANY IN THIS FILING?
10 A. Yes. They are included as allowed by P.U.C. SUBST. R. 25.231(b)(1)(E).
11 However, advertising to promote the increased consumption of electricity
12 and advertising to promote the industry are excluded from cost of service
13 as required by P.U.C. SUBST. R. 25.231(b)(2).
14
15 Q. WHAT WERE THE COMPANY'S ADVERTISING COSTS DURING THE
16 TEST YEAR?
17 A. The advertising costs for the test year included in the cost of service total
18 $1,194,000 which is approximately .08% of gross revenues. These costs
19 are detailed in Schedule G-4.1.
2011 ETI Rate Case 3-292
Entergy Texas, Inc. Page 10 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. DOES THIS FILING INCLUDE CONTRIBUTIONS OR DONATIONS IN
2 THE COST OF SERVICE?
3 A. No. Schedule G-4.2 shows the details of the contributions and donations
4 that have been excluded from the cost of service, including contributions
5 and donations from the Company's affiliates.
6
7 Q. PLEASE DESCRIBE THE DUES AND MEMBERSHIPS THAT ARE
8 INCLUDED IN ETI’S COST OF SERVICE.
9 A. Industry and professional association dues are included in the filing only to
10 the extent they comply with the Commission's Substantive Rules. The
11 total advertising, dues, and memberships expense included in the cost of
12 service is less than .1% of gross revenues, which is within the allowable
13 range under P.U.C. SUBST. R. 25.231(b)(1)(E).
14
15 Q. EARLIER YOU STATED ETI HAS EXCLUDED LEGISLATIVE
16 ADVOCACY EXPENSES INCLUDED IN EEI DUES. WHAT IS THE
17 BASIS FOR THE EEI EXCLUSION?
18 A. The Company's EEI dues have been reduced to exclude the portion of EEI
19 expenditures classified and reported as lobbying expense in accordance
20 with the expenditure categories agreed to by EEI and the National
21 Association of Regulatory Utility Commissioners, and as expanded by the
22 PUC staff in recent dockets before the Commission. The exclusion is
23 based on EEI’s 2011 estimate of such expenditures.
2011 ETI Rate Case 3-293
Entergy Texas, Inc. Page 11 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 V. COST OF SERVICE
2 A. Schedule A – Overall Cost of Service
3 Q. BRIEFLY DESCRIBE RFP SCHEDULE A.
4 A. Schedule A summarizes ETI's cost of service with adjustments to the test
5 year. Schedule A includes all of the adjustments requested by the
6 Company in Schedule A-3.
7
8 Q. ARE THE EXPENSES REFLECTED ON SCHEDULE A AND INCLUDED
9 IN THE COMPANY'S COST OF SERVICE REASONABLE AND
10 NECESSARY?
11 A. Yes. The testimony filed in this docket demonstrates that the expenses
12 included in this RFP constitute expenses for items that are reasonable and
13 necessary for the Company to provide service to the public and fulfill its
14 utility obligations.
15
16 Q. WHAT CONTROLS ARE IN PLACE TO ENSURE THAT ONLY THOSE
17 EXPENDITURES THAT ARE REASONABLE AND NECESSARY ARE
18 INCLUDED IN ETI’S COST OF SERVICE?
19 A. The Company and ESI maintain a system of internal accounting controls
20 that require review and authorization to determine the propriety of
21 expenditures. This review and authorization is performed by individuals
22 having managerial responsibility in their respective areas of expertise.
23 Responsible personnel are accountable for expenditures within their
2011 ETI Rate Case 3-294
Entergy Texas, Inc. Page 12 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 regions, divisions or departments and sufficient cross checks are in place
2 to assure that the procedures operate effectively. The system of internal
3 accounting controls is designed to provide reasonable assurance that
4 transactions are executed in accordance with management's authorization
5 and that assets are properly safeguarded and accounted for. Various
6 Company witnesses have filed testimony that reflects the necessity and
7 reasonableness of expenditures included in the cost of service.
8 Additionally, Deloitte & Touche performed the required test year review to
9 provide reasonable assurance that the Company prepared this filing in
10 compliance with the rules and procedures established by the Commission.
11
12 Q. PLEASE DESCRIBE SCHEDULE A-1.
13 A. Schedule A-1, sponsored by Company witness Heather G. LeBlanc, sets
14 forth the Company's overall cost of service.
15
16 Q. PLEASE DESCRIBE SCHEDULE A-2.
17 A. This schedule shows the detail of cost of service in the form prescribed by
18 the PUC's RFP instructions. Column (1) of Schedule A-2 provides the
19 description of amounts included in cost of service, rate base, revenue
20 information, and various ratios. Column (2) reflects the actual test year
21 activity, balance, or factor, for the particular item in Column (1). Column
22 (3) represents the adjustments to the per book amounts in Column (2).
2011 ETI Rate Case 3-295
Entergy Texas, Inc. Page 13 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Column (4) reflects the same information on an as-requested basis. This
2 schedule is sponsored by Company witness LeBlanc.
3
4 Q. PLEASE DESCRIBE SCHEDULE A-3.
5 A. Schedule A-3 provides a brief description and all necessary calculations to
6 support each adjustment appearing on Schedule A.
7
8 1. Adjustments
9 Q. PLEASE GENERALLY DESCRIBE THE ADJUSTMENTS INCLUDED IN
10 SCHEDULE A-3.
11 A. Generally, the adjustments bring expenses and revenues to a year-end
12 level or include in or exclude from cost of service expenses or revenues
13 that are not reflected in the Company's operations as of the close of the
14 test year, but which are known and measurable at the time of filing, and
15 which will occur either before or during the time that any modified rates will
16 be ordered into effect, expected to be in June 2012. The 12-month period
17 following the effective date when rates are first expected to be ordered
18 into effect is referred to as the "Rate Year." In this filing, the Rate Year is
19 June 1, 2012 through May 31, 2013. The resulting adjusted expenses and
20 revenues are those that, if used as the basis for setting rates for the
21 prospective period following the ordering of rates in effect, will give ETI a
22 reasonable opportunity to recover its reasonable and necessary expenses
2011 ETI Rate Case 3-296
Entergy Texas, Inc. Page 14 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 and earn a reasonable return on investment, as is required by PURA
2 Section 36.051.
3
4 Q. YOU STATED THAT ADJUSTMENTS WERE MADE FOR KNOWN AND
5 MEASURABLE CHANGES. ON WHAT AUTHORITY DO YOU RELY TO
6 DETERMINE WHAT IS KNOWN AND MEASURABLE?
7 A. P.U.C. SUBST. R. 25.231(a) and (b) state:
8 (a) Components of cost of service. Except as
9 provided for in subsection (c)(2) of this section,
10 relating to Invested capital; rate base, and
11 §23.23(b) [sic] of this title, (relating to Rate Design),
12 rates are to be based upon an electric utility's cost
13 of rendering service to the public during a historical
14 test year, adjusted for known and measurable
15 changes. The two components of cost of service
16 are allowable expenses and return on invested
17 capital.
18 (b) Allowable expenses. Only those expenses which
19 are reasonable and necessary to provide service to
20 the public shall be included in allowable expenses.
21 In computing an electric utility’s allowable
22 expenses, only the electric utility’s historical test
23 year expenses as adjusted for known and
24 measurable changes will be considered, except as
25 provided for in any section of these rules dealing
26 with fuel expenses.
27 The adjustments included in Schedules A-3 and B-1 meet the above
28 criteria for known and measurable changes to historical test year data.
2011 ETI Rate Case 3-297
Entergy Texas, Inc. Page 15 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. WHO IS SPONSORING THE ADJUSTMENTS INCLUDED IN
2 SCHEDULE A-3?
3 A. I will be sponsoring the adjustments discussed below, except where
4 otherwise noted.
5
6 a) Local Franchise Tax Adjustment (Adjustment 7)
7 Q. PLEASE DESCRIBE THE LOCAL FRANCHISE TAX ADJUSTMENT.
8 A. This adjustment removes the incremental local franchise tax and street
9 rental tax from taxes other than income tax expense. These taxes are
10 recovered in a separate rate rider.
11
12 b) Property Insurance Reserve (Adjustment 8)
13 Q. PLEASE EXPLAIN THE ADJUSTMENT TO THE PROPERTY
14 INSURANCE RESERVE ACCRUAL.
15 A. This adjustment reflects an annual property insurance accrual of
16 $8,760,000 as supported by the direct testimony of Company witness
17 Gregory S. Wilson. This reserve is part of the Company's self-insurance
18 plan.
2011 ETI Rate Case 3-298
Entergy Texas, Inc. Page 16 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 c) Margins Tax (Adjustment 9)
2 Q. PLEASE DESCRIBE THE STATE FRANCHISE TAX EXPENSE
3 ADJUSTMENT.
4 A. The Company increased taxes other than income tax expense to reflect
5 the margins tax calculation of state franchise taxes.
6
7 d) Income Taxes (Adjustment 10)
8 Q. PLEASE DESCRIBE THE INCOME TAX ADJUSTMENT.
9 A. The income tax adjustment removes prior year amounts from the test
10 year, adjusts some items to the correct test year levels, and eliminates
11 adjustments to taxable income and deferred income taxes for items which
12 are normalized in other adjustments. The current and deferred income tax
13 effects of net operating losses are also eliminated along with the deferred
14 income taxes related to the Statement of Financial Accounting Standards
15 (“SFAS”) No. 109, Accounting for Income Taxes.
16 Q. WHY ARE PRIOR YEAR AMOUNTS RECORDED IN THE TEST YEAR?
17 A. The tax return for 2009 was not completed and filed until September 2010.
18 Differences between amounts recorded on the books for current and
19 deferred income taxes and the amounts ultimately used in the filed tax
20 return were recorded on the books in the month of November 2010. Since
21 these amounts do not relate to the expenses incurred during the test year,
22 they must be eliminated from the test year.
2011 ETI Rate Case 3-299
Entergy Texas, Inc. Page 17 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. WHY DID YOU MAKE THE ADJUSTMENTS TO THE TEST YEAR
2 LEVELS OF CURRENT AND DEFERRED INCOME TAXES?
3 A. Corrections were recorded during the test year to current and deferred
4 income tax amounts that were originally recorded in periods prior to the
5 test year. These adjustments were either eliminated or the test year
6 amount was adjusted to an amount consistent with test year operating
7 expenses.
8
9 Q. PLEASE EXPLAIN THE ADJUSTMENT TO TAXABLE INCOME AND
10 DEFERRED INCOME TAXES FOR ITEMS THAT ARE NORMALIZED IN
11 OTHER ADJUSTMENTS.
12 A. Current and deferred income taxes related to items that are eliminated in
13 their entirety, or where the test year amount is substantially changed in
14 other adjustments, are eliminated or adjusted in the income tax
15 adjustment. This is to insure that the correct ending current and deferred
16 income tax effects match and correspond to the items of revenue and
17 expense in the cost of service.
18
19 Q. WHY HAVE YOU ELIMINATED DEFERRED INCOME TAXES RELATED
20 TO SFAS NO. 109?
21 A. The regulated effect of SFAS No. 109 results in recording accumulated
22 deferred income taxes that subsequently will be collected from or paid to
23 customers and are offset by corresponding regulatory assets and
2011 ETI Rate Case 3-300
Entergy Texas, Inc. Page 18 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 liabilities. SFAS No. 109 should have no effect on net operating income or
2 rate base from a regulatory standpoint and this adjustment accomplishes
3 the required net operating income neutral effect.
4
5 e) Rate Case Expense (Adjustment 11)
6 Q PLEASE DESCRIBE THE ADJUSTMENT FOR RATE CASE EXPENSES.
7 A. Based on the rate case expense estimate from ETI’s last base rate case
8 (Docket No. 37744) and adjusted for known changes to legal and
9 consulting expenses expected to be incurred during the current
10 proceeding, the Company has estimated the rate case expenses related
11 to this filing to be $12,350,000. The estimated rate case expenses will be
12 replaced by actual costs incurred as the proceeding progresses. The
13 Company requests that these amounts be recovered over three years.
14 The Company is also requesting that the average balance of rate case
15 expense be included in rate base.
16
17 f) Trade Association Dues/Legislative Advocacy (Adjustment 12)
18 Q. PLEASE EXPLAIN THIS ADJUSTMENT.
19 A. Earlier, I stated that I removed the Company’s EEI dues related to
20 lobbying from cost of service. This adjustment presents that disallowance.
21 Specifically, I eliminated 21.28% of the Company's EEI dues from the cost
22 of service. This percentage of EEI dues related to lobbying is calculated
2011 ETI Rate Case 3-301
Entergy Texas, Inc. Page 19 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 based on EEI’s 2011 estimate of such expenditures. The amount of EEI
2 dues requested is $162,916.
3
4 g) Depreciation Expense (Adjustment 13)
5 Q. PLEASE DESCRIBE THE DEPRECIATION EXPENSE ADJUSTMENT.
6 A. This adjustment shows the increase in depreciation expense resulting
7 from the application of depreciation rates approved in Docket No. 16705
8 and Docket No. 34800 to the test year end depreciable plant in service
9 balances. Test year actual depreciation expense is subtracted from this
10 pro forma amount to arrive at the adjustment of $2,459,367. Deferred
11 income taxes are also adjusted to reflect the impact of the approved
12 depreciation rates. Adjustments to affiliate depreciation expense are
13 included in Schedule G-6.2 and Adjustment 21.
14
15 h) Depreciation Study Adjustment (Adjustment 14)
16 Q. HAS THE COMPANY SUBMITTED A NEW DEPRECIATION STUDY AS
17 PART OF THIS CASE?
18 A. Yes. A depreciation study was prepared by Company witness Dane
19 Watson and the results of that study are described in Mr. Watson’s
20 testimony. Mr. Watson co-sponsors this adjustment which applies the
21 depreciation study rates to test year end plant balances. The result of this
22 adjustment is an increase in depreciation expense of $19,970,000.
2011 ETI Rate Case 3-302
Entergy Texas, Inc. Page 20 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Deferred income tax expense is also adjusted for the effect of the
2 proposed depreciation rate as are Service Schedule MSS-4 revenues.
3
4 Q. WHY ARE MSS-4 REVENUES ADJUSTED?
5 A. The new depreciation rates for production plants will be reflected in the
6 Service Schedule MSS-4 billings, resulting in decreased Service Schedule
7 MSS-4 revenues.
8
9 i) Hurricane Securitization (Adjustment 15)
10 Q. PLEASE DESCRIBE THIS ADJUSTMENT FOR HURRICANE COST.
11 A. All Hurricane Ike and Gustav costs that have been securitized are
12 removed from rate base as a result of including the contra-plant accounts
13 related to those storms. In addition, the net amount of unrecovered
14 Hurricane Rita insurance proceeds, the Hurricane Ike and Gustav
15 insurance proceeds in excess of insurance proceeds included in the
16 securitization, the carrying costs associated with Entergy Gulf States
17 Louisiana’s share of hurricane production costs (mainly associated with
18 ETI’s Sabine generating plant), the non-capital costs and the carrying
19 costs associated with ETI’s share of EGSL’s hurricane production nuclear
20 costs are included in rate base and amortized over five years in this
21 adjustment.
2011 ETI Rate Case 3-303
Entergy Texas, Inc. Page 21 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 j) Miscellaneous Adjustments (Adjustment 16)
2 Q. PLEASE DESCRIBE THE MISCELLANEOUS ADJUSTMENTS.
3 A. This pro forma includes the following adjustments:
4 1) An adjustment was made to both expense and rate base to remove
5 the impact in the cost of service of the asset retirement obligation
6 and related accretion expense recorded as result of implementing
7 SFAS No. 143. SFAS No. 143 should have no effect on net
8 operating income or rate base from a regulatory standpoint.
9 2) This adjustment eliminates from plant a reclassification recorded on
10 the Company’s books for cash flow statement purposes. This
11 adjustment has no impact on net plant.
12 3) Regulatory debits and credits that are not properly included in the
13 cost of service are eliminated in this adjustment.
14 4) Provisions for rate refunds are eliminated in this adjustment. These
15 amounts should have no impact on this case.
16 5) This adjustment removes certain expenses from the cost of service
17 that are not allowed under P.U.C. SUBST. R. 25.231(b)(2).
18 6) An adjustment was made to eliminate the SFAS No. 158 regulatory
19 asset offset to the unfunded pension liability balance.
20 7) An adjustment was made to separate facilities revenue by function.
21 8) This adjustment eliminates the test year direct costs for the 2009
22 (Docket No. 37744) rate case.
23 9) This adjustment eliminates energy efficiency costs which are
24 recovered in a rider.
25 10) This adjustment adds to rate base plant held for future use that is in
26 service or expected to be in service in the next ten years.
27 11) This adjustment eliminates prepaid balances which are not
28 recoverable in base rates.
29 12) This adjustment removes $652,627 of MISO transition expenses,
30 incurred since January 1, 2011, being considered in Docket No.
31 39741. This adjustment also includes a five year amortization of
32 $263,908 for the MISO transition expenses incurred during the test
2011 ETI Rate Case 3-304
Entergy Texas, Inc. Page 22 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 year for the time period of July 2010 through December 2010 for
2 which the Company is not seeking a deferral. This adjustment also
3 includes a three year amortization of expected MISO transition
4 costs. If the Company’s proposed accounting order for MISO
5 transition costs is approved in Docket No. 39741 prior to the
6 effective date of new rates from the instant proceeding, this
7 adjustment will not be necessary.
8 13) This adjustment eliminates expenses that were not incurred during
9 the test year.
10
11 k) Interest Synchronization (Adjustment 17)
12 Q. PLEASE DESCRIBE THE INTEREST SYNCHRONIZATION
13 ADJUSTMENT.
14 A. Per book interest expense in the tax calculation is replaced with the
15 interest expense calculated by multiplying the weighted cost of debt in the
16 requested cost of capital by adjusted rate base.
17
18 l) Customer Deposits and ESI Interest Expense (Adjustment 18)
19 Q. PLEASE DESCRIBE THE ADJUSTMENT FOR INTEREST ON
20 CUSTOMER DEPOSITS.
21 A. This adjustment is made to increase test year cost of service to reflect an
22 annualized amount for interest on active customer deposits. This
23 adjustment is made using a rate of 0.19%, the rate currently in effect
24 under the P.U.C. SUBST. R. 25.24(g). This rate was applied to the amount
25 of active customer deposits at the end of the test year. The total amount
26 of deposits is reflected as a reduction from rate base as required by
2011 ETI Rate Case 3-305
Entergy Texas, Inc. Page 23 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 P.U.C. SUBST. R. 25.231(c)(2)(C)(v). The amount of customers’ deposits
2 is $36,307,938, which results in interest expense of $68,985.
3
4 Q. DESCRIBE THE ADJUSTMENT FOR ESI AND EOI INTEREST.
5 A. The adjustment reclassifies ESI interest expense recorded below the line
6 in the test year to Account 923. The Company is not requesting a return
7 on assets owned by ESI, but is requesting recovery of actual interest costs
8 paid to ESI.
9
10 m) SFAS 106 (Adjustment 19)
11 Q. PLEASE DESCRIBE THE SFAS 106 ADJUSTMENT.
12 A. In December 1990, the Financial Accounting Standards Board (“FASB”)
13 issued SFAS 106, which was effective for fiscal years beginning after
14 December 15, 1992. Under SFAS 106, a business must account for
15 benefits other than pensions to be provided to retirees during retirement
16 on an accrual basis during the periods that the employees render service.
17 The Commission approved recovery of these costs by ETI on an
18 accrual basis in Docket No. 16705. Adjustment 19 reflects the estimated
19 2012 SFAS 106 accrual in the cost of service.
2011 ETI Rate Case 3-306
Entergy Texas, Inc. Page 24 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 n) Pension Expense (Adjustment 20)
2 Q. PLEASE EXPLAIN THE PENSION EXPENSE ADJUSTMENT.
3 A. The estimated amount of pension expense for 2012 is included in the cost
4 of service. This amount on an electric operation and maintenance
5 (“O&M”) expense was $3,871,000 compared to the per books amount of
6 $2,035,000.) The adjustment is an increase of $1,836,000 to the overall
7 pension expense included in cost of service.
8
9 o) Payroll Expense (Adjustment 22)
10 Q. PLEASE EXPLAIN THE PAYROLL EXPENSE ADJUSTMENT.
11 A. Payroll expense has been adjusted to reflect the decrease in the number
12 of ETI employees during the test year. The effective number of
13 employees who left during the test year is calculated and an average
14 salary for employees who left the Company during the test year is used to
15 calculate a total Company adjustment to decrease payroll expense. This
16 has the effect of annualizing the payroll impact of the employees who left
17 during the test year. This amount is then factored down to an electric
18 O&M amount, to which payroll taxes and benefits are added, resulting in a
19 total expense reduction of $957,695. This reduction is offset by payroll
20 increases for non-bargaining employees, effective April 1, 2011 and April
21 1, 2012, and increases for bargaining employees, which were effective
22 March 20, 2011 and August 6, 2011. The increase in expense (including
2011 ETI Rate Case 3-307
Entergy Texas, Inc. Page 25 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 benefits and payroll taxes) is $1,105,871 for a net increase to expense of
2 $148,176.
3
4 Q. WAS A SIMILAR ADJUSTMENT MADE FOR ESI EMPLOYEES?
5 A. Yes. The number of employees and wage increases were considered in a
6 similar fashion for ESI employees. The net ESI adjustment was an
7 increase in payroll expense of $852,493.
8
9 p) Service Schedule MSS-2 Adjustment (Adjustment 23)
10 Q. PLEASE DESCRIBE THE SERVICE SCHEDULE MSS-2 ADJUSTMENT.
11 A. This adjustment adjusts the Service Schedule MSS-2 test year level of
12 revenue and expense to the estimated rate year level of Service Schedule
13 MSS-2 expense.
14
15 q) Capacity Adjustment (Adjustment 24)
16 Q. PLEASE DESCRIBE ADJUSTMENT 24.
17 A. This adjustment removes purchase power capacity expenses that the
18 Company proposes to be recovered via the purchase power rider on a
19 prospective basis. The amounts removed include third-party capacity
20 purchases, Service Schedule MSS-4 purchases and Service Schedule
21 MSS-1 reserve equalization expenses. If the Commission decides these
22 capacity costs should remain in base rates, then these expenses would
2011 ETI Rate Case 3-308
Entergy Texas, Inc. Page 26 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 have to be added to the cost of service. Company witness Phillip R. May
2 discusses this in his direct testimony.
3
4 r) Property Tax (Adjustment 25)
5 Q. PLEASE DESCRIBE ADJUSTMENT 25.
6 A. This adjustment reflects property tax expenses at the level of expense that
7 will be incurred during the rate year. This adjustment is further described
8 in the direct testimony of Company witness Patricia A. Galbraith.
9
10 2. Trial Balances, Schedule A-4
11 Q. PLEASE DESCRIBE SCHEDULE A-4.
12 A. Schedule A-4 provides a detailed test year-end trial balance by major
13 FERC account. The amounts shown on this trial balance are referenced
14 to, or reconciled with, test year-end numbers appearing on Schedule A-2.
15 Column (1) lists the FERC Account Number for all amounts included on
16 Schedule A-2. Column (2) describes the account. Column (3) presents
17 the amount shown for each account in the detailed trial balance. Column
18 (4) presents the Schedule A-2 line number reference. Column (5) shows
19 the reconciliation reference.
2011 ETI Rate Case 3-309
Entergy Texas, Inc. Page 27 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 B. Schedule B - Rate Base and Return
2 Q. PLEASE DESCRIBE SCHEDULE B-1.
3 A. Schedule B-1 summarizes ETI's total Company net original cost rate base,
4 the requested adjustments to rate base, and the requested rate of return.
5 Column (1) of Schedule B-1 describes the components of rate base.
6 Column (2) reflects the total Company per book amounts for each
7 component of rate base. Column (3) shows the adjustments to total
8 Company amounts necessary to develop the per book total electric
9 amounts in column (4). Column (5) shows the necessary adjustments to
10 total electric per book amounts for each component of rate base. Column
11 (6) is the total requested rate base by component and the requested rate
12 of return. Schedule B-1 is co-sponsored by Company witness LeBlanc.
13
14 1. Rate Base Adjustments
15 a) Cash Working Capital (Adjustment 6)
16 Q. PLEASE DESCRIBE HOW THE CASH WORKING CAPITAL
17 ALLOWANCE IS CALCULATED.
18 A. Schedule E-4 contains the calculation of the cash working capital
19 allowance for operating and maintenance expenses obtained from the
20 lead-lag study. P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV) and (V) require
21 that a lead-lag study be performed to determine the reasonableness of a
22 cash working capital allowance. A lead-lag study is a detailed analysis of
23 the Company's normal day-to-day business activities performed to assist
2011 ETI Rate Case 3-310
Entergy Texas, Inc. Page 28 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 in determining the amount of investment that is necessary to fund these
2 activities before the Company is reimbursed by its customers. Company
3 witness Jay Joyce discusses the lead-lag study in his direct testimony.
4
5 b) Income Tax (Adjustment 10)
6 Q. PLEASE DESCRIBE THE RATE BASE EFFECTS OF THE INCOME TAX
7 ADJUSTMENT.
8 A. As described earlier in my testimony, all ADIT effects of SFAS 109 are
9 eliminated from the test year. ADIT associated with items removed from
10 the case are eliminated in the adjustment.
11
12 2. Schedules B-1.1 through B-2.1
13 Q. PLEASE DESCRIBE SCHEDULE B-1.1.
14 A. Schedule B-1.1 reflects the Company’s allocation of rate base to the
15 Texas Retail jurisdiction, which is presented in the same format as
16 Schedule B-1. Company witness LeBlanc sponsors this schedule.
17
18 Q. PLEASE DESCRIBE SCHEDULE B-1.2.
19 A. This schedule is not applicable to the Company because the Company's
20 requested plant in service is not less than 100% of original prudent cost.
21 Q. PLEASE DESCRIBE SCHEDULE B-1.3.
22 A. Schedule B-1.3 reports that there are no penalties or fines included in the
23 Company's requested plant in service on Schedule B-1.
2011 ETI Rate Case 3-311
Entergy Texas, Inc. Page 29 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. PLEASE EXPLAIN SCHEDULE B-1.4.
2 A. There were no post test year adjustments to rate base.
3
4 Q. PLEASE DESCRIBE SCHEDULE B-2.
5 A. Schedule B-2 reports the monthly balance of each accumulated provision
6 account, the amount accrued each month, and the amount charged off
7 each month during the test year. The same information is provided in total
8 for each of the calendar years 2007 through 2010.
9
10 Q. PLEASE DESCRIBE SCHEDULE B-2.1.
11 A. Schedule B-2.1 provides an explanation of the Company's policy
12 regarding accumulated provision accounts and the benefits these
13 accounts provide to customers.
14
15 C. Schedule C – Original Cost of Plant
16 Q. PLEASE DESCRIBE SCHEDULE C-1.
17 A. This schedule summarizes the original cost of utility plant as of the
18 beginning of the test year, shows additions, retirements and transfers, and
19 the balances at the end of the test year. Adjustments made to the book
20 balances for requested plant amounts are also included in this schedule.
2011 ETI Rate Case 3-312
Entergy Texas, Inc. Page 30 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. PLEASE DESCRIBE SCHEDULE C-2.
2 A. This schedule presents the data shown in Schedule C-1, detailed by each
3 of the major plant accounts.
4
5 Q. PLEASE DESCRIBE SCHEDULE C-3.
6 A. Schedule C-3 is a monthly presentation of plant balances by primary or
7 functional classification by primary plant account as well as any requested
8 adjustments to the balances.
9
10 Q. PLEASE DESCRIBE SCHEDULE C-4.1.
11 A. This schedule lists items of $100,000 or more by functional group included
12 in Construction Work in Progress (“CWIP”) with details concerning the
13 items.
14
15 Q. PLEASE DESCRIBE SCHEDULE C-4.2, CWIP ALLOWED IN RATE
16 BASE.
17 A. The schedule shows that no CWIP was requested in rate base in Docket
18 Nos. 34800 or 37744, the Company's two most recent base rate
19 proceedings. In this filing, the Company is not requesting CWIP in rate
20 base.
2011 ETI Rate Case 3-313
Entergy Texas, Inc. Page 31 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. PLEASE DESCRIBE SCHEDULE C-5, ALLOWANCE FOR FUNDS USED
2 DURING CONSTRUCTION (“AFUDC”) AND CONSTRUCTION
3 OVERHEADS.
4 A. This schedule details the methods, procedures, and calculations in
5 capitalizing AFUDC. Also shown are the capitalization rates for each of
6 the five years ended December 31, 2006 through 2010 along with the test
7 year, and the amounts of AFUDC generated and transferred to plant in
8 service.
9
10 Q. PLEASE DISCUSS SCHEDULES C-6 THROUGH C-10.
11 A. Theses schedules are not applicable to ETI, which has no nuclear fuel.
12
13 D. Schedule D – Accumulated Depreciation
14 Q. PLEASE DESCRIBE SCHEDULE D.
15 A. Schedule D is a narrative description of computer programs, diskettes,
16 schedules, and file names associated with Schedules D-1, D-3, D-4, D-6,
17 D-7, and D-8.
18
19 Q. PLEASE DESCRIBE SCHEDULE D-1.
20 A. Schedule D-1 shows the reserve for depreciation and amortization at the
21 beginning of the test year, provisions, salvage, cost of properties retired,
22 cost of removal, other additions and/or reductions, and the reserve for
2011 ETI Rate Case 3-314
Entergy Texas, Inc. Page 32 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 depreciation and amortization at the end of the test year. Adjustments
2 and the as-adjusted amounts are also shown.
3
4 Q. PLEASE DESCRIBE SCHEDULE D-2.
5 A. Schedule D-2 is a narrative description of the methods and procedures
6 followed in booking depreciation and plant retirements and abandonments.
7
8 Q. PLEASE DESCRIBE SCHEDULE D-3.
9 A. Schedule D-3 details plant held for future use (“PHFU”).
10
11 Q. PLEASE DESCRIBE SCHEDULE D-4.
12 A. This schedule shows depreciable plant, the depreciation rate for the test
13 year, and test year depreciation. The requested depreciable plant and
14 existing depreciation rates are shown, requested depreciation expense is
15 computed, and the adjustment to depreciation expense requested is
16 presented in the last column.
17
18 Q. PLEASE DESCRIBE SCHEDULE D-5.
19 A. The depreciation study prepared by Company witness Watson is
20 referenced in Schedule D-5.
2011 ETI Rate Case 3-315
Entergy Texas, Inc. Page 33 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. PLEASE DESCRIBE SCHEDULE D-6.
2 A. This schedule provides projected retirement dates for the Company’s
3 generating units. Company witness Robert R. Cooper co-sponsors this
4 schedule with me.
5
6 Q. PLEASE DESCRIBE SCHEDULE D-7.
7 A. This schedule provides summary data for cost of removal, salvage, and
8 net salvage, and is provided by functional classification.
9
10 Q. PLEASE DESCRIBE SCHEDULE D-8.
11 A. This schedule provides the average service life of each group of assets
12 and the Iowa Curves used to determine the lives.
13
14 E. Schedule E – Short-Term Assets and Inventories
15 Q. PLEASE DESCRIBE SCHEDULE E-1.
16 A. Schedule E-1 lists each short-term asset requested in rate base (e.g.,
17 materials and supplies, prepayments, and fuel inventory). The schedule
18 includes book balances for the month end before the test year begins and
19 each of the twelve months of the test year in order to arrive at a 13 month
20 average.
2011 ETI Rate Case 3-316
Entergy Texas, Inc. Page 34 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. PLEASE DESCRIBE SCHEDULE E-1.1.
2 A. Schedule E-1.1 details the monthly per book balances by category
3 included in Schedule E-1.
4
5 Q. PLEASE DESCRIBE SCHEDULE E-1.2.
6 A. Schedule E-1.2 explains the Company’s policies related to obsolete,
7 damaged, or no-longer-used inventory.
8
9 Q. PLEASE DESCRIBE SCHEDULE E-1.3.
10 A. Schedule E-1.3 indicates there have been no changes in accounting policy
11 for the book balances (started capitalizing, quit keeping item on hand,
12 change in write-off procedures, etc.) for items included in Schedule E-1.
13
14 Q. PLEASE DESCRIBE SCHEDULE E-2.2
15 A. Schedule E-2.2 details the optimal coal inventory level for the Company.
16
17 Q. PLEASE DESCRIBE SCHEDULE E-2.3.
18 A. Schedule E-2.3 presents a detailed analysis of fossil fuel inventories on
19 hand at the end of the test year.
2011 ETI Rate Case 3-317
Entergy Texas, Inc. Page 35 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. PLEASE DESCRIBE SCHEDULE E-2.4.
2 A. Schedule E-2.4 presents ETI's monthly fossil fuel inventory levels for the
3 test year ended June 30, 2011.
4
5 Q. PLEASE DESCRIBE SCHEDULE E-4.
6 A. Schedule E-4 details the application of the lead-lag study to calculate the
7 rate base effect of the lead lag study. This schedule is co-sponsored by
8 Company witness Joyce.
9
10 Q. PLEASE DESCRIBE SCHEDULES E-5 AND E-6.
11 A. Schedule E-5 presents the amount of prepayment and materials and
12 supplies charged to O&M expense by month during the test year.
13 Schedule E-6 contains information about customer deposits at the end of
14 the test year.
15
16 F. Schedule G – Accounting Information
17 1. Payroll Schedules
18 Q. PLEASE DESCRIBE SCHEDULE G-1.
19 A. Schedule G-1 provides a narrative of the payroll practices of the
20 Company. Schedules G-1.6 and G-2.1 described below are co-sponsored
21 by Company witness Kevin G. Gardner.
2011 ETI Rate Case 3-318
Entergy Texas, Inc. Page 36 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. PLEASE DESCRIBE SCHEDULE G-1.1.
2 A. Schedule G-1.1 provides annual gross payroll information for each year of
3 the three-year period ending December 31, 2010, as well as for each
4 month of the test year. The information is categorized by regular payroll,
5 overtime payroll, other, and total payroll.
6
7 Q. PLEASE DESCRIBE SCHEDULE G-1.2.
8 A. Schedule G-1.2 provides annual gross regular payroll information for each
9 year of the three-year period ending December 31, 2010, as well as for
10 each month of the test year. The information is categorized by union
11 payroll, non-union payroll, and total payroll.
12
13 Q. PLEASE DESCRIBE SCHEDULE G-1.3.
14 A. Schedule G-1.3 provides annual gross payroll information for each year of
15 the three-year period ending December 31, 2010, as well as for each
16 month of the test year. The information is categorized by payroll
17 expensed, payroll capitalized, other payroll, and total payroll.
18
19 Q. PLEASE DESCRIBE SCHEDULE G-1.4.
20 A. Schedule G-1.4 provides the amount of payroll charged to joint owners of
21 certain power plants operated by ETI for each year of the three-year
22 period ending December 31, 2010, as well as for each month of the test
23 year. This schedule presents information for units in which there are joint
2011 ETI Rate Case 3-319
Entergy Texas, Inc. Page 37 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 owners, ETI is the operator, and the joint owner reimburses ETI for the
2 payroll as part of the billing for O&M costs.
3
4 Q. PLEASE DESCRIBE SCHEDULE G-1.6.
5 A. Schedule G-1.6 reports all payments other than standard pay or overtime
6 pay made to ETI employees for each year of the three-year period ended
7 December 31, 2010, as well as for each month of the test year.
8
9 2. Pensions and Benefits Schedules
10 Q. PLEASE DESCRIBE SCHEDULE G-2.1.
11 A. A summary of ETI's pension fund activity is included in Schedule G-2.1.
12 The schedule includes pension expense pursuant to SFAS No. 87, actual
13 pension payments to the fund, actuarial minimums and actuarial
14 maximum, along with supporting documentation.
15
16 Q. PLEASE DESCRIBE SCHEDULE G-2.2.
17 A. Schedule G-2.2 provides details concerning SFAS 106 expense incurred
18 during the test year and as requested in cost of service.
2011 ETI Rate Case 3-320
Entergy Texas, Inc. Page 38 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 3. Bad Debt Expense Schedule
2 Q. PLEASE DESCRIBE SCHEDULE G-3.
3 A. Schedule G-3 contains information concerning bad debt expense including
4 the methodology of calculating monthly expense and the amount of write-
5 offs.
6
7 4. Advertising, Contributions, and Dues Schedules
8 Q. PLEASE DESCRIBE SCHEDULE G-4.
9 A. This schedule presents a summary of advertising, contributions, and
10 donations, and organization memberships and dues expenses subject to
11 the 0.3% of revenue limitation. The schedule includes the FERC account
12 charged, category, schedule number that details the expense, and test
13 year expense.
14
15 Q. PLEASE DESCRIBE SCHEDULES G-4.1 THROUGH G-4.1c.
16 A. Schedule G-4.1 provides a summary of advertising expense categorized
17 by: FERC account, category schedule number, and test year amount.
18 Schedules G-4.1a through G-4.1c provide a summary of expense for
19 informational/instructional advertising, promoting and retaining usage, and
20 general advertising expense, respectively.
21
22 Q. PLEASE DESCRIBE SCHEDULE G-4.1d.
23 A. Schedule G-4.1d requires detail about advertising costs capitalized.
2011 ETI Rate Case 3-321
Entergy Texas, Inc. Page 39 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. PLEASE DESCRIBE SCHEDULES G-4.2 THROUGH G-4.2c.
2 A. Schedule G-4.2 provides a summary of contribution and donation
3 expenses in the following categories: educational; community service; and
4 economic development. The schedule includes the FERC account
5 charged, the description of the contribution, the schedule number that
6 details the expense, and the test year amount. Schedules G-4.2a through
7 G-4.2c detail educational, community service, and economic development
8 contribution and donations expense, respectively.
9
10 Q. PLEASE DESCRIBE SCHEDULES G-4.3 THROUGH G-4.3e.
11 A. Schedule G-4.3 provides a summary of membership dues or support
12 expenses categorized by: industry organizations; business/economic
13 organizations; professional organizations; social/recreational/religious
14 organizations; and political organizations. The schedule includes the
15 FERC account charged, the category, the schedule number that details
16 the expense, and the test year amount. Also included are certain amounts
17 that ETI has excluded from its requested cost of service. Schedules G-
18 4.3a through G-4.3e provide: a summary of electric industry organization
19 dues; business and economic dues; professional dues; social,
20 recreational, fraternal or religious expenses; and political organization
21 expenses, respectively.
2011 ETI Rate Case 3-322
Entergy Texas, Inc. Page 40 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 5. Exclusions from Test Period Schedules
2 Q. PLEASE DESCRIBE SCHEDULES G-5 THROUGH G-5.1b.
3 A. Schedule G-5 presents a summary of all test year expenditures in the
4 categories of: legislative advocacy expenses; penalties and fines; other
5 exclusions; social/recreational/religious; and political. The schedule
6 includes a description of the expenditure, the schedule number that details
7 the expenditure, and the test year amount. Schedules G-5.1 through G-
8 5.1b summarize legislative advocacy expense, payments made to
9 individuals registered to lobby on behalf of the utility during the test year,
10 and payments made to individuals or firms who monitored legislation for
11 the utility during the test year, respectively. The Company is not
12 requesting lobbying expenses in the cost of service in accordance with
13 PURA § 36.062.
14
15 Q. PLEASE DESCRIBE SCHEDULE G-5.2.
16 A. Schedule G-5.2 requires a summary of all penalties and fines included in
17 the test year expense. ETI is not, however, requesting recovery of any
18 fines or penalties in its cost of service.
19
20 Q. PLEASE DESCRIBE SCHEDULE G-5.3.
21 A. Schedule G-5.3 presents a summary of all test year expenditures referred
22 to in P.U.C. SUBST. R. 25.231(b)(2), but not shown in Schedules G-4.3d,
23 G-4.3e, G-5.1, and G-5.2.
2011 ETI Rate Case 3-323
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Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. PLEASE DESCRIBE SCHEDULE G-5.4.
2 A. Schedule G-5.4 requires amounts which were excluded from cost of
3 service by the PUC in the Company's most recent rate case not resolved
4 by settlement, if any, in the last five years. The only rate cases applicable
5 to ETI or its predecessor EGSI resolved in the past five years were the
6 base rate case filed in Docket No. 34800 in September 2007 and Docket
7 No. 37744 in December 2009, which were resolved by settlement. This
8 schedule, therefore, does not apply to this case.
9
10 Q. PLEASE DESCRIBE SCHEDULE G-5.5.
11 A. Schedule G-5.5 requests payments made during the test year and
12 included in cost of service for activities or services similar to those
13 excluded from either of the two most recent rate cases not resolved by
14 settlement. The two most recent bundled rate cases applicable to ETI or
15 its predecessor EGSI were resolved by settlement filed in Docket No(s).
16 37744 and 34800. EGSI did file an unbundled rate case in Docket No.
17 22356 in 2000, but that proceeding did not result in a final order. This
18 schedule, therefore, does not apply to this case.
19
20 6. Income Tax Schedules
21 Q. PLEASE DESCRIBE SCHEDULE G-7.1.
22 A. Schedule G-7.1 is the reconciliation of book net income to taxable net
23 income for the test year and for the most recently filed tax return. The
2011 ETI Rate Case 3-324
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Direct Testimony of Michael P. Considine
2011 Rate Case
1 workpapers for Schedule G-7.1 contain explanations of all items in the
2 reconciliation along with an explanation of items that appeared in the tax
3 return that have not been considered in the test year calculation. This
4 schedule is co-sponsored by Company witness Rory L. Roberts.
5
6 Q. ARE YOU FILING SCHEDULE G-7.2, PLANT ADJUSTMENTS?
7 A. Yes. This schedule is not applicable to ETI in this rate case because ETI
8 has not purchased or constructed any new generating unit since the
9 Company’s last rate case.
10
11 Q. PLEASE EXPLAIN SCHEDULE G-7.4, ACCUMULATED DEFERRED
12 FEDERAL INCOME TAXES (“ADFIT”).
13 A. This schedule shows the balance sheet amount of ADFIT for the twelve
14 months of the test year, as well as requested adjustments to the balances.
15 The deferrals are segregated by specific items giving rise to the deferral.
16 This schedule also shows the additional deferred taxes that were recorded
17 as a result of adopting SFAS 109. SFAS 109 has no effect on rate base
18 compared to the prior standard for accounting for income taxes,
19 Accounting Principles Board No. 11. As stated earlier in my testimony,
20 recording income taxes in accordance with SFAS 109 is revenue neutral.
21 Schedules G-7.4 through G-7.4d are co-sponsored by Company witness
22 Roberts.
2011 ETI Rate Case 3-325
Entergy Texas, Inc. Page 43 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. PLEASE DESCRIBE SCHEDULE G-7.4b, ADJUSTMENTS TO ADFIT.
2 A. Adjustments to balance sheet amounts are detailed on this schedule. The
3 reasons for these adjustments are shown and supporting calculations are
4 included. A description of the adjustments is provided in the discussion of
5 the income tax pro forma (Adjustment 10).
6
7 Q. WHAT IS THE PROPER RATE TREATMENT FOR THE DEFERRED
8 TAXES SHOWN ON SCHEDULE G-7.4, ADFIT?
9 A. The total deferred taxes from Schedule G-7.4 are an adjustment to rate
10 base on Schedule B-1. The pre-1971 ITC shown on Schedule G-7.5e is
11 also an adjustment to rate base on Schedule B-1.
12
13 Q. WHY IS THE PRE-1971 ITC A DEDUCTION TO RATE BASE WHILE
14 THE POST-1970 ITC IS NOT DEDUCTED FROM RATE BASE?
15 A. Use of the pre-1971 ITC for rate purposes was not restricted by the Tax
16 Code. An election was made by the Company to not reduce rate base by
17 the Post-1970 ITC, but to instead amortize these credits to cost of service
18 no more rapidly than ratably. This treatment is in accordance with Section
19 46(f)(2) of the Tax Code.
2011 ETI Rate Case 3-326
Entergy Texas, Inc. Page 44 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. PLEASE DESCRIBE SCHEDULE G-7.4c, ADFIT AND ITC - PLANT
2 ADJUSTMENTS AND ALLOCATIONS.
3 A. This schedule seeks information on the balance sheet ADFIT and ITC for
4 additions to new generating plant-in-service since the Company's last filing
5 and any plant adjustments to the test year end. There have been no new
6 generating units added to rate base since the Company's last filing or
7 plant adjustments to the test year end.
8
9 Q. PLEASE DESCRIBE SCHEDULE G-7.4d, ADFIT - RATE CASE
10 EXPENSES.
11 A. This schedule is inapplicable to ETI for this rate case. The Company does
12 not have any accumulated deferred federal income tax (ADFIT) related to
13 Texas Retail rate case expenses.
14
15 Q. PLEASE DESCRIBE SCHEDULE G-7.5c, ITC UTILIZED - STAND-
16 ALONE BASIS.
17 A. This schedule shows ITC utilized as if the Company had filed on a stand-
18 alone basis consistent with the limitations included in the Tax Code based
19 on the stand-alone methodology.
2011 ETI Rate Case 3-327
Entergy Texas, Inc. Page 45 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. PLEASE DESCRIBE SCHEDULE G-7.5e, FERC ACCOUNT 255
2 BALANCE.
3 A. This schedule shows the FERC account balance for Account 255,
4 Accumulated Deferred ITC, allocated between nuclear production plant
5 and other plant.
6
7 Q. PLEASE DESCRIBE SCHEDULE G-7.6, ANALYSIS OF TEST YEAR FIT
8 AND REQUESTED FIT - TAX METHOD 2.
9 A. Schedule G-7.6 calculates FIT for the test year and requested FIT using
10 Tax Method 2. Included with this schedule are supporting explanations
11 and calculations. This method of calculating FIT expense determines the
12 components of FIT separately. These components include the taxes
13 payable currently, the deferred taxes, and the amortization of ITC.
14 Company witness Roberts and LeBlanc co-sponsor Schedules G-7.6 and
15 G-7.6a.
16
17 Q. PLEASE DESCRIBE SCHEDULE G-7.6a, ANALYSIS OF DEFERRED
18 FIT.
19 A. This schedule is an analysis of the deferred FIT expense as shown on
20 Schedule G-7.6. Workpapers supporting the calculation(s) are included in
21 WP/G-7.6.
2011 ETI Rate Case 3-328
Entergy Texas, Inc. Page 46 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. PLEASE DESCRIBE SCHEDULE G-7.7, ANALYSIS OF ADDITIONAL
2 DEPRECIATION REQUESTED.
3 A. This schedule requests support for any requested adjustment to return for
4 additional depreciation. ETI is not requesting an adjustment to return for
5 additional depreciation expense.
6
7 Q. PLEASE DESCRIBE SCHEDULE G-7.8, ANALYSIS OF TEST YEAR FIT
8 AND REQUESTED FIT - TAX METHOD 1.
9 A. This schedule represents what is known as the Method 1 calculation of
10 test year and requested FIT. This is sometimes described as the "return
11 method" for computing FIT. Company witness Roberts and LeBlanc co-
12 sponsor Schedule G-7.8.
13 Return is the total amount shown on Schedule B-1, line 25.
14 Regulated interest expense is defined as the weighted cost of debt
15 (Schedule K-1, Line 3, column 6) multiplied by the requested rate base
16 (Schedule B-1, line 24). Interest expense is subtracted from return to
17 arrive at the taxable amount of return before adjustments.
18 Also subtracted is the amortization of taxes in excess of the
19 statutory 35% rate and other items that, before adoption of SFAS 109,
20 were called permanent and flow-through differences. The most significant
21 of these differences is AFUDC, which for many years was recorded on a
22 net of tax basis for both the interest and equity components of AFUDC.
2011 ETI Rate Case 3-329
Entergy Texas, Inc. Page 47 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. WHAT IS THE RESULT OF THE TAX METHOD 1 CALCULATIONS?
2 A. The result of the above calculation equals the taxable component of
3 return. This taxable return is multiplied by the tax factor 0.5384615 (Tax
4 Rate divided by One minus the Tax Rate, (which is .35/1-.35)), resulting in
5 the total FIT amount before adjustments.
6 From this amount is subtracted the ITC amortization and
7 amortization of excess deferred taxes to determine total FIT (Method 1).
8
9 Q. DOES THE AMOUNT COMPUTED UNDER METHOD 1 DIFFER FROM
10 THE AMOUNT SHOWN ON SCHEDULE G-7.6, ANALYSIS OF TEST
11 YEAR FIT AND REQUESTED FIT - TAX METHOD 2, AT REQUESTED
12 RATES?
13 A. No, it is the same amount. The two calculations result in the same
14 amount of FIT expense.
15
16 Q. PLEASE DESCRIBE SCHEDULE G-7.9, AMORTIZATION OF
17 PROTECTED AND UNPROTECTED EXCESS DEFERRED TAXES.
18 A. This schedule summarizes the amortization of protected and unprotected
19 excess deferred FIT. Schedules G-7.9 through G.7-9c are sponsored by
20 Company witness Roberts.
2011 ETI Rate Case 3-330
Entergy Texas, Inc. Page 48 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. PLEASE DESCRIBE SCHEDULE G-7.9a.
2 A. This schedule reflects the amount of protected excess deferred FIT
3 included in the test year and the unamortized balance of protected excess
4 deferred FIT as of June 30, 2011.
5
6 Q. PLEASE DESCRIBE SCHEDULE G-7.9b.
7 A. Schedule G-7.9b provides a reconciliation of excess deferred FIT as of
8 June 30, 2011.
9
10 Q. WHAT INFORMATION IS PROVIDED IN SCHEDULE G-7.9c?
11 A. The Company’s unprotected excess deferred FIT was fully amortized at
12 the end of July 1991.
13
14 Q. PLEASE DESCRIBE SCHEDULE G-7.10, EFFECTS OF ACCOUNTING
15 ORDER DEFERRALS.
16 A. This schedule lists and explains all effects on requested FIT and ADFIT of
17 the Company's deferred accounting approved by the Commission in
18 previous dockets. These are no accounting order deferrals remaining on
19 ETI’s books.
20
21 Q. PLEASE DESCRIBE SCHEDULE G-7.11, EFFECTS OF POST-TEST
22 YEAR ADJUSTMENTS.
23 A. The Company made no post-test year adjustments to rate base.
2011 ETI Rate Case 3-331
Entergy Texas, Inc. Page 49 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. SCHEDULES G-7.12 AND G-7.12a RELATE TO DEFERRED FIT THAT
2 IS PART OF A RATE MODERATION PLAN. DOES THE COMPANY
3 HAVE A RATE MODERATION PLAN?
4 A. No.
5
6 Q. PLEASE DESCRIBE SCHEDULE G-7.13, LIST OF FIT TESTIMONY.
7 A. Schedule G-7.13 simply provides page references to Company
8 witness testimony supporting FIT and ADFIT.
9
10 7. Outside Services Schedule
11 Q. PLEASE DESCRIBE SCHEDULE G-8.
12 A. This schedule presents information on all outside services employed
13 during the test year that appear in the FERC 900 series accounts. The
14 information is shown as follows: column (a) is the FERC account; column
15 (b) is the vendor sorted by category; column (c) is the purpose of the
16 service; column (d) indicates whether the service is recurring or non-
17 recurring; and column (e) is the amount. Items of a non-recurring nature
18 are removed or normalized in the requested cost of service.
2011 ETI Rate Case 3-332
Entergy Texas, Inc. Page 50 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 8. Taxes Other Than Income Tax Schedules
2 Q. PLEASE DESCRIBE SCHEDULE G-9.
3 A. This schedule shows the amount of taxes other than income taxes for the
4 three most recent calendar years, the test year expense, adjustments to
5 the test year and the total adjusted tax amount.
6
7 Q. PLEASE DESCRIBE SCHEDULE G-9.1.
8 A. Schedule G-9.1 reflects the ad valorem taxes assessed and the related
9 plant balances for the last three calendar years and the test year.
10
11 9. Factoring Expense Schedule
12 Q. PLEASE DESCRIBE SCHEDULE G-10.
13 A. This schedule is not applicable to ETI because the Company does not
14 factor accounts receivable.
15
16 10. Deferred Expense Information Schedule
17 Q. PLEASE DESCRIBE SCHEDULE G-11.
18 A. Schedule G-11 includes information concerning all amortization expense
19 either included in the test year or requested by the Company in this rate
20 filing. The information is categorized by:
21  authorizing docket;
22  original amount to be amortized;
23  deferral period;
2011 ETI Rate Case 3-333
Entergy Texas, Inc. Page 51 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1  date amortization began;
2  total amortization taken as of the beginning of the test year;
3  amortization expense for the test year;
4  amortization expense included in requested cost of service;
5 and
6  unamortized amount as of the end of the test year.
7
8 11. Below the Line Expenses Schedule
9 Q. PLEASE DESCRIBE SCHEDULE G-12.
10 A. Schedule G-12 presents a complete analysis of all expenses charged
11 "below the line" during the test year. Verification that "below the line"
12 expenses have been eliminated from the filing has been provided in the
13 workpapers (WP/G-12) for this schedule. The starting point for the
14 Company’s cost of service is net utility operating income. None of the
15 items recorded below the line are included in the calculation of net utility
16 operating income and none of the items recorded below the line are
17 included in any adjustment that would include these amounts in cost of
18 service.
19
20 12. Non-Recurring Expense Schedule
21 Q. PLEASE DESCRIBE SCHEDULE G-13.
22 A. Schedule G-13 describes any nonrecurring extraordinary expenses the
23 Company is requesting in this filing. The only such item the Company is
2011 ETI Rate Case 3-334
Entergy Texas, Inc. Page 52 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 including in the filing is the recovery of insurance amounts related to storm
2 securitizations as described in Adjustment 15.
3
4 13. Rate Case Expense Schedules
5 Q. PLEASE DESCRIBE SCHEDULE G-14.
6 A. Schedule G-14 details the various expenses charged to FERC Account
7 928, Regulatory Expense, during the test year, the Company’s
8 adjustments to the test year amounts, and the Company’s request for
9 each item.
10
11 Q. PLEASE DESCRIBE SCHEDULE G-14.1.
12 A. Schedule G-14.1 provides information concerning estimated rate case
13 expenses for this case, detailed by each type of expense.
14
15 Q. PLEASE DESCRIBE SCHEDULE G-14.2.
16 A. Schedule G-14.2 provides information concerning rate case expenses
17 related to previous rate applications which were not previously considered
18 by the Commission.
19
20 14. Monthly O&M Schedules
21 Q. PLEASE DESCRIBE SCHEDULE G-15.
22 A. Schedule G-15 includes the O&M expense for the test year. The schedule
23 provides O&M expense by month, by account, and the total booked for the
2011 ETI Rate Case 3-335
Entergy Texas, Inc. Page 53 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 test year. This schedule also includes total adjusted O&M expenses
2 claimed, including subtotals by functional classification. The Company
3 has also detailed the amount of O&M expense by account that was the
4 result of a transaction with an affiliate and presents this information in the
5 Schedule G-6 series of Schedules.
6
7 G. Schedule H – Engineering Information
8 Q. PLEASE DESCRIBE SCHEDULES H-1 THROUGH H-1.2d.
9 A. Schedules H-1 through H-1.2d provide detailed information related to the
10 production plant O&M expenses for all power generating stations.
11 Schedules H-1 through H-1.2d are co-sponsored by Company witness
12 Winfred W. Garrison.
13
14 Q. PLEASE DESCRIBE SCHEDULE H-2.
15 A. Schedule H-2 provides the information in Schedule H-1 adjusted for
16 known and measurable changes. This schedule is co-sponsored by
17 Company witness Garrison.
18
19 Q. PLEASE DESCRIBE SCHEDULE H-3.
20 A. Schedule H-3 is the summary of production O&M expenses incurred for
21 the years 2006 through 2010.
2011 ETI Rate Case 3-336
Entergy Texas, Inc. Page 54 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. PLEASE DESCRIBE SCHEDULE H-5.1.
2 A. Schedule H-5.1 describes the criteria used to determine which unit
3 improvements, modifications, and repairs become capitalized costs. The
4 instructions for Schedule H-5.1 require that workpapers be provided for
5 the retirement units and expense item information (Retirement Catalog).
6 ETI maintains a Retirement Catalog for capitalized units, which is provided
7 in WP/H-5.1.
8
9 Q. PLEASE DESCRIBE SCHEDULE H-10.
10 A. This schedule notes that the most recent River Bend Station
11 Decommissioning Cost Study, dated November 2009, was filed with the
12 PUC on December 30, 2009 in Docket No. 37744 as Exhibit WAC-1 to the
13 testimony of Company witness William A. Cloutier. The Company is not
14 proposing any changes or adjustments to that study.
15
16 H. Schedule J – Financial Statements
17 Q. PLEASE DESCRIBE SCHEDULE J.
18 A. This schedule provides the financial statements considered necessary for
19 presentation of the Company's financial position in accordance with
20 generally accepted accounting practices. The statements provided are
21 the Income Statement, Balance Sheet, Retained Earnings, and Statement
22 of Cash Flows for both the test year and twelve months immediately
2011 ETI Rate Case 3-337
Entergy Texas, Inc. Page 55 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 preceding the test year. Also included are the footnotes to the financial
2 statements.
3
4 Q. PLEASE DESCRIBE SCHEDULE J-1.
5 A. This schedule provides a reconciliation of the balance sheet and the
6 income statement presented on a total Company basis in Schedule J to
7 the same information on a total electric basis.
8
9 Q. PLEASE DESCRIBE SCHEDULE J-2.
10 A. This schedule provides the consolidated financial statements, including
11 the footnotes, for Entergy, the parent of ETI.
12
13 I. Schedule K – Financial Information
14 Q. WOULD YOU PLEASE EXPLAIN SCHEDULE K-1.
15 A. Schedule K-1 of the RFP shows the overall rate of return on invested
16 capital of the Company. Schedules K-1 through K-6 are co-sponsored by
17 Company witness Chris E. Barrilleaux. Column (4) of Schedule K-1 shows
18 that the Company's capitalization percentages are 50.08% debt and
19 49.92% common equity. The component cost rates shown in Column (5)
20 are calculated in supporting Schedules K-2 and K-3. The required cost of
21 common equity requested by the Company in this filing is discussed in the
22 testimony of Company witness Samuel C. Hadaway. The cost of equity
23 reflected in Schedule K-1 is 10.6%.
2011 ETI Rate Case 3-338
Entergy Texas, Inc. Page 56 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 The component cost rates in Column (5) of Schedule K-1 are then
2 applied to the capitalization percentages shown in Column (4) to obtain
3 the overall weighted cost of capital of 8.6683% shown in Column (6). The
4 net original cost rate base of $1,741,096,000 on line 5 is multiplied by the
5 overall rate of return to obtain the requested dollar return on rate base of
6 $150,923,000 on line 7 of Schedule K-1.
7 The capital amount for common equity reflects the common equity
8 balance as of September 30, 2011.
9
10 Q. PLEASE DISCUSS SUPPORTING SCHEDULE K-2.
11 A. Schedule K-2 is no longer applicable to the Company as it has no
12 preferred stock.
13
14 Q. PLEASE DISCUSS SCHEDULE K-3.
15 A. The adjusted overall cost of long-term debt of 6.74% is calculated in
16 Schedule K-3 of the RFP. Details of the sinking fund requirements for
17 long-term debt are also provided in Schedule K-3.
18
19 Q. PLEASE DISCUSS SCHEDULE K-4.
20 A. This schedule shows a listing of notes outstanding at the end of the test
21 year, and at the end of each quarter for the past two years.
2011 ETI Rate Case 3-339
Entergy Texas, Inc. Page 57 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. PLEASE DISCUSS SCHEDULE K-5.
2 A. Schedule K-5 is a summary of security issuance restrictions that apply to
3 the issuance of preferred stock and long-term debt as of the end of the
4 test year, the most recent fiscal year and projections for three fiscal years.
5 The Mortgage Indenture coverage calculation and the Articles of
6 Incorporation calculation provide the restrictions on the amount of
7 securities that can be issued under each test. The projections of each
8 financial test provided for three fiscal years are sponsored by Company
9 witness Barrilleaux.
10
11 Q. PLEASE DESCRIBE SCHEDULE K-6.
12 A. Schedule K-6 contains thirteen specific ratios for the fiscal years 2006
13 through 2010 and the test year, as well as three projected fiscal years. I
14 co-sponsor the projected ratios along with Company witness Barrilleaux.
15
16 J. Schedule M – Nuclear Plant Decommissioning
17 Q. PLEASE DESCRIBE SCHEDULE M-1.
18 A. Schedule M-1 provides general information, decommissioning cost and
19 funding for each decommissioning fund the Company has established.
20
21 Q. PLEASE DESCRIBE SCHEDULE M-2.
22 A. Schedule M-2, the decommissioning funding plan established by the
23 Company provides the actual and projected annual contributions,
2011 ETI Rate Case 3-340
Entergy Texas, Inc. Page 58 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 administrative fees, earnings on the funds, tax payments,
2 decommissioning outlays and accumulated fund balances by year.
3
4 Q. WHAT IS THE COMPANY PROPOSING BASED ON THE M-2
5 INFORMATION?
6 A. The Company is not proposing any change from the current level of
7 revenue requirement resulting from Docket No. 37744. The last
8 decommissioning cost estimate was completed in 2009 and per the rule a
9 cost estimate is only required every five years. The Company’s proposal
10 to request no change in the revenue requirement is further supported by
11 the August 9, 2011 letter from the Nuclear Regulatory Commission
12 included as Exhibit MPC-2 to my testimony.
13
14 K. Schedule P – Class Cost of Service Analysis
15 Q. PLEASE DESCRIBE SCHEDULE P-10.
16 A. Schedule P-10 provides adjusted O&M payroll by account for the test
17 year. The information is categorized by Company, affiliates, and total.
18
19 L. Schedule S – Test Year Review
20 Q. PLEASE DESCRIBE SCHEDULE S.
21 A. Schedule S consists of a report by ETI's independent certified public
22 accountants (“CPAs”), Deloitte & Touche, on a review covering the test
2011 ETI Rate Case 3-341
Entergy Texas, Inc. Page 59 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 year which complies with applicable standards established by the
2 American Institute of CPAs and with the procedures detailed in the RFP.
3
4 Q. PLEASE DESCRIBE THE SCHEDULE S-1 SERIES.
5 A. Schedules S, S-1a, and S-1b include a description summarizing the
6 independent accountants' scope of review procedures and materiality
7 considerations applied to each of the required minimum procedures listed
8 in the RFP instructions for Schedule S.
9
10 Q. PLEASE DESCRIBE SCHEDULE S-2.
11 A. Schedule S-2 indicates that there were no material errors, exceptions, or
12 omissions noted by Deloitte & Touche during the course of the test year
13 review.
14
15 Q. PLEASE DESCRIBE THE SCHEDULE S-3 SERIES.
16 A. Schedules S-3 and S-3a indicate there were no communications by the
17 independent accountants on reportable conditions required by Statement
18 on Auditing Standards No. 60, Communication of Internal Control
19 Structure Related Matters Noted in an Audit.
20
21 Q. PLEASE DESCRIBE SCHEDULE S-4.
22 A. Schedule S-4 requires a copy of adjusting journal entries resulting from
23 the most recent annual audit provided by Deloitte & Touche to ETI for
2011 ETI Rate Case 3-342
Entergy Texas, Inc. Page 60 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 posting to ETI's books. There were no such entries for ETI as the result of
2 the most recent audit.
3
4 Q. PLEASE DESCRIBE SCHEDULE S-5.
5 A. Schedule S-5 includes a copy of all potential or passed adjusting journal
6 entries identified during the course of the most recent annual audit that
7 were not posted to ETI's books.
8
9 Q. PLEASE DESCRIBE SCHEDULE S-6.
10 A. Schedule S-6 requires the name and telephone number of a contact
11 person through whom arrangements can be made to review Deloitte &
12 Touche’s workpapers for the test year review and the most recent annual
13 audit. This schedule also specifies a location in Austin, Texas, where the
14 workpapers will be made available for review.
15
16 VI. RATE CASE EXPENSES
17 Q. WHAT IS THE COMPANY'S ESTIMATE OF RATE CASE EXPENSES
18 ASSOCIATED WITH THIS PROCEEDING?
19 A. Schedule G-14.1 reflects the estimated rate case expenses that the
20 Company will incur in connection with this rate proceeding. Total
21 estimated expenses, including expenses of Cities, are $12,350,000 as
22 shown on page 1. The estimated expenses are based on the assumption
23 the case is litigated and reflect estimated expenses to obtain a final order
2011 ETI Rate Case 3-343
Entergy Texas, Inc. Page 61 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 from the PUC. The Company will collect actual expenses related to this
2 case and submit the expense amounts, along with supporting testimony,
3 in accordance with the procedural schedule ultimately adopted by the
4 Administrative Law Judge.
5
6 Q. ARE COSTS OF ESI INCLUDED IN RATE CASE EXPENSE?
7 A. Yes. ETI uses the services of ESI in preparing rate filings. Employees of
8 ESI, such as myself, were required and needed to provide support or
9 testimony in this proceeding.
10
11 Q. PLEASE DESCRIBE THE PROCEDURE FOR REVIEWING THE
12 COMPANY’S ACTUAL RATE CASE EXPENSES.
13 A. There are a number of consultants and outside lawyers involved in
14 preparing this rate case. The consultants have been retained by ESI or
15 the Company or have been retained by legal counsel representing the
16 Company to provide specialized work needed to support the rate filing.
17 When billings are received from the consultants or through legal
18 counsel, the appropriate personnel review the charges and approve them
19 for payment. The bill is then forwarded to Accounts Payable for payment.
20 Accounts Payable personnel review each bill submitted for payment to
21 determine that proper approval has been made.
2011 ETI Rate Case 3-344
Entergy Texas, Inc. Page 62 of 62
Direct Testimony of Michael P. Considine
2011 Rate Case
1 Q. HOW DOES THE COMPANY PROPOSE TO RECOVER RATE CASE
2 EXPENSES?
3 A. The Company proposes that it be permitted to recover these costs over a
4 three-year period, with a return on the unamortized balance.
5
6 VII. CONCLUSION
7 Q. PLEASE STATE YOUR CONCLUSIONS.
8 A. The Company's requested cost of service and rate base are an accurate
9 reflection of the Company's reasonable and necessary costs as
10 appropriately adjusted and presented in accordance with the PUC's
11 Substantive Rules. Additionally, the adjustments contained in the
12 Company’s filing are appropriate and reflect the regulatory treatment
13 intended.
14
15 Q. DOES THIS CONCLUDE YOUR PREFILED DIRECT TESTIMONY?
16 A. Yes.
2011 ETI Rate Case 3-345
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2011 ETI Rate Case 3-346
Exhibit MPC-1
2011 TX Rate Case
Page 1 of 5
Entergy Texas, Inc.
Listing of Rate Filing Package Schedules Sponsored
Or Co-Sponsored By Michael P. Considine
Line No. Schedule Description Sponsor Co-Sponsor
1 A-4 Detail TYE Trial Balance X
2 B-1 Rate Base & Return-Total Co X
3 B-1.2 % Of Plant In Service X
4 B-1.3 Penalties Or Fines X
5 B-1.4 Post Test Year Adjustments X
6 B-2 Accumulated Provision Balances X
7 B-2.1 Accumulated Provision Policies X
8 C-1 Original Cost of Utility Plan X
9 C-2 Detail Of Orig Cost Of Util Plant X
10 C-3 Monthly Detail Of Util Plt In Svc X
11 C-4.1 CWIP By Functional Group X
12 C-4.2 CWIP Allowed In Rate Base X
13 C-5 AFUDC or IDC X
14 C-6 Nuclear Fuel X
15 C-6.1 Nuclear Fuel in Process X
16 C-6.2 Distrib Of Costs & Qnts-A/C 120-1 X
17 C-6.3 Distrib Of Costs & Qnts-A/C 120.2 X
18 C-6.4 Distrib Of Costs & Qnts-A/C 120.3 X
19 C-6.5 Distrib Of Costs & Qnts-A/C 120.4 X
20 C-6.6 Distrib Of Costs & Qnts-A/C 120.5 X
21 C-6.7 Distrib Of Costs & Qnts-A/C 120.6 X
22 C-6.8 Allocation Of Unassigned Balance X
23 C-6.9 Nuclear Fuel Inventory Policy X
24 C-6.10 Nuclear Fuel Trust/Lease X
25 D Narrative-Accum Depr Sect As Spcfd X
26 D-1 Accum Dpr By Funct Grp/Prim A/C X
27 D-2 Accum Dpr BookingMethods X
28 D-3 Plant Held For Future Use X
29 D-4 Depreciation Expense X
30 D-5 Depreciation Rate Study X
2011 ETI Rate Case 3-347
Exhibit MPC-1
2011 TX Rate Case
Page 2 of 5
Entergy Texas, Inc.
Listing of Rate Filing Package Schedules Sponsored
Or Co-Sponsored By Michael P. Considine
Line No. Schedule Description Sponsor Co-Sponsor
31 D-6 Retirement Data for All Generating Units X
32 D-7 Summary Of Book Salvage X
33 D-8 Service Lives X
34 E-1 Monthly Blnces-Short Term Assets X
35 E-1.1 Detail Of Short Term Assets X
36 E-1.2 Obsolete Assets X
37 E-1.3 Short Term Assets Policies X
38 E-2.2 Fossil Fuel Inventory Evaluation X
39 E-2.3 Fossil Fuel Inventories X
40 E-2.4 Fossil Fuel Inventory Levels X
41 E-4 Working Cash Allowance X
42 E-5 Prepaymnts + Matrls & Supplies X
43 E-6 Customer Deposits X
44 G-1 Payroll Information X
45 G-1.1 Regular * Overtime Payroll X
46 G-1.2 Regular Payroll By Category X
47 G-1.3 Payroll Capitalized vs. Expenses X
48 G-1.4 Payroll By Company X
49 G-1.6 Payments Oth Than Standard Pay X
50 G-2.1 Pension Expense X
51 G-2.2 Postretirement Benefits Excl Pens X
52 G-3 Bad Debt Expense X
53 G-4 Summ Of Adtsng, Contrbtns, Dues X
54 G-4.1 Summary Of Advertising Expense X
55 G-4.1a Summ Of Inform/;instruct Advtsng X
56 G-4.1b Advtsng Summ-Promote/Rtn Use X
57 G-4.1c Summ Of General Advtsng Exp X
58 G-4.1d Capitalized Advertising X
59 G-4.2 Summ-Contrbtn & Donation Exp X
60 G-4.2a Summ-Educat Contrbtns/Dontns X
2011 ETI Rate Case 3-348
Exhibit MPC-1
2011 TX Rate Case
Page 3 of 5
Entergy Texas, Inc.
Listing of Rate Filing Package Schedules Sponsored
Or Co-Sponsored By Michael P. Considine
Line No. Schedule Description Sponsor Co-Sponsor
61 G-4.2b Summ-Commun Svc Contr/Dontns X
62 G-4.2c Summ-Econ Dvlpmnt Contr/Dontns X
63 G-4.3 Summary-Membership Dues Exp X
64 G-4.3a Summary-Industry Organztn Dues X
65 G-4.3b Summ-Business/Economic Dues X
66 G-4.3c Summary-Professional Dues X
67 G-4.3d Summ-Socl/Recrtnl/Fratnl/Relgs Exp X
68 G-4.3e Summ-Political Organztns Exp X
69 G-5 Summ-Exclsns From Test Yr Exp X
70 G-5.1 Analysis Of Legislative Advocacy X
71 G-5.1a Payments To Registrd Lobbyists X
72 G-5.1b Payments For Monitoring Legislatn X
73 G-5.2 Summary Of Penalities & Fines X
74 G-5.3 Other Exclusions X
75 G-5.4 Analysis Of Prior Rt Case Exclsns X
76 G-5.5 Comprsn-Pr Rt Cse Excl To Currnt X
77 G-7.1 Recon-Test Yr Bk Net Inc & Tax Net Inc X
78 G-7.2 Plant Adjustments X
79 G-7.4 ADFIT X
80 G-7.4b Adjustments to ADFIT X
81 G-7.4c ADFIT & ITC-Plt Adjstmnts & Alloc X
82 G-7.4d ADFIT-Rate Case Expense X
83 G-7.5c ITC Utilized-Stand Alone Basis X
84 G-7.5e FERC A/C 255 Balance X
85 G-7.6 Analys-TY & Rqstd FIT-Tx Meth 2 X
86 G-7.6a Analysis Of Deferred FIT X
87 G-7.7 Analysis Of Addtnl Deprec Rqstd X
88 G-7.8 Analys-TV & Rqstd FIT-Tx Meth 1 X
89 G-7.10 Effects Of Acctng Order Deferrals X
90 G-7.11 Effct-Post TY Adjust-FIT & ADFIT X
2011 ETI Rate Case 3-349
Exhibit MPC-1
2011 TX Rate Case
Page 4 of 5
Entergy Texas, Inc.
Listing of Rate Filing Package Schedules Sponsored
Or Co-Sponsored By Michael P. Considine
Line No. Schedule Description Sponsor Co-Sponsor
91 G-7.12 Effcts-Rt Modrtn Plan-FIT & ADFIT X
92 G-7.12a Trtmnt=FIT/ADFIT in Rt Modrtn Pln X
93 G-7.13 List of FIT/ADFIT Testimony X
94 G-8 Outside Svcs Emp-FERC 900 Exp X
95 G-9 Taxes Oth Than Inc Taxes (UR X
96 G-9.1 Ad Valorem Txs & Plt Balances X
97 G-10 Factoring Expense (UR) X
98 G-11 Def Expenses From Prior Dckts X
99 G-12 Below The Line Expenses X
100 G-13 Nonrecurring Or Extrdnry Exp X
101 G-14 Regulatory Commission Exp X
102 G-14.1 Rate Case Expenses X
103 G-14.2 Rate Case Exp-Pr Rate Applctns X
104 G-15 Monthly O&M Expense X
105 H-1 Summ Of Test Yr Prod O&M Exp X
106 H-1.1 Nucl Co-Wide O&M Exp Summary X
107 H-1.1a Nucl Plt O&M Summary X
108 H-1.1a1 Nucl Unit O&M Summary X
109 H-1.2 Fossil Co-Wide O&M Exp Summ X
110 H-1.2a Nat Gas Plt O&M Summary X
111 H-1.2a1 Natural Gas (Steam Genrtn) X
112 H-1.2a2 Natural Gas (Combustn Turbine) X
113 H-1.2b Coal Plant O&M Summary X
114 H-1.2c Lignite Plant O&M Summary X
115 H-1.2d Oth Plant O&M Summary X
116 H-2 Summ-Adjstd TY Prod O&M Exp X
117 H-3 Summary-Act. Prod. O&M Exp Incurred X
118 H-5.1 Prod Plt Capital Cost Methodology X
119 H-10 Nucl Decommiss Cost Studies X
120 J Financial Statements X
2011 ETI Rate Case 3-350
Exhibit MPC-1
2011 TX Rate Case
Page 5 of 5
Entergy Texas, Inc.
Listing of Rate Filing Package Schedules Sponsored
Or Co-Sponsored By Michael P. Considine
Line No. Schedule Description Sponsor Co-Sponsor
121 J-1 Reconciliation-Total Co To Total Elec X
122 J-2 Consolidated Finance Statements X
123 K-1 Weighted Avg Cost Of Capital X
124 K-2 Wghtd Avg Cost Of Preferred Stock X
125 K-3 Wghtd Avg Cost Of Debt X
126 K-4 Notes Payable X
127 K-5 Security Issuance Restrictions X
128 K-6 Financial Ratios X
129 P-10 Payroll Expense Distribution X
130 S Test Yr Review As Specfd X
131 S-1 Scope Of Review X
132 S-2 Errors/Excptns Noted-Indp Accnts X
133 S-3 Communictns From Indept Accnts X
134 S-4 Adjusting Journal Entries X
135 S-5 Passed Adjstng Journal X
136 S-6 Workpaper Review-Indep Acctnts X
2011 ETI Rate Case 3-351
This page has been intentionally left blank.
2011 ETI Rate Case 3-352
Exhibit MPC-2
2011 TX Rate Case
Page 1 of 3
UNITED STATES
NUCLEAR REGULATORY COMMISSION
WASHINGTON , O.C. 20555-0001
August 9 2011
1
Vice President, Operations
Entergy Operations, Inc.
River Bend Station
5485 U.S. Highway 61 N
St. Francisville, LA 70775
SUBJECT: ENTERGY GULF STATES LOUISIANA, LLC 'S STATUS OF
DECOMMISSIONING FUNDING ASSURANCE FOR RIVER BEND STATION,
UNIT 1 (70 PERCENT REGULATED) (TAC NO. ME5526)
Dear Sir or Madam:
By letter dated March 31 , 2011 (Agencywide Documents Access and Management System
Accession No. ML 110940138), Entergy Operations, Inc. (the licensee), submitted the biennial
decommissioning funding report for River Bend Station (RBS) for both the regulated portion of
the unit (70 percent) and the unregulated portion of the unit (30 percent).
The U.S. Nuclear Regulatory Commission (NRC) staff has concluded that the 30 percent non-
regulated portion of RBS meets the required minimum funding criteria of Title 10 of the Code of
Federal Regulations (10 CFR) 50.75(b) and (c) based on the current funding level of the
decommissioning trust fund , length of time remaining on the license, and expected earnings on
the trust fund balance.
The NRC staff has concluded that the 70 percent rate-regulated portion of RBS meets the
required minimum funding criteria of 10 CFR 50.75(b) and (c) based on its current funding level,
length of time remaining on the license, expected earnings on the trust fund , and future
collections to the trust fund from the Louisiana Public Service Commission (LPSC) and the
Public Utilities Commission of Texas (PUCT). For the regulated portion of RBS (70 percent),
the licensee submitted orders from the LPSC and PUCT approving decommissioning trust fund
collections through 2034 for RBS .
The NRC has concluded that RBS is on track to have sufficient funds for decommissioning at
the time of permanent termination of operations is expected. As such, we consider our review
of the decommissioning funding report complete with the issuance this letter.
Paperwork Reduction Act Statement
This letter does not contain any new or amended information collection requirements subject to
the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq .). Existing collection requirements
under 10 CFR Part 50 were approved by the Office of Management and Budget (OMB), control
number 3150-0011 , which expires August 31 , 2013.
2011 ETI Rate Case 3-353
Exhibit MPC-2
2011 TX Rate Case
Page 2 of 3
-2-
Public Protection Notification
The NRC may not conduct or sponsor, and a person is not required to respond to, an
information collection unless the requesting document displays a currently valid OMS control
number.
If you have any questions regarding this review, please contact me at alan.wang@nrc.gov or
(301) 415-1445.
Sincerely,
~vJ~
Alan B. Wang, Project Manager
Plant Licensing Branch IV
Division of Operating Reactor Licensing
Office of Nuclear Reactor Regulation
Docket No. 50-458
cc: Distribution via Listserv
2011 ETI Rate Case 3-354
Exhibit MPC-2
2011 TX Rate Case
Page 3 of 3
-2-
Public Protection Notification
The NRC may not conduct or sponsor, and a person is not required to respond to , an
information collection unless the requesting document displays a currently valid OMS control
number.
If you have any questions regarding this review, please contact me at alan.wang@nrc.gov or
(301) 415-1445.
Sincerely,
/RAJ
Alan 8. Wang , Project Manager
Plant Licensing Branch IV
Division of Operating Reactor Licensing
Office of Nuclear Reactor Regulation
Docket No. 50-458
cc : Distribution via Listserv
DISTRIBUTION :
PUBLIC
LPUV r/f
RidsAcrsAcnw_MailCTR Resource
RidsNrrDprPfpb Resource
RidsNrrDorllpl4 Resource
RidsNrrLAJBurkhardt Resource
RidsNrrPMRiverBend Resource
RidsOgcRp Resource
RidsRgn4Mai1Center Resource
MDusaniwskyj, NRR/DPR/PFPB
TFredrichs, NRR/DPR/PFPB
SUttal, OGC
ADAMS Accession No. ML112010507 *memo dated
OFFICE NRR/L PL4/PM NRR/LPL4/ LA NRR/DPR/PFPB/BC OGC NLO NRR/LPL4/BC NRR/LPL4/PM
AWang (LWilkins
AWang ... CRegan ASimmons tor" SUttal MMarkley for)
--NAME
DAT E 7/25/11
JBurkhardt
7/21/11 7/15/1 1 7128/1 1 8/9/ 11 8/9/11
OFFICIAL AGENCY RECORD
2011 ETI Rate Case 3-355
This page has been intentionally left blank.
2011 ETI Rate Case 3-356
SOAH Docket No. XXX-XX-XXXX
PUC Docket No. 39896
ETI 2011 Rate Case
ETI EXHIBIT NO. 15
DOCKET NO. 39896
APPLICATION OF ENTERGY § PUBLIC UTILITY COMMISSION
TEXAS, INC. FOR AUTHORITY §
TO CHANGE RATES AND § OF TEXAS
RECONCILE FUEL COSTS §
DIRECT TESTIMONY
OF
JAY C. HARTZELL, Ph.D.
ON BEHALF OF
ENTERGY TEXAS, INC.
NOVEMBER 2011
2011 ETI Rate Case 5-1
ENTERGY TEXAS, INC.
DIRECT TESTIMONY OF JAY C. HARTZELL, Ph.D.
2011 RATE CASE
TABLE OF CONTENTS
Page
I. Background and Introduction 1
II. Overview of the Issues Surrounding Incentive Compensation 3
III. The False Dichotomy Between Compensation Tied to "Financial"
Measures and Compensation Tied to "Operational" Measures; and
the Benefits of Cost Control, Profitability, and Stock Price Measures 9
IV. Costs to Customers of Discouraging the Use of Incentive
Compensation That is Linked to Cost Control, Profitability and
Stock Prices 22
V. Response to Common Arguments Against Incentive Compensation
Linked to Cost Control, Profitability and Stock Prices from the
Customers' Perspective 28
VI. Conclusion 31
EXHIBITS
EXHIBIT JCH-1 Curriculum Vitae of Jay C. Hartzell
2011 ETI Rate Case 5-2
Entergy Texas, Inc. Page 1 of 31
Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 I. BACKGROUND AND INTRODUCTION
2 Q. PLEASE STATE YOUR NAME, TITLE, AND BUSINESS ADDRESS.
3 A. My name is Jay C. Hartzell. I am the Chair of the Finance Department,
4 Professor of Finance, and the Allied Bancshares Centennial Fellow at the
5 McCombs School of Business at the University of Texas at Austin. My
6 business address is Department of Finance, The University of Texas at
7 Austin, 1 University Station B6600, Austin, Texas 78712.
8
9 Q. ON WHOSE BEHALF ARE YOU TESTIFYING?
10 A. I am testifying on behalf of Entergy Texas, Inc. ("ETI" or the "Company").
11
12 Q. PLEASE STATE YOUR EDUCATION, PROFESSIONAL AND WORK
13 EXPERIENCE.
14 A. I obtained a Bachelor of Science degree (cum laude) from Trinity
15 University in May 1991, with majors in Business Administration and
16 Economics. After graduating, I went to work as a consultant for Hewitt
17 Associates in The Woodlands, Texas. Hewitt is a consulting firm that
18 specializes in benefits and compensation. While there, I specialized in the
19 area of defined contribution plans. I left Hewitt to go to graduate school at
20 the University of Texas at Austin in 1993. I completed my PhD in finance
21 there in May 1998. Upon graduating, I took a job as an Assistant
22 Professor of Finance at New York University's Stern School of Business,
23 where I worked until 2001. At that time, the University of Texas at Austin
2011 ETI Rate Case 5-3
Entergy Texas, Inc. Page 2 of 31
Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 hired me as an Assistant Professor at the McCombs School of Business
2 ("McCombs School"), where I have worked since. I was promoted to the
3 rank of Associate Professor (with tenure), effective in the fall of 2006.
4 Beginning in the fall of 2008, I was given the title of Allied Bancshares
5 Centennial Fellow. I also now serve as the Executive Director of the Real
6 Estate Finance and Investment Center at the McCombs School. As of
7 September 2011, I was promoted to Professor and assumed the duties of
8 the Chair of the Finance Department. My current curriculum vitae is
9 attached as Exhibit JCH-1.
10
11 Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE A REGULATORY
12 COMMISSION?
13 A. Yes. I have submitted written testimony on incentive compensation issues
14 and testified on behalf of the Company before the Public Utility
15 Commission of Texas ("Commission" or "PUCT") in PUCT Docket Nos.
16 34800 and 37744, and on behalf of Entergy Louisiana, LLC before the
17 Louisiana Public Service Commission on incentive compensation issues in
18 Docket No. U-20925. I have also submitted written testimony on behalf of
19 Entergy Arkansas, Inc. before the Arkansas Public Service Commission
20 on incentive compensation issues in Docket No. 09-084-U.
2011 ETI Rate Case 5-4
Entergy Texas, Inc. Page 3 of 31
Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 II. OVERVIEW OF THE ISSUES SURROUNDING INCENTIVE
2 COMPENSATION
3 Q. WHAT FORMS OF INCENTIVE COMPENSATION DO YOU FOCUS ON
4 IN YOUR TESTIMONY?
5 A. The focus of my testimony is on incentive compensation that is linked to
6 cost control measures (for operating costs and capital expenditures),
7 profitability measures (including earnings and operating cash flow), and
8 stock prices. Compensation that is linked to these sorts of measures – for
9 companies generally and for ETI in particular – include annual incentive
10 plans, long-term incentive plans, restricted stock grants, and stock option
11 grants. The compensation could come in the form of cash (as in annual
12 incentive plans), stock or stock-based units (as in ETI's long-term
13 incentive plan, or "LTIP"), or options.
14
15 Q. WHAT IS YOUR UNDERSTANDING OF HOW COMPENSATION BASED
16 ON COST CONTROLS, PROFITABILITY AND STOCK PRICES HAS
17 BEEN CHARACTERIZED IN RECENT PUCT RATE DECISIONS?
18 A. In such cases, compensation that is linked to cost controls, profitability
19 and stock prices as discussed in the previous question has commonly
20 been referred to as incentive compensation that is based on "financial
21 measures." This category of incentives has been distinguished from
22 incentive compensation that is based on measures that are not
23 denominated in dollars, such as customer satisfaction, reliability, and
2011 ETI Rate Case 5-5
Entergy Texas, Inc. Page 4 of 31
Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 safety metrics, which has commonly been categorized as incentive
2 compensation based on "operational measures." As I discuss later in my
3 testimony, I view this as a false dichotomy for the purposes of assessing
4 whether customers benefit from a particular form of incentive
5 compensation.
6
7 Q. WHY DO FIRMS USE INCENTIVE COMPENSATION IN GENERAL, AND
8 COMPENSATION BASED ON COST CONTROLS, PROFITABILITY AND
9 STOCK PRICES MORE SPECIFICALLY?
10 A. Incentive compensation is a prevalent tool used to attract, motivate, and
11 retain the qualified and talented employees needed to ensure that a
12 business can continue to operate successfully. To understand why it is so
13 widely used, it is first useful to draw a distinction between the level and
14 form of compensation. The level of compensation can be thought of as
15 the total dollar value of compensation received by an employee from all
16 sources, including salary, cash incentive-based pay, the value of
17 long-term incentives such as stock performance units and options granted,
18 and the value of benefits. In order to attract and retain employees, this
19 level needs to be in line with the labor market for a particular type of
20 employee, whether it is an engineer, a maintenance worker, or a chief
21 executive officer. Otherwise, all things equal, that same employee will
22 take a job with a company that is offering the more attractive level of pay
2011 ETI Rate Case 5-6
Entergy Texas, Inc. Page 5 of 31
Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 and benefits. Company witness Kevin G. Gardner discusses the overall
2 reasonableness of ETI's level of compensation in his direct testimony.
3
4 Q. HOW DOES THE FORM OF COMPENSATION DIFFER FROM THE
5 LEVEL OF COMPENSATION?
6 A. The form of compensation can be thought of as the split of total
7 compensation across these components – for example, how much is paid
8 via salary versus annual incentive-based compensation. Holding the total
9 level of compensation fixed at the proper market level, the form of
10 compensation is important because it can help motivate employees to
11 engage in behaviors that positively impact the operational efficiency of the
12 firm, or positively affect its cost structure. At the same time, the form of
13 compensation is important to attract and retain certain types of employees
14 that offer a skill set or a particular talent that is important to the company's
15 operations. For example, if a compensation plan provides for incentive
16 payments if goals are met – such as controlling costs at some level – then
17 according to basic economic theory, employees will be motivated to work
18 harder toward those goals. More subtly, such incentive pay will tend to
19 attract and retain employees who believe that they are especially good at
20 controlling costs because they will expect higher compensation under
21 such a plan. This implies that a firm seeking to manage costs will find it
22 valuable to institute such an incentive compensation plan as part of the
2011 ETI Rate Case 5-7
Entergy Texas, Inc. Page 6 of 31
Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 design of the form of compensation, while keeping the level of
2 compensation at a competitive market-based amount.
3
4 Q. WHAT IS YOUR UNDERSTANDING OF THE COMMISSION'S
5 PREVIOUS VIEW ON ALLOWING THE RECOVERY OF INCENTIVE
6 COMPENSATION EXPENSE THROUGH RATES?
7 A. My understanding of the Commission's recent rulings on this issue is that
8 the Commission has distinguished between compensation tied to what it
9 has termed operational measures and compensation tied to what it has
10 termed financial measures. Generally, the Commission has not allowed
11 for the recovery of incentive compensation tied to financial measures
12 through rates, but has allowed for the recovery of incentive compensation
13 tied to operational measures. The core rationale for this distinction has
14 been that it has not been sufficiently demonstrated that incentive
15 compensation linked to financial measures is in the public interest or of
16 direct benefit to customers. The decisions in those previous cases,
17 however, do not reflect a review or consideration of the relevant literature
18 or other matters I discuss below, all of which support a conclusion that
19 allowing utilities to use incentive pay based on cost control, profitability,
20 and stock prices is properly viewed as in the public interest and is
21 expected to be of direct benefit to customers.
2011 ETI Rate Case 5-8
Entergy Texas, Inc. Page 7 of 31
Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 Q. HOW WOULD YOU SUMMARIZE YOUR OPINION ON THE ISSUE OF
2 WHETHER INCENTIVE COMPENSATION BASED ON COST
3 CONTROLS, PROFITABILITY, AND STOCK PRICES BENEFITS
4 CUSTOMERS?
5 A. In my opinion, a well-designed compensation plan that includes incentive
6 compensation tied to cost controls, profitability, and stock prices would
7 tend to provide greater benefits to customers than an otherwise similar
8 compensation plan that did not include any such incentive compensation.
9 I discuss the details below, but the overarching basis for my opinion is as
10 stated above: incentive compensation based on cost control, profitability,
11 and stock prices helps companies attract, motivate, and retain talented
12 employees, and by doing so, both customers and shareholders directly
13 benefit. Moreover, if ETI's incentive compensation were only based on
14 non-dollar-based measures such as safety and reliability, customers
15 would tend to be worse off, because such a plan would not provide
16 employees with incentives to look after the financial health of the
17 Company. The important point is that customers and shareholders both
18 benefit from well-designed, balanced compensation plans that provide
19 employees with the appropriate level of compensation and that include
20 incentives based on cost control, profitability, stock prices, and
21 non-dollar-based measures such as reliability, safety and customer
22 satisfaction.
2011 ETI Rate Case 5-9
Entergy Texas, Inc. Page 8 of 31
Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 Q. IS YOUR OPINION THAT CUSTOMERS WILL TEND TO BENEFIT
2 FROM INCENTIVE COMPENSATION TIED TO COST CONTROLS,
3 PROFITABILITY AND STOCK PRICES SUPPORTED BY EMPIRICAL
4 EVIDENCE?
5 A. Yes. As I discuss in more detail below, there are multiple studies
6 published in peer-reviewed journals that report evidence that is consistent
7 with my testimony. Published empirical research has shown that workers
8 respond to incentive plans in a manner consistent with the intent behind
9 the plans' design. Thus, if a company adopts a compensation plan that
10 includes incentives based on customer welfare and stock price, one can
11 expect managers to take actions to improve customer welfare and
12 maximize stock price (holding all else equal). There is also empirical
13 evidence that following the adoption of long-term incentive plans that
14 provide for stock-based compensation, managers’ interests appear more
15 closely aligned with those of the firms’ customers. In addition, there is
16 evidence that stockholders’ and customers’ interests tend to be aligned,
17 rather than opposed, suggesting that incentive compensation linked to
18 stock prices is likely to improve customer satisfaction rather than detract
19 from it.
2011 ETI Rate Case 5-10
Entergy Texas, Inc. Page 9 of 31
Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 III. THE FALSE DICHOTOMY BETWEEN COMPENSATION TIED TO
2 "FINANCIAL" MEASURES AND COMPENSATION TIED TO
3 "OPERATIONAL" MEASURES; AND THE BENEFITS OF COST
4 CONTROL, PROFITABILITY, AND STOCK PRICE MEASURES
5 Q. DO YOU AGREE WITH THE OPINION THAT INCENTIVE
6 COMPENSATION LINKED TO WHAT THE COMMISSION HAS TERMED
7 "FINANCIAL MEASURES" DOES NOT PROVIDE DIRECT BENEFITS TO
8 CUSTOMERS?
9 A. No. Based on its previous rulings, the Commission appears to be
10 categorizing as "financial" all incentive performance measures that have
11 been labeled as such by the utility and that are based on dollar amounts.
12 These include not only measures such as earnings per share, but also
13 measures designed to promote cost containment.1 In reading these
14 decisions and the debates among the parties discussed therein, much of
15 the discussion seems to take it as given that incentives linked to financial
16 (or dollar-based) measures, regardless of their specific characteristics, do
17 not benefit customers. As a result, the competing viewpoints reflected in
18 these decisions seem to address mainly whether to label particular
19 measures as operational or financial.2
20 Instead of focusing on whether a particular measure is dollar-based
21 or not – and therefore, whether incentives linked to that measure are
22 "financial" or "operational" based on the above dichotomy – I think it is
1
For example, see PUCT Docket No. 28840, PFD at 78.
2
For example, see PUCT Docket No. 35717, PFD at 98.
2011 ETI Rate Case 5-11
Entergy Texas, Inc. Page 10 of 31
Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 more worthwhile to return to the primary question: whether specific
2 incentives linked to dollar-based measures (including cost control,
3 profitability, and stock prices) are of benefit to customers.
4
5 Q. WHY WOULD INCENTIVE COMPENSATION LINKED TO COST
6 CONTROL, PROFITABILITY, AND STOCK PRICE MEASURES BE OF
7 DIRECT BENEFIT TO CUSTOMERS?
8 A. This is the case because these measures provide a necessary and
9 important incentive to managers to improve service and control costs.
10 Perhaps the easiest example of a dollar-based measure that could be
11 used in an incentive compensation plan that would benefit customers
12 directly is cost containment. As an example, consider an incentive
13 compensation plan that pays corporate managers an incentive award if
14 costs are suitably contained. On the one hand, such an incentive is likely
15 to benefit shareholders to some extent – managers who work under such
16 a compensation plan will work to control costs in order to achieve their
17 incentive compensation, and to the extent that they are successful, the
18 company will generate greater profits, benefiting shareholders. But
19 customers also directly benefit, because the company has lower costs,
20 and through the regulatory process, customers will ultimately pay lower
21 rates than they otherwise would have paid in the absence of such cost
22 controls.
2011 ETI Rate Case 5-12
Entergy Texas, Inc. Page 11 of 31
Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 Q. WHAT IS THE ROLE OF THE REGULATORY PROCESS IN ENSURING
2 THAT INCENTIVES LINKED TO COST CONTROL BENEFIT
3 CUSTOMERS?
4 A. To understand the role of the regulatory process in linking cost control to
5 customer benefit, first consider an extreme example where there is no
6 regulatory lag and rates adjust instantaneously so that any change in a
7 utility's costs is immediately passed through to customers. In this case, a
8 cost-containment incentive clearly directly benefits customers and does
9 not benefit shareholders at all because customers reap the entire benefit
10 of any cost-saving innovations. In the other extreme, if rates never adjust
11 to changes in costs, then a cost-containment incentive benefits
12 shareholders but not customers. Thus, the regulatory process plays the
13 critical role of sharing the gains from cost controls brought about by
14 managerial incentive compensation between customers and shareholders.
15
16 Q. IS THIS POINT THAT CUSTOMERS BENEFIT FROM MANAGERIAL
17 EFFICIENCY A COMMONLY ACCEPTED TENANT OF UTILITY RATE
18 ECONOMICS?
19 A. Yes. This idea of a win-win scenario, where both shareholders and
20 customers benefit from managerial efficiency, is not new and is a core
21 idea at the heart of well-established principles of regulatory economics.
22 For example, James C. Bonbright discusses it in his seminal 1961 treatise
23 on utility economics, Principles of Public Utility Rates.
2011 ETI Rate Case 5-13
Entergy Texas, Inc. Page 12 of 31
Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 Q. DO THESE PRINCIPLES APPLY TO OTHER FORMS OF INCENTIVE
2 COMPENSATION THAT ARE LINKED TO PROFITABILITY AND STOCK
3 PRICE MEASURES?
4 A. Yes. While I think that cost containment measures are the most obvious
5 example of incentives that have in some past PUCT cases been
6 categorized as "financial" and yet directly benefit customers, these
7 principles apply to other dollar-based or financial measures as well, such
8 as incentive awards tied to corporate profitability and stock prices.
9
10 Q. CAN YOU PLEASE FURTHER ELABORATE ON WHY CUSTOMERS
11 ARE LIKELY TO BENEFIT FROM COMPENSATION THAT IS LINKED
12 TO PROFITABILITY?
13 A. Yes. There is a direct link between cost containment and company
14 earnings, especially for a regulated utility. Managers with an incentive to
15 increase earnings will focus on controlling or cutting costs in a regulated
16 industry because it is more difficult to grow revenues. Additionally, the
17 same type of reasoning that supports a linkage between cost containment
18 and customer benefit also applies to incentive measures that focus on
19 containing capital expenditures. If managers can offer the same service
20 while cutting back on capital expenditures by investing more efficiently,
21 then shareholders benefit due to greater short-run cash flows for the
22 company, and customers benefit through the regulatory process through
23 lower recovery for the cost of capital due to a lower capital base.
2011 ETI Rate Case 5-14
Entergy Texas, Inc. Page 13 of 31
Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 Q. WHAT TYPE OF INCENTIVE COMPENSATION DO YOU INCLUDE
2 WITHIN THE CATEGORY OF COMPENSATION THAT IS LINKED TO
3 STOCK PRICES?
4 A. This category would include most long-term incentive plans (including
5 ETI's) that use performance units that are based on stock prices, as well
6 as stock options.
7
8 Q. CAN YOU BRIEFLY SUMMARIZE WHY YOU BELIEVE THAT
9 COMPENSATION THAT IS LINKED TO STOCK PRICES BENEFITS
10 CUSTOMERS?
11 A. Compensation that is linked to stock prices has several advantages for
12 customers as long as it is part of a reasonable, well-designed
13 compensation plan – in other words, as long as the total level of
14 compensation is reasonable compared to the market for similar positions
15 and the form of compensation is well balanced across dollar-based and
16 non-dollar-based measures. First, compensation that is linked to stock
17 prices helps ensure that managers will consider the financial health of the
18 company when they make decisions, and it is in customers' interests to
19 have the company continue to be financially healthy. Second,
20 stock-based compensation provides an incentive for managers and
21 employees to ensure that the company operates efficiently, and via the
22 regulatory process, lower costs result in lower rates than would otherwise
23 occur. Third, stock-based compensation provides a monitoring
2011 ETI Rate Case 5-15
Entergy Texas, Inc. Page 14 of 31
Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 mechanism for managerial decision making and the overall quality of
2 management. Fourth, there is an interaction between these effects, as the
3 capital markets will tend to reward efficient long-term investments or
4 capital expenditures that will also lead to lower costs for customers.
5
6 Q. DO THESE REASONS THAT COMPENSATION THAT IS LINKED TO
7 STOCK PRICES BENEFITS CUSTOMERS ALSO APPLY TO
8 COMPENSATION THAT IS LINKED TO COST CONTROL AND
9 PROFITABILITY?
10 A. In general, yes. Stock prices are driven in part by cost control and
11 profitability, so to the extent that managers have an incentive to increase
12 the stock price, they will also have an incentive to control costs and
13 increase profits and cash flows, and vice versa. Of the reasons listed in
14 the previous answer, the first two reasons – incentives to ensure that the
15 company is financially healthy and that it operates efficiently – are the
16 ones that are most closely shared by compensation based on cost control
17 and profitability.
2011 ETI Rate Case 5-16
Entergy Texas, Inc. Page 15 of 31
Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 Q. STARTING WITH THE FIRST REASON YOU MENTIONED, WHY DOES
2 COMPENSATION THAT IS LINKED TO PROFITABILITY AND STOCK
3 PRICES BENEFIT CUSTOMERS BY IMPROVING A COMPANY'S
4 FINANCIAL HEALTH?
5 A. If compensation that is linked to profitability and stock prices gives
6 managers an incentive to increase their company's earnings, cash flows,
7 and stock price, then this will also provide them with an incentive to
8 ensure that the company remains financially healthy. Stock prices of firms
9 that are in poor financial condition – for example, that have high debt
10 relative to the value of their assets – tend to be lower, all else being equal.
11 Similarly, firms in poor financial condition tend to have lower earnings and
12 operating cash flows. A stronger financial condition will also benefit
13 customers. If a company maintains a financially healthy position, it will
14 tend to have a lower cost of capital that will in turn benefit customers
15 through lower rates. For a discussion of this effect, see Chapter 15 of
16 Investment Valuation, by Aswath Damodaran.3 In addition, the costs of
17 doing business with suppliers (of both goods and services, including labor)
18 will remain lower. For example, if a company was not in a financially
19 stable condition, suppliers would tend to demand higher prices or more
20 onerous credit terms, resulting in higher costs that would lead to higher
3
ASWATH DAMODARAN, INVESTMENT VALUATION (John Wiley & Sons, 2d ed. 2002).
2011 ETI Rate Case 5-17
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Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 rates than would otherwise occur. These are often termed "indirect costs
2 of financial distress," and are a commonly accepted concept in finance.
3
4 Q. DOES EXISTING EMPIRICAL EVIDENCE SUPPORT THE OPINION
5 THAT FINANCIALLY HEALTHY FIRMS WILL TEND TO FACE LOWER
6 COSTS, WHICH WOULD BENEFIT CUSTOMERS OF A REGULATED
7 UTILITY?
8 A. Yes. There is empirical evidence that firms with lower stock prices (or that
9 are less financially healthy) face higher costs and greater risks. This
10 includes work by researchers who have shown how less financially
11 healthy companies have trouble responding to external shocks, and face
12 higher costs of doing business (through higher wages or worse terms from
13 suppliers, for example).4 These results support the financial-health
14 channel, by which stock-based incentive compensation should provide
15 direct benefits to customers. Stock-based incentive compensation
16 encourages managers to maintain a company's financial health, thus
17 leading to more efficient operations and greater cost control than would
18 otherwise occur.
4
Chris Parsons and Sheridan Titman, Capital Structure and Corporate Strategy (January
2007). The article is available at http://ssrn.com/abstract=983553.
2011 ETI Rate Case 5-18
Entergy Texas, Inc. Page 17 of 31
Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 Q. ARE THERE EXAMPLES OF EXTERNAL SHOCKS IN THE UTILITY
2 INDUSTRY THAT COULD MATERIALLY IMPACT A COMPANY’S
3 FINANCIAL HEALTH?
4 A. One example of a large external shock is a severe storm or hurricane,
5 such as Hurricanes Rita and Ike that, to my understanding, had significant
6 financial impact on Entergy Companies. For example, Hurricane Ike was
7 estimated to cause ETI to incur restoration costs between $435 million
8 and $510 million.5 The ability of a company to absorb such a shock
9 without suffering from costs of distress depends on its financial health
10 (e.g., their stock price, liquidity, and debt capacity). In this way, customers
11 benefit from compensation that provides incentives for management to
12 improve the firm’s financial condition, because such incentives would tend
13 to improve the firm’s ability to withstand sizable negative events such as
14 hurricanes, without incurring excessive additional costs of financial
15 distress.
16
17 Q. CAN YOU FURTHER EXPLAIN HOW INCENTIVE COMPENSATION
18 THAT IS LINKED TO PROFITABILITY AND STOCK PRICES CAN TEND
19 TO LEAD TO LOWER COSTS FOR CUSTOMERS?
20 A. The first step is to understand that compensation linked to profitability and
21 stock prices will provide managers with an incentive to operate efficiently
5
See http://investor.shareholder.com/entergy/releasedetail.cfm?ReleaseID=337564
2011 ETI Rate Case 5-19
Entergy Texas, Inc. Page 18 of 31
Direct Testimony of Jay C. Hartzell, PhD.
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1 because, by doing so, a company's profitability (including earnings and
2 cash flow) and stock price will be higher than it would otherwise be. To
3 increase stock price, management tries to maximize the present value of a
4 company's expected cash flows by minimizing expenses and the cost of
5 capital. The role of incentive compensation in motivating managers to
6 minimize the cost of capital component and the associated benefits to
7 customers were discussed earlier. A second channel provided by
8 incentive compensation that can benefit customers is the incentive to
9 maximize the company's cash flows. In a regulated environment,
10 particularly one in which promotion of sales growth is discouraged, it is
11 likely to be more difficult to increase cash flows or profits by growing
12 revenues, so management will tend to focus on efficient operations and
13 investment.
14 These lower costs will benefit shareholders in the short run, but
15 customers over the long run. This is due to the regulatory process that
16 directly links operating costs to rates.
17
18 Q. DO PUBLISHED EMPIRICAL STUDIES SUPPORT THE OPINION THAT
19 FINANCIAL PERFORMANCE, INCLUDING STOCK PRICE, IS
20 POSITIVELY RELATED TO CUSTOMER SATISFACTION GENERALLY,
21 AND FOR UTILITY FIRMS IN PARTICULAR?
22 A. Yes. There is empirical evidence in the literature that firms with higher
23 market values tend to also have higher customer satisfaction, supporting
2011 ETI Rate Case 5-20
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Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 the conclusion that the goals of financial success and customer
2 satisfaction are interrelated.6 This result has been shown for a broad
3 sample of firms, but also for utilities in particular. This empirical finding is
4 inconsistent with the idea that the most profitable or valuable firms
5 become that way by cutting customer service, and instead suggests that
6 there exists positive feedback between a firm's financial performance
7 (stock price) and customers' welfare, even in the utility industry.
8
9 Q. HOW DOES COMPENSATION THAT IS LINKED TO STOCK PRICES
10 BENEFIT CUSTOMERS VIA THE MONITORING OF MANAGERIAL
11 DECISIONS?
12 A. One of the functions of the stock market and its various participants is to
13 monitor companies' management. In their efforts to properly value stocks,
14 analysts, portfolio managers, and traders follow companies and
15 continually assess the various decisions, announcements, and pieces of
16 information they produce. In doing so, they act as a monitoring device,
17 ensuring that poor decisions would be punished by a falling stock price, so
18 managers have incentives to invest the shareholders' financial resources
19 efficiently. In this manner, managers help keep customers' costs lower
6
Christopher D. Ittner and David F. Larcker, Are Nonfinancial Measures Leading Indicators of
Financial Performance? An Analysis of Customer Satisfaction, 36 JOURNAL OF ACCOUNTING
RESEARCH, Supplement 1998 at 1 – 35.
2011 ETI Rate Case 5-21
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Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 than they might otherwise be in the absence of such monitoring, and
2 improve the overall quality of service.
3
4 Q. DOES PUBLISHED EMPIRICAL EVIDENCE SUPPORT THE OPINION
5 THAT STOCK MARKET PARTICIPANTS MONITOR MANAGERIAL
6 DECISIONS?
7 A. Yes. There are published empirical studies that provide support for my
8 opinion that stock-based incentive compensation provides benefits to
9 customers via the monitoring of managerial decisions. An example of
10 such evidence is a study that shows that institutional investors can help
11 ensure that management does not act myopically to cut research and
12 development expenditures in order to meet short-term earnings targets.7
13 Thus, the presence of stock-based compensation that provides incentives
14 for management to respond to monitoring by stock-market participants
15 and investors can benefit customers by encouraging managers to focus
16 beyond the short term and think about long-term efficient investments.
17
18 Q. HOW DO THESE INVESTMENT AND COST EFFECTS INTERACT DUE
19 TO THE STOCK MARKET?
20 A. An important role for stock-based compensation is to encourage
21 managers to refrain from sacrificing long-run success in pursuit of
7
Brian J. Bushee, The Influence of Institutional Investors on Myopic R&D Investment Behavior,
73 THE ACCOUNTING REVIEW, 3 at 305-333 (July 1998).
2011 ETI Rate Case 5-22
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Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 short-term profit.8 Stock prices are based not just on a company's
2 performance in the current year, but also on the market's expectations
3 about a company's future performance over many years. This ensures
4 that good investments tend to increase stock prices, even though those
5 investments use cash today in order to produce greater cash flows in the
6 future. This is a critical advantage of stock-based compensation over
7 annual incentive plans that are based on a particular year's (or a few
8 years') performance. Stock-based compensation can help overcome
9 managerial myopia and provide managers with an incentive to make
10 efficient, long-term investments that benefit both customers (due to
11 efficient investments that lead to lower costs) and shareholders (due to
12 higher cash flows). In this case, the testimony of Company witnesses
13 Joseph F. Domino and Chris E. Barrilleaux addressing the Company's
14 expected future capital investments, and that of Company witness Robert
15 R. Cooper regarding long-term resource planning, provide examples of
16 such consideration.
8
For example, see M.P. Narayanan, Form of Compensation and Managerial Decision Horizon,
31 JOURNAL OF FINANCIAL AND QUANTITATIVE ANALYSIS, 4 at 467-491 (1996).
2011 ETI Rate Case 5-23
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Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 IV. COSTS TO CUSTOMERS OF DISCOURAGING THE USE OF
2 INCENTIVE COMPENSATION THAT IS LINKED TO COST CONTROL,
3 PROFITABILITY AND STOCK PRICES
4 Q. WHILE YOUR EARLIER TESTIMONY DISCUSSED THE BENEFITS TO
5 CUSTOMERS OF USING INCENTIVE COMPENSATION THAT IS
6 LINKED TO COST CONTROL, PROFITABILITY AND STOCK PRICES,
7 ARE THERE ALSO NEGATIVE IMPACTS TO CUSTOMERS OF NOT
8 USING STOCK-BASED COMPENSATION?
9 A. Yes. In my opinion customers would be adversely affected if ETI did not
10 include such incentive compensation in its overall compensation policy.
11
12 Q. STARTING WITH AN EXTREME EXAMPLE OF A COMPENSATION
13 POLICY WHERE ALL EMPLOYEES WERE ONLY PAID WITH
14 SALARIES, CAN YOU HIGHLIGHT THE IMPACT TO CUSTOMERS OF
15 SUCH A POLICY?
16 A. Yes. First, it is useful to note that if employees did not receive any
17 incentive compensation, salaries would have to be much higher to attract
18 and retain the same quality of talent. Second, costs would likely rise and
19 employee performance would likely suffer, as it would be difficult to
20 effectively and efficiently motivate employees to take actions that would
21 benefit shareholders and customers. In my opinion, customers would be
22 worse off under such a policy. This is supported by the principle that
23 individuals respond to incentives (a basic tenet of economics), and by
2011 ETI Rate Case 5-24
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Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 empirical work that shows workers' output responds to the institution of an
2 incentive plan.9
3
4 Q. WOULD CUSTOMER INTERESTS BE ADVERSELY AFFECTED IF A
5 COMPANY USED SALARY AND INCENTIVES LINKED TO MEASURES
6 THAT HAVE BEEN TERMED "OPERATIONAL" ONLY? IN OTHER
7 WORDS, IF THEY PROVIDED SALARY AND INCENTIVES BASED ON
8 MEASURES LIKE RELIABILITY AND SAFETY, BUT NO INCENTIVES
9 BASED ON COST CONTROL, PROFITABILITY AND STOCK PRICES?
10 A. Yes. I believe customers would be worse off under such a compensation
11 policy. On the one hand, incentives linked to what have been termed
12 "operational" measures can improve customer welfare because the
13 company can better attract, motivate and retain talented employees.
14 Compared to the hypothetical case where a company compensates its
15 employees with salary only, by using salary and incentives linked to, for
16 example, safety or reliability, the company can pay less in salary and use
17 the associated savings to contribute to the annual incentive plans. On the
18 other hand, such a compensation plan still has substantial problems in the
19 context of customer benefits.
20 First, there is still no free lunch. In order for the firm to compete in
21 the market for labor, the level of employees' total compensation – even if it
9
Edward P. Lazear, Performance Pay and Productivity, 90 THE AMERICAN ECONOMIC REVIEW,
at 1346-1361 (December 2000).
2011 ETI Rate Case 5-25
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Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 consisted only of salaries and incentive payments linked to operational
2 incentives – would have to be similar to what the total compensation
3 would be if the firm also offered incentive compensation linked to cost
4 control, profitability and stock prices.
5 Second, such a compensation plan would not provide any
6 incentives for employees and managers to control costs. If employees
7 only had incentives to improve non-cash measures of performance, such
8 as safety and reliability, then they would likely over-invest in these
9 measures relative to what customers might prefer, at the expense of
10 alternative, contemporaneous investments that would produce lower costs
11 for customers.
12 Relatedly, a compensation plan consisting of salary and incentives
13 based solely on annual measures of operational performance could likely
14 lead to "horizon problems." By horizon problems, I mean that managers
15 tend to have a natural tendency, absent incentives, to focus on the short
16 run at the expense of the long run. Stock prices by their nature are
17 forward looking. Taken together, a compensation plan that included
18 incentives based on annual measures such as reliability and customer
19 satisfaction, but not incentives based on cost controls, profitability and
20 especially stock prices, could provide incentives for managers to maximize
2011 ETI Rate Case 5-26
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Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 their immediate compensation at the expense of longer-run benefits that
2 the customer could have enjoyed.10
3 For example, consider a manager facing a decision whether to hire
4 additional staff to answer phones in a call center (and bring down phone
5 wait times) or to invest the same amount in a capital investment to put in
6 place a new, more centralized call center that would produce significantly
7 lower costs several years in the future. If the manager is paid purely in
8 cash compensation including an incentive payment based on current-year
9 customer satisfaction surveys (that would include phone wait times), then
10 the manager would be more likely to forgo the long-term investment
11 project and increase payroll by hiring additional employees in order to
12 maximize his or her incentive pay by implementing the short-term solution
13 today. But, at some point, customers are better off by having slightly
14 longer waits on the phone now but reaping the benefits of lower overall
15 costs in the future. A well-designed compensation plan that includes
16 incentives linked to both customer satisfaction (in this example) and cost
17 control, profitability and stock prices would provide incentives for the
18 manager in this example to properly consider the benefits of such a long-
19 term investment without sacrificing current customer satisfaction.
10
See M.P. Narayanan, Form of Compensation and Managerial Decision Horizon, 31 JOURNAL
OF FINANCIAL AND QUANTITATIVE ANALYSIS, 4 at 467-491 (1996).
2011 ETI Rate Case 5-27
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Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 Q. IS THERE PUBLISHED EMPIRICAL EVIDENCE THAT SUPPORTS THE
2 OPINION THAT COMPENSATION BASED ON STOCK PRICE COULD
3 CURTAIL SUCH EXCESSIVE SHORT-TERM INVESTMENTS?
4 A. Yes. Empirical evidence exists that some firms hurt their financial
5 performance (stock price) by overinvesting in customer service.11 This
6 result suggests that including stock price in the compensation plan will
7 help ensure against myopic investments in short-term service that would
8 come at the expense of investments that would produce greater long-term
9 benefits to customers. It also points toward the conclusion that basing
10 incentive compensation for purposes of setting rates solely on operational
11 goals could well be harmful to customers' interests in the long run.
12
13 Q. HOW DOES THE INCLUSION OF INCENTIVE COMPENSATION THAT
14 IS LINKED TO COST CONTROLS, PROFITABILITY AND STOCK
15 PRICES HELP AVOID THESE NEGATIVE OUTCOMES FOR
16 CUSTOMERS?
17 A. If a company adds compensation that is linked to cost controls,
18 profitability, and stock prices to a compensation plan that includes base
19 salary and incentives based on non-cash based measures in a reasonable
20 way, customers are likely to be better off. Such incentive compensation
11
Christopher D. Ittner and David F. Larcker, Are Nonfinancial Measures Leading Indicators of
Financial Performance? An Analysis of Customer Satisfaction, 36 JOURNAL OF ACCOUNTING
RESEARCH, Supplement 1998 at 1 – 35.
2011 ETI Rate Case 5-28
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Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 helps a company attract, motivate, and retain talented employees and
2 gives managers a reason to focus on the long run in addition to the current
3 year's performance, costs, customer service, and the like.
4 This focus on the longer run is evident in the design of ETI's LTIP,
5 stock option and restricted stock plans. For example, ETI's LTIP bases its
6 payments in a particular year on the achievement of goals over the
7 previous three years, encouraging managers to consider consistent and
8 long-term success as key objectives. Plus, options granted vest over a
9 three-year period, forcing managers to think about future years and how
10 the firm will be viewed several years into the future. The stock options
11 also have a life of ten years, which provides an additional incentive to
12 focus on the long term. Such a focus on maximizing stock price over a
13 ten-year period is beneficial for all stakeholders. As stock options may be
14 awarded annually, option grants present a rolling ten-year window for
15 those employees who receive them, reinforcing that long-term view.
16 Similar to stock options, restricted stock is also awarded annually and
17 vests over a three-year period. The fact that the ultimate value realized
18 from restricted stock grants (once they vest) depends on the stock price at
19 that time again provides a focus on maximizing stock price which is likely
20 to be of benefit to all stakeholders for the reasons discussed above.
21 Finally, the provision that requires senior managers to continue to hold
22 stock received via exercising option grants or through the vesting of
23 restricted stock up to a multiple of their salary further encourages longer-
2011 ETI Rate Case 5-29
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Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 run thinking and incentive alignment, as senior managers cannot exercise
2 all their options for cash or cash out their restricted stock positions and be
3 immune to declines in the firm's financial health.
4
5 V. RESPONSE TO COMMON ARGUMENTS AGAINST INCENTIVE
6 COMPENSATION LINKED TO COST CONTROL, PROFITABILITY AND
7 STOCK PRICES FROM THE CUSTOMERS' PERSPECTIVE
8 Q. HOW DO YOU RESPOND TO THE ARGUMENT THAT INCENTIVE
9 COMPENSATION THAT IS LINKED TO COST CONTROL,
10 PROFITABILITY, AND STOCK PRICES WILL BE DETRIMENTAL TO
11 CUSTOMERS BECAUSE IT WILL CAUSE MANAGERS TO CUT
12 CUSTOMER SERVICE-RELATED EXPENSES TO INCREASE
13 PROFITS?
14 A. This argument underscores the importance of a well-balanced
15 compensation plan. By including both incentives based on non-dollar
16 based measures such as customer service, reliability and safety, and
17 incentives based on cost control, profitability and stock price, as does ETI,
18 management will not want to cut one in order to increase the other, but will
19 instead look for balanced decisions that help both.
2011 ETI Rate Case 5-30
Entergy Texas, Inc. Page 29 of 31
Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 Q. IS THERE EMPIRICAL EVIDENCE THAT THE ADOPTION OF
2 INCENTIVE COMPENSATION WITH TARGETS BASED ON STOCK OR
3 EARNINGS PERFORMANCE BENEFITS CUSTOMERS RATHER THAN
4 HARMS THEM?
5 A. Yes. There is a published study that examines the adoption of long-term
6 incentive plans that reward managers with stock or stock-based
7 compensation, where the stock grants are based on long-run profitability.12
8 The study finds that after the adoption of such plans, managerial
9 compensation is more closely linked to the interests of managers and
10 stakeholders, including customers. This is also consistent with the studies
11 I discuss above in my testimony, such as one that links market value with
12 customer satisfaction.
13 Another published study examines the impact of an incentive plan
14 on the performance of a particular regulated utility.13 This study compared
15 the performance of two divisions within the utility company – one that
16 added an incentive compensation plan with payouts based on financial
17 measures such as sales, costs, and investments, plus employee
18 absenteeism, and a second division that served as a control group
19 because it did not take part in the incentive plan. The authors found for
12
Alka Arora and Pervaiz Alam, CEO Compensation and Stakeholders’ Claims,
22 CONTEMPORARY ACCOUNTING RESEARCH, 3 at 519-547 (Fall 2005).
13
M.M. Petty, Bart Singleton, and David W. Connell, An Experimental Evaluation of an
Organizational Incentive Plan in the Electric Utility Industry, 77 JOURNAL OF APPLIED
PSYCHOLOGY, 4 at 427-436 (1992).
2011 ETI Rate Case 5-31
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Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 the division that added the incentive plan, performance was significantly
2 better along several dimensions, including operational measures (e.g.,
3 reliability) and employee health and safety. This evidence is particularly
4 relevant in that it demonstrates a link between the adoption of an incentive
5 compensation plan with payouts based on financial performance metrics
6 and positive changes in a much broader set of stakeholder measures.
7
8 Q. IS THERE REASON TO BE CONCERNED FROM THE CUSTOMERS'
9 PERSPECTIVE BECAUSE STOCK PRICES AND PROFITS ARE
10 DRIVEN BY MANY OTHER FACTORS IN ADDITION TO COST
11 CONTROLS, OR HAVING A LOW COST OF CAPITAL?
12 A. No. Avoiding this concern is why firms generally do not use compensation
13 plans that consist solely of stock- or profit-based incentive pay – to do so
14 would be too risky for the employees and would lead to larger overall
15 compensation expense because risk-averse individuals would demand
16 higher compensation levels in order to compensate them for bearing the
17 risk of such a hypothetical plan. This is also why stock- and profit-based
18 incentive compensation is more important at the top of the organization.
19 Senior management can more clearly see (and anticipate) the impact of
20 their actions on the firm's stock price, so stock-based compensation is a
21 more efficient compensation tool for this level of management.
2011 ETI Rate Case 5-32
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Direct Testimony of Jay C. Hartzell, PhD.
2011 Rate Case
1 VI. CONCLUSION
2 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
3 A. Yes, at this time.
2011 ETI Rate Case 5-33
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2011 ETI Rate Case 5-34
Exhibit JCH-1
2011 TX Rate Case
Page 1 of 7
Jay C. Hartzell
Department of Finance
McCombs School of Business
The University of Texas at Austin
1 University Station B6600
Austin, TX 78712
(512) 471-6779; jhartzell@mail.utexas.edu
Academic Positions Held
McCombs School of Business, The University of Texas at Austin
Professor of Finance 2011 to present
Chair, Department of Finance 2011 to present
Allied Bancshares Centennial Fellow in Finance 2008 to present
Executive Director, Real Estate Finance and Investment Center (REFIC) 2007 to present
Associate Professor of Finance 2006 to 2011
Associate Director, REFIC 2005 to 2007
Assistant Professor of Finance 2001 to 2006
Stern School of Business, New York University
Assistant Professor of Finance 1998 to 2001
Education
Ph.D. in Finance, The University of Texas at Austin, 1998
Minors: Real Estate, Economics.
B.S. in Business Administration and Economics, Trinity University, 1991
Graduated Cum Laude. National Merit Scholar.
Publications
“Incentive Compensation and the Likelihood of Termination: Theory and Evidence from Real Estate
Organizations” with Greg Hallman and Chris Parsons. 2011. Real Estate Economics 39, 507-546.
“Is a Higher Calling Enough? Incentive Compensation in the Church” with Chris Parsons and
David Yermack. 2010. Journal of Labor Economics 28, 509-539.
“Alternative Benchmarks for Evaluating Mutual Fund Performance” with Tobias M¨
uhlhofer and
Sheridan Titman. 2010. Real Estate Economics 38, 121-154.
“Explicit vs. Implicit Contracts: Evidence from CEO Employment Agreements” with Stuart Gillan
and Robert Parrino. 2009. Journal of Finance 64, 1629-1655.
“The Role of Corporate Governance in Initial Public Offerings: Evidence from Real Estate Invest-
ment Trusts” with Jarl Kallberg and Crocker Liu. 2008. Journal of Law and Economics 51, 539-562.
“Why Do Firms Hold So Much Cash? A Tax-Based Explanation” with Fritz Foley, Sheridan Titman
and Garry Twite. 2007. Journal of Financial Economics 86, 579-607 (Lead article).
1
2011 ETI Rate Case 5-35
Exhibit JCH-1
2011 TX Rate Case
Page 2 of 7
“The Effect of Corporate Governance on Investment: Evidence from Real Estate Investment Trusts”
with Libo Sun and Sheridan Titman. 2006. Real Estate Economics 34, 343-376 (Lead article).
Winner of the 2006 Edwin S. Mills Real Estate Economics Best Paper Award.
“Active Institutional Shareholders and Costs of Monitoring: Evidence from Executive Compen-
sation” with Andres Almazan and Laura T. Starks. 2005. Financial Management 34(4), 5-34 (Lead
article).
“The Impact of CEO Turnover on Equity Volatility” with Matthew J. Clayton and Joshua Rosen-
berg. 2005. Journal of Business 78, 1779-1808.
“The Role of the Underlying Real Asset Market in REIT IPOs” with Jarl G. Kallberg and Crocker
H. Liu. 2005. Real Estate Economics 33, 27-50.
“What’s In It For Me? Private Benefits Obtained by CEOs Whose Companies are Acquired” with
Eli Ofek and David Yermack. 2004. Review of Financial Studies 17, 37-61.
“Institutional Investors and Executive Compensation” with Laura T. Starks. 2003. Journal of
Finance 58, 2351-2374.
“Market Reaction to Public Information: The Atypical Case of the Boston Celtics” with Gregory
W. Brown. 2001. Journal of Financial Economics 60, 333-370.
Research Papers
“On the Optimality of Shareholder Control: Evidence from the Dodd-Frank Financial Reform Act”
with Jonathan Cohn and Stuart Gillan.
“Is There a Disposition Effect in Corporate Investment Decisions? Evidence from Real Estate
Investment Trusts” with Alan Crane.
“Trade-offs in Corporate Governance: Evidence from Board Structures and Charter Provisions”
with Stuart Gillan and Laura Starks.
“Institutional Investors as Monitors of Corporate Diversification Decisions: Evidence from Real
Estate Investment Trusts” with Libo Sun and Sheridan Titman.
Professional and Academic Activities and Service
Associate Editor, Review of Financial Studies, 2009-present.
Editorial Board, Real Estate Economics, 2007-present.
American Real Estate and Urban Economics Association (AREUEA), Board of Direc-
tors, 2009-present. Member, 1998-present.
Urban Land Institute. Advisory Board (previously known as Executive Committee), Austin
District Council, 2010-present. Member, Industrial & Office Park Development Council (Gold),
2009-present. Full member, 2008-present.
2
2011 ETI Rate Case 5-36
Exhibit JCH-1
2011 TX Rate Case
Page 3 of 7
National Council of Real Estate Investment Fiduciaries. Data Products Council, 2009.
Member, 2008-present.
Financial Management Association. Track chair, real estate, annual meeting, 2007. Program
committee, European meeting, 2006. Program committee, annual meeting, 2004, 2005. Corporate
finance awards committee, annual meeting, 2003. Member, 1998-present.
Western Finance Association. Program committee, annual meeting, 2006, 2010, 2011. Member,
1998-present.
Conference on Financial Economics and Accounting. Co-organizer, Finance, 19th Annual
Meeting, 2008.
American Finance Association. Member, 1998-present.
Ad Hoc Referee for the following journals:
The Accounting Review; American Economic Review; Financial Management; International Jour-
nal of Managerial Finance; International Journal of Manpower; International Review of Finance;
Journal of Banking and Finance; Journal of Corporate Finance; Journal of Economics, Manage-
ment, and Strategy; Journal of Economic Behavior and Organization; Journal of Finance; Journal
of Financial and Quantitative Analysis; Journal of Financial Economics; Journal of Financial In-
termediation; Journal of Financial Markets, Instruments and Institutions; Journal of Institutional
and Theoretical Economics; Journal of Law, Economics, and Organizations; Journal of Real Estate
Research; Journal of Risk and Insurance; Journal of Urban Economics; Management Science; Public
Finance Review; Quarterly Review of Economics and Finance; Real Estate Economics; Review of
Economic Studies; Review of Financial Studies.
Service for the University of Texas at Austin
Executive Director, Real Estate Finance and Investment Center (REFIC), 2007-present.
Associate Director, REFIC, 2005-2007.
Member, Finance Department Executive Committee, 2006-present.
Member, Graduate Assembly (University wide), 2009-present.
Member, Finance Department PhD Committee, 2003-present.
Member, University Outstanding Graduate Thesis Award Committee, 2010.
Guest speaker, MBA Alumni Network, El Paso, 2010; Seattle and Austin, 2009.
Guest speaker, UT LAMP program, 2009.
Speaker on Real Estate Valuation, VALCON 2009, Co-sponsored by UT School of Law.
Member, Planning Committee, 2009 Mortgage Lending Institute, Sponsored by UT School of Law.
Speaker, 2009 Mortgage Lending Institute (Austin and Dallas), Sponsored by UT School of Law.
Guest speaker, Austin Bar Association Real Estate Section meeting, 2010.
Speaker, 2009 Land Use Conference, Sponsored by UT School of Law.
Judge, MBA Finance Tournament, 2001-2006, 2008-2009.
Assistant Graduate Advisor and Minority Liaison, Finance Department, 2005-2008.
Member, McCombs Option I Policy Committee, 2006-2008.
Panel Chair, IC 2 Conference on Corporate Governance in Early-Stage Companies, 2005, 2006.
Member, Plus Program Committee, 2003-2005.
Judge, MBA Consulting Challenge, 2002, 2003, 2004.
Member, MBA Scholarship Committee, 2002.
PhD Dissertation Committees
UT-Austin: Jennifer Brown (accounting), Alan Crane (co-chair), Ayla Kayhan, Andreas Lawson,
Jie Lian, Andras Marosi, Bill Mayew (accounting), Thomas Moeller, Carlos Molina, Saumya Mo-
han (co-chair), Chris Parsons (co-chair), Lorenzo Preve, Casey Schwab (accounting), Zekiye Selvili,
Nate Sharp (accounting), Stephanie Sikes (accounting), Libo Sun (co-chair), Vahap Uysal, Malcolm
3
2011 ETI Rate Case 5-37
Exhibit JCH-1
2011 TX Rate Case
Page 4 of 7
Wardlaw, Peggy Weber (accounting), Li Yong.
NYU: Eliezer Fich (economics), Charu Raheja, Jayanthi Sunder.
Academic Presentations (includes presentations made by co-authors at major conferences)
2011
Indian School of Business Summer Research Conference, National Bureau of Economic Research
(NBER) Program on Law and Economics, Society for Financial Studies Finance Cavalcade, Univer-
sity of Michigan.
2010
American Real Estate and Urban Economics Association (AREUEA) annual meeting, Homer Hoyt
Institute/Weimer School of Advanced Studies in Real Estate and Land Economics Spring Confer-
ence, UC-Irvine Commercial Real Estate Academic Symposium, Indiana University, University of
Colorado at Boulder, University of Florida.
2009
AREUEA annual meeting, Association for the Study of Religion Economics and Culture (ASREC)
annual meeting, National Bureau of Economic Research (NBER) Economics of Religion conference,
Western Finance Association (WFA) annual meeting, National University of Singapore, Ohio State
University, Singapore Management University, University of Alabama, University of Cincinnati, Uni-
versity of Washington.
2008
AREUEA annual meeting, Real Estate Research Institute (RERI) Conference, McGill University,
University of California - Los Angeles.
2007
American Finance Association (AFA) annual meeting, Hong Kong University of Science and Technol-
ogy Symposium, Real Estate Research Institute (RERI) Conference, Australian National University,
Baylor University, Penn State University, Texas Tech University, University of California - Berkeley,
University of Delaware, University of Oklahoma, University of South Florida.
2006
AFA annual meeting (two papers), University of Texas at Dallas.
2005
AREUEA annual meeting, NBER Corporate Governance meeting, Ohio State University, Penn State
University, Southern Methodist University, University of North Carolina at Chapel Hill Tax Sym-
posium, University of Texas at San Antonio.
2004
Association of Financial Economists (AFE) annual meeting, AREUEA annual meeting, Financial
Management Association (FMA) annual meeting, NBER Summer Institute: Corporate Governance
Workshop, College of William and Mary.
2003
AFA annual meeting, AREUEA/AFA joint session at annual meeting, University of British Columbia,
University of Delaware Corporate Governance Symposium, University of Minnesota, University of
North Carolina at Chapel Hill, WFA annual meeting.
2002
Babson College, Oklahoma State University, University of Oklahoma, Real Estate Research Confer-
4
2011 ETI Rate Case 5-38
Exhibit JCH-1
2011 TX Rate Case
Page 5 of 7
ence (Vail, CO), University of Southern California.
2001
Arizona State University, University of Oregon.
2000
Dartmouth Center for Corporate Governance/Journal of Financial Economics (JFE) Conference
on Contemporary Governance Issues, Marquette University, NYU-Columbia Joint Seminar, South-
ern Methodist University, University of Illinois at Urbana-Champaign, University of Texas at Austin.
1999
AFA annual meeting, Harvard Business School/JFE Conference on Complementary Research Method-
ologies.
1998
AFA annual meeting, FMA annual meeting, University of Alberta, University of Florida, Georgia
State University, University of Michigan Ann Arbor, New York University, University of North Car-
olina Chapel Hill, Penn State University, Rice University, Southern Methodist University, Stanford
University, and Tulane University.
1997
FMA annual meeting.
Other Participation in Academic Conferences
Discussant
AFA annual meeting, 2002, 2009, 2010.
AFA / AFE joint session at annual meeting, 2003.
AFE annual meeting, 1999, 2007.
AREUEA annual meeting, 1999, 2000, 2004, 2007, 2008.
AREUEA mid-year meeting, 2009, 2010.
Conference, Financial Economics and Accounting, 1999.
Financial Research Association, 2010.
FMA annual meeting, 1999, 2002, 2003, 2004, 2006.
FMA annual meeting – Tutorial on empirical methodology, 2009.
FMA annual meeting – Panel discussion, 2008.
Mitsui Symposium at the University of Michigan, 2005.
Real Estate Research Institute Conference, 2011.
Texas Finance Festival, 2000, 2007.
WFA annual meeting, 2001, 2010, 2011.
Session Chair
AREUEA annual meeting, 2010.
AREUEA mid-year meeting, 2009.
FMA annual meeting, 2004, 2005.
WFA annual meeting, 2006, 2010.
Teaching Experience
The University of Texas at Austin
Current PhD Course: Empirical Corporate Finance. Doctoral course in research methodology and
5
2011 ETI Rate Case 5-39
Exhibit JCH-1
2011 TX Rate Case
Page 6 of 7
topics.
Current MBA courses: Real Estate Markets. Elective in real estate asset and capital markets. Fi-
nancial Management. Core MBA course, Houston MBA program.
Current BBA course: Real Estate Finance and Syndication. Elective in real estate capital mar-
kets.
Previous courses: Financial Management. Core MBA course, also taught in UT’s Executive MBA
and Professional MBA programs. Real Estate Analysis. MBA elective in real estate debt markets.
Seminar in Real Estate Finance. MBA elective in real estate equity markets. Business Finance.
Undergraduate required course.
Teaching honors and awards: Twice voted the “Outstanding Core Instructor” by graduating MBA
classes. Named to the Honor Roll for teaching for both the MBA and Executive MBA programs.
New York University
Taught Corporate Finance and Corporate Finance Topics. MBA elective and undergraduate elec-
tive, respectively.
Honors and Awards
Best Paper Award, Indian School of Business Summer Research Conference, 2011.
Outstanding Editorial Board Member, Real Estate Economics, 2010.
Post Doctoral Award, Weimer School of Advanced Studies in Real Estate and Land Economics,
Homer Hoyt Institute, 2010.
Real Estate Research Institute (RERI) Grant Recipient (with Alan Crane), 2007.
RERI Grant Recipient (with Tobias M¨ uhlhofer and Sheridan Titman), 2006.
CBA Foundation Research Excellence Award for Assistant Professors, 2006. (Finance Department
nominee, 2003, 2005.)
Finance Department nominee for Assistant Professor Teaching Award, 2003, 2004.
University Preemptive Fellowship, UT-Austin, 1993-1995.
University Continuing Fellowship, UT-Austin, 1995-1997.
Austin Mortgage Bankers Association Scholarship, 1995.
Lola Wright Foundation Scholarship, 1995-1997.
Non-Academic Experience
Consulting practice, Austin, Texas.
Expert witness and financial consulting. 2007 to present
Provided expert witness testimony and served as a consulting expert. Retained as expert witness in
multiple cases involving real estate transactions, valuation, contracting issues and market conditions.
Experience includes depositions and testimony on multiple occasions. Retained as expert witness for
several cases regarding incentive compensation for regulated utilities. Retained as consulting expert
by multiple clients for matters involving corporate governance, valuation, and mortgage issues (com-
mercial and subprime). Deposed in matter before Superior Court of the State of California (trial
pending). Provided (written and oral) testimony and was deposed on behalf of Entergy Louisiana
LLC (Docket No. U-20925), 2008. Provided (written and oral) testimony on behalf of Entergy Gulf
States, Inc. (Docket No. 34800), 2008. Provided written testimony on behalf of Entergy Arkansas,
Inc. (Docket No. 09-084-U), 2009. Provided written testimony on behalf of Entergy Texas, Inc.
(Docket No. 37744), 2010.
6
2011 ETI Rate Case 5-40
Exhibit JCH-1
2011 TX Rate Case
Page 7 of 7
Hewitt Associates, The Woodlands, Texas.
Benefits Consultant. 1991 to 1993
Consulted with clients on administration and ongoing design of defined contribution retirement
plans. Earned Certified Employee Benefits Specialist (CEBS) designation.
Lola Wright Foundation, Austin, Texas.
Investment Performance Consultant. 1995 to 1997
While in graduate school, analyzed performance of foundation’s investment managers.
References
Furnished upon request.
7
2011 ETI Rate Case 5-41
This page has been intentionally left blank.
2011 ETI Rate Case 5-42
SOAH Docket No. XXX-XX-XXXX
PUC Docket No. 39896
ETI 2011 Rate Case
ETI EXHIBIT NO. 36
DOCKET NO. 39896
APPLICATION OF ENTERGY § PUBLIC UTILITY COMMISSION
TEXAS, INC. FOR AUTHORITY §
TO CHANGE RATES AND § OF TEXAS
RECONCILE FUEL COSTS §
DIRECT TESTIMONY
OF
KEVIN G. GARDNER
ON BEHALF OF
ENTERGY TEXAS, INC.
November 2011
2011 ETI Rate Case 8-149
Entergy Texas, Inc. Page 29 of 77
Direct Testimony of Kevin G. Gardner
2011 Rate Case
1 and restricted stock awards to be at market, I conclude that the actual
2 level of stock option and restricted awards for the Test Year is reasonable.
3
4 Q. WHAT CONCLUSION DO YOU DRAW FROM THIS ANALYSIS OF THE
5 ENTERGY COMPANIES’ COMPENSATION VERSUS THE MARKET?
6 A. The Entergy Companies establish compensation targets that reflect the
7 market median for individual components and in the aggregate. The
8 design of the compensation program is reasonable and that design
9 yielded a reasonable combination of base pay, annual incentive
10 compensation, and long-term incentive compensation during the Test
11 Year.
12
13 6. Commission Precedent Regarding Financially Based Incentive
14 Compensation
15 Q. ARE YOU AWARE OF COMMISSION PRECEDENT THAT HAS
16 DISALLOWED FINANCIALLY BASED INCENTIVE COMPENSATION?
17 A. Yes. I have been informed by counsel that what the Commission has
18 termed financially based incentive compensation has been disallowed in
19 several recent rate cases in Texas.
2011 ETI Rate Case 8-181
Entergy Texas, Inc. Page 30 of 77
Direct Testimony of Kevin G. Gardner
2011 Rate Case
1 Q. IS A PORTION OF THE INCENTIVE COMPENSATION REQUESTED BY
2 THE COMPANY IN THIS CASE TIED TO ITS PROFITABILITY AND
3 STOCK PRICE?
4 A. Yes. Based on the methodology used to divide annual incentive pay
5 between financial and operational measures utilized by the utility (and
6 accepted by the Commission Staff) in PUCT Docket Nos. 34800 and
7 37744, approximately 14.1 % of ES l's annual incentive compensation is
8 tied to financial measures such as profitability and stock price. See
9 Exhibit KGG-4. In addition, all of the equity-based long-term incentive
10 compensation programs I describe above are tied to such financial
11 measures. On the other hand, none of the costs of the ML 6 Operational
12 Incentive Plan are tied to financial measures of profitability or stock price.
13
14 Q. IN LIGHT OF THE PRECEDENT YOU DESCRIBE ABOVE, WHY IS ETI
15 REQUESTING RECOVERY OF TEST YEAR COMPENSATION COSTS
16 RELATED TO FINANCIALLY BASED MEASURES?
17 A. Pilst, I a111 infem:ied by crnmsel tba.Ltt:ie-eom~TirCeaent ,.Wii'ig'""
18 financially based incentives is not required by statute or--~nd that the
19 Commission retains the authority to c~L course. The facts
20 and evidence presented are diff r-El'1lfin each case, and the Commission
21 should continue to c. n 1der whether incentive programs, such as the
22 scribe above, deserve to be divided into its subparts and, in
23 The operational and financial goals of the Entergy
2011 ET! Rate Case 8-182
Entergy Texas, Inc. Page 31of77
Direct Testimony of Kevin G. Gardner
2011 Rate Case
1 Companies' incentive plans are intertwined such that operational
2 measures help the Entergy Companies achieve financial success and the
3 financial measures help the Entergy Companies achieve operational
4 success.
5 Incentive compensation based on financial metrics is a reasonable,
6 necessary, and common component of compensation for companies like
7 the Entergy Companies, including ETI. Such incentive compensation is a
8 part of the compensation programs of substantially all of ETl's peer
9 companies. It is a market necessity that ETI include such pay in its
10 compensation package so that it can hire and retain talented employees,
11 and customers benefit from a utility that offers compensation that attracts
12 and keeps qualified people.
13 Further, Co111pa11y witness Jay C. I la1 tzell ide11tifies-emz·-
14 studies not previously considered by the Commission tha/ nect
15 financially based incentive compensation to benefits for cupefliers. As he
16 testifies, encouraging the financial health of thezom~is in customers'
17 interests because if a company maintains a y cially healthy position, it
18 will tend to have a lower cost of cap~ttfut will in turn benefit customers
19 through lower rates, andzhe
fi ar;cially healthy company will be more
20 prepared for emerz ents such as storms. Mr. Hartzell also explains
21 that, withz1nanc·I health, the costs of doing business with suppliers (of
22 both go s and services, including labor) will remain lower because, for
23
20 II ET! Rate Case 8-183
Entergy Texas, Inc. Page 32 of 77
Direct Testimony of Kevin G. Gardner
2011 Rate Case
2 resulting in higher costs that wou -te-hi er rates than would
3
4 Additionally, disallowing financial-based performance targets only
5 serves to encourage utilities to eliminate them, and such an approach
6 weakens the alignment of employees' financial interests with the interest
7 of the ratepayers in having an efficiently run and financially healthy utility.
8 Having only operational targets could encourage utilities to overspend in
9 some areas and would result in an incomplete, unbalanced incentive
10 program that would be atypical when compared with American industry in
11 general and does not create a reasonable mix of incentives.
12 Further, to the extent that the total compensation levels are within
13 market range, it should be at the reasonable discretion of the Entergy
14 Companies to determine how best to pay their employees, and it is
15 common practice for a company to emphasize one form of compensation
16 over another form depending on its circumstances. It would not be
17 appropriate to conclude that, for example, all of the compensation paid to
18 ETI employees is reasonable, so long as it is all paid in the form of base
19 salary, but that it becomes unreasonable when that same level is partially
20 paid out in the form of incentive pay.
21 Finally, the Commission should also reconsider its precedent
22 regarding incentive compensation tied to financial performance because
23 increasing company profitability is a legitimate end for public utilities.
20 II ET! Rate Case 8-184
Entergy Texas, Inc. Page 33 of 77
Direct Testimony of Kevin G. Gardner
2011 Rate Case
1 Investor-owned utilities are authorized by statute to earn a reasonable
2 return on invested capital, and thus trying to achieve financial targets that
3 support the utility’s ability to achieve the authorized return is properly
4 viewed as a legitimate performance goal for a regulated utility. Utilities are
5 allowed and expected to operate at a profit. It is not reasonable to
6 disallow such expenditures as per se unreasonable simply because they
7 are tied to company profitability.
8
9 C. Benefit Plans
10 1. Description of the Entergy Companies’ Benefit Plans
11 Q. PLEASE DESCRIBE THE BENEFIT PLANS PROVIDED BY THE
12 ENTERGY COMPANIES TO THEIR EMPLOYEES.
13 A. The benefit plans consist of: (1) medical and dental plans; (2) employee
14 disability insurance; (3) employee life insurance as well as accidental
15 death and dismemberment insurance; (4) retirement plans, consisting of
16 both a defined benefit pension plan and a 401(k) Savings Plan; and (5)
17 Executive Retirement Benefit Programs.
18 The costs of providing many of these programs are shared between
19 the Entergy Companies and their employees. The cost sharing allows the
20 Entergy Companies to provide competitive benefits programs to
21 employees while maintaining total compensation costs that were
22 comparable with industry medians.
2011 ETI Rate Case 8-185
SOAH Docket No. XXX-XX-XXXX
PUC Docket No. 39896
ETI 2011 Rate Case
ETI EXHIBIT NO. 41
DOCKET NO. 39896
APPLICATION OF ENTERGY § PUBLIC UTILITY COMMISSION
TEXAS, INC. FOR AUTHORITY §
TO CHANGE RATES AND § OF TEXAS
RECONCILE FUEL COSTS §
DIRECT TESTIMONY
OF
STEPHANIE B. TUMMINELLO
ON BEHALF OF
ENTERGY TEXAS, INC.
NOVEMBER 2011
2011 ETI Rate Case 9-341
ENTERGY TEXAS, INC.
DIRECT TESTIMONY OF STEPHANIE B. TUMMINELLO
2011 RATE CASE
TABLE OF CONTENTS
Page
I. Name and Qualifications 1
II. Introduction 3
III. Background Information Regarding Entergy Corporation and its
Subsidiaries 8
IV. Affiliate Transaction Regulation 15
V. Affiliate Case Layout 25
VI. The Affiliate Billing Process 41
VII. ESI Service Billings 44
A. Overview of the ESI Billing Process 44
B. Summary of ESI Billings to Affiliated Companies 55
C. Billing Methods 57
1. Billing Method Overview 57
2. Billing Method Calculations 64
D. Service Company Recipient Allocation (also referred to as
Shared Services Loader) 65
E. Payroll Loaders 70
VIII. Other Affiliate Billings 73
IX. Sponsored Classes of Affiliate Costs 74
A. Overview 74
B. Depreciation Class 76
1. Description of Class 76
2011 ETI Rate Case 9-342
2. Necessity 79
3. Reasonableness 81
4. How Costs are Charged 84
C. Service Company Recipient Offsets (also referred to as
Shared Services Loader Offsets) 86
1. Description of Class 86
D. Other Expenses Class 87
1. Description of Class 87
2. Necessity 91
3. Reasonableness 92
4. How Costs are Charged 92
X. Sponsored Affiliate Pro Forma Adjustments 93
XI. Benchmarking of ESI COsts 94
XII. Conclusion 98
2011 ETI Rate Case 9-343
EXHIBITS
Exhibit SBT-A Affiliate Billings – by Witness, Class and Department
Exhibit SBT-A.1 Roadmap to Exhibit SBT-A
Exhibit SBT-B Affiliate Billings – by Witness, Class and Project
Exhibit SBT-B.1 Roadmap to Exhibit SBT-B
Exhibit SBT-C Affiliate Billings – by Witness, Class, Department and Project
Exhibit SBT-C.1 Roadmap to Exhibit SBT-C
Exhibit SBT-D Affiliate Billings – Pro Forma Summary – by Witness, Class
and Pro Forma
Exhibit SBT-D.1 Roadmap to Exhibit SBT-D
Exhibit SBT-E Project Summaries
Exhibit SBT-F Electronic Format of SBT Exhibits and Workpapers on
Compact Disc
Exhibit SBT-1 Professional Work Experience
Exhibit SBT-2 Entergy System Subsidiaries Discussion
Exhibit SBT-3 Regulated/Non-Regulated Affiliate Organization Charts
Exhibit SBT-4A Service Agreement Between ESI and Entergy Texas, Inc.
Exhibit SBT-4B Service Agreement Between ESI and Entergy Arkansas
Exhibit SBT-4C Service Agreement Between ESI and EGS Holdings, Inc.
Exhibit SBT-4D Service Agreement Between ESI and Entergy Gulf States
Louisiana
Exhibit SBT-4E Service Agreement Between ESI and Entergy Louisiana
Holdings, Inc.
Exhibit SBT-4F Service Agreement Between ESI and Entergy Louisiana
Exhibit SBT-4G Service Agreement Between ESI and Entergy Louisiana
Properties, LLC
2011 ETI Rate Case 9-344
Exhibit SBT-4H Service Agreement Between ESI and Entergy Mississippi
Exhibit SBT-4I Service Agreement Between ESI and Entergy New Orleans
Exhibit SBT-4J Service Agreement Between ESI and Entergy Corporation
Exhibit SBT-4K Service Agreement Between ESI and Entergy Operations
Exhibit SBT-4L Service Agreement Between ESI and Entergy Power
Exhibit SBT-4M Service Agreement Between ESI and Entergy Enterprises
Exhibit SBT-4N Service Agreement Between ESI and System Fuels
Exhibit SBT-4O Service Agreement Between ESI and System Energy
Exhibit SBT-4P Service Agreement Between ESI and Entergy New Nuclear
Utility Development, LLC
Exhibit SBT-5 Functions and Classes
Exhibit SBT-6 Families and Functions
Exhibit SBT-7 Affiliates That Receive Services from ESI
Exhibit SBT-8 ESI Test Year Per Book Billings to Affiliates by Project
Exhibit SBT-9 ESI Annual Billings to Affiliates 2008 – 2010
Exhibit SBT-10A FERC Order Accepting Entergy’s Service Company Cost
Allocation Request
Exhibit SBT-10B FERC Order Accepting ESI’s October 28, 2010 Filing
Request
Exhibit SBT-11 Affiliate Billing Exclusions by Class
Exhibit SBT-12 Pro Forma Documentation List
Exhibit SBT-13 Flow of Test Year Affiliate Costs – G-6 Schedules and
Supporting Information
Exhibit SBT-14 Elements of ETI’s Cost of Service
Exhibit SBT-15 Affiliate Billing Process Discussion
2011 ETI Rate Case 9-345
Exhibit SBT-16 ESI Time and Expense Training
Exhibit SBT-17 Direct vs. Allocated ESI Test Year Per Book Billings to
Affiliates
Exhibit SBT-18 Definition of Terms – Direct, Indirect, Allocated, and
Overhead
Exhibit SBT-19 ESI Billing Methods – Basis for Calculation and Types of
Costs Allocated Using Billing Methods
Exhibit SBT-20 Entergy Arkansas Test Year Billings to Affiliates
Exhibit SBT-21 Entergy Gulf States Louisiana Test Year Billings to Affiliates
Exhibit SBT-22 Entergy Louisiana Test Year Billings to Affiliates
Exhibit SBT-23 Entergy Mississippi Test Year Billings to Affiliates
Exhibit SBT-24 Entergy New Orleans Test Year Billings to Affiliates
Exhibit SBT-25 Entergy Non-Regulated Affiliates Test Year Billings to
Regulated Affiliates
Exhibit SBT-26 ESI Net Book Value of Assets
Exhibit SBT-27 Service Company Property Per Employee with Graph
Exhibit SBT-28A ESI Benchmarking Analysis Peer Group
Exhibit SBT-28B Service Company O&M as a Percentage of Total Company
O&M
Exhibit SBT-28C Service Company O&M as a Percentage of Total Company
Revenue
Exhibit SBT-28D Service Company O&M as a Percentage of Total Company
Assets
Exhibit SBT-28E Service Company O&M Per Service Company Employee
2011 ETI Rate Case 9-346
Entergy Texas, Inc. Page 1 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 I. NAME AND QUALIFICATIONS
2 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
3 A. My name is Stephanie B. Tumminello. During the Commission’s last
4 review in Docket No. 37744 and during the test period in this case through
5 June 24, 2011, my name was Stephanie B. Neyland. My business
6 address is 639 Loyola Avenue, New Orleans, LA 70113.
7
8 Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY?
9 A. I am employed by Entergy Services, Inc. (“ESI” or “Entergy Services”) as
10 Manager of Affiliate Accounting and Allocations, which was formerly
11 Intrasystem Affiliate Billing (“ISABill”).1
12
13 Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?
14 A. I am testifying on behalf of Entergy Texas, Inc. ("ETI" or the “Company").
15
16 Q. PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND.
17 A. I have a Bachelor of Science degree in Accounting from the University of
18 New Orleans. I am a Certified Public Accountant licensed in the State of
19 Louisiana.
1
This is distinct from the intra-system bill invoicing process discussed by Company witness
Patrick J. Cicio.
2011 ETI Rate Case 9-347
Entergy Texas, Inc. Page 2 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q. PLEASE BRIEFLY DESCRIBE YOUR PROFESSIONAL EXPERIENCE.
2 A. I have been employed by ESI for approximately 15 years and have held
3 various positions in the Accounting and Finance organizations. ESI is one
4 of the service companies providing services to Entergy Corporation and its
5 subsidiaries.2 My work experience is described in more detail in
6 Exhibit SBT-1.
7
8 Q. WHAT ARE THE PRINCIPAL AREAS OF YOUR RESPONSIBILITY AS
9 MANAGER OF AFFILIATE ACCOUNTING AND ALLOCATIONS?
10 A. I am responsible for the intrasystem affiliate billing processes of the
11 Entergy Service Companies: ESI, Entergy Operations, Inc. (“EOI”),
12 Entergy Enterprises, Inc. (“EEI”), and Entergy Nuclear Operations, Inc.
13 (“ENUC”). I oversee these companies’ billing processes and procedures
14 to ensure they are in compliance with applicable requirements of the retail
15 regulators of the Entergy Operating Companies,3 the Public Utility Holding
16 Company Act of 2005 (“PUHCA 2005”), and Federal Energy Regulatory
17 Commission (“FERC”) regulations.4
2
Each of these subsidiaries is a separate legal entity.
3
I use the name “Entergy” or “Entergy Companies” to mean, collectively, Entergy Corporation
and its direct and indirect subsidiaries. Each of these subsidiaries is a separate legal entity.
The Entergy Operating Companies (“Operating Companies”) are: ETI; Entergy Arkansas, Inc.
(“EAI” or “Entergy Arkansas”); Entergy Gulf States Louisiana, L.L.C. (“EGSL,” “EGSLA,” or
“Entergy Gulf States Louisiana”); Entergy Louisiana, LLC (“ELL” or “Entergy Louisiana”);
Entergy Mississippi, Inc. (“EMI” or “Entergy Mississippi”); and Entergy New Orleans, Inc.
(“ENOI” or “Entergy New Orleans”).
4
See Exhibit SBT-2 for a discussion of the regulation of Entergy Corporation’s subsidiaries.
2011 ETI Rate Case 9-348
Entergy Texas, Inc. Page 3 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 My responsibilities also include billings, allocations, approval of
2 billing method assignments on project codes, and updating and
3 maintaining processes for allocations related to the affiliates. I have
4 overall responsibility for all affiliate billing functions.
5 My responsibilities include oversight for the review of the elements
6 of billable project code (“PC”) requests and the approval of each billable
7 PC. I am also responsible for analyzing the amounts billed to affiliates to
8 ensure that the billing process is efficient and effective. In addition, I have
9 oversight for the provision of advice and training for ESI employees
10 regarding affiliate billing issues. My accounting responsibility for ESI as a
11 business unit (“BU”; also known as “legal entity” or “LE”) includes
12 providing information required for the preparation of the ESI FERC Form
13 60, Annual Report of Centralized Service Companies, as well as the
14 FERC Form 60 reports for EOI, EEI and ENUC.
15
16 II. INTRODUCTION
17 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
18 A. The primary purpose of my testimony is to provide an overview of ETI’s
19 affiliate case. I also discuss the regulation of affiliate transactions. In
20 addition, I explain how the affiliate portion of the Company’s filing is
21 organized. I address several affiliate transaction-related issues, such as
22 the affiliate billing processes used by ESI, the Operating Companies, other
2011 ETI Rate Case 9-349
Entergy Texas, Inc. Page 4 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 regulated affiliates,5 and non-regulated affiliates to collect and bill costs to
2 their affiliates, including ETI, for services rendered. A more detailed
3 discussion of the purpose of my testimony is provided below.
4 Affiliate Case Layout: In the Affiliate Case Layout section of my
5 testimony, I describe how affiliate charges to ETI have been organized
6 into classes, explain how the affiliate case is organized and how it ties to
7 the G-6 schedules and supporting workpapers,6 and introduce the other
8 affiliate witnesses. I describe how the information in this filing is presented
9 for the purpose of showing:
10  affiliate costs charged to ETI are necessary;
11  affiliate costs charged to ETI are reasonable;
12  the prices charged to ETI for each class of items are no
13 higher than the prices charged to other affiliates, or to
14 non-affiliates, for the same or similar class of items; and
15  the allocated amounts represent the actual cost of services
16 to ETI.
17 I also explain why the affiliate costs charged to ETI do not include
18 prohibited expenses and that the services provided to ETI by affiliates are
19 not duplicative of services provided internally by ETI or other affiliates.
20 Each affiliate cost witness will provide testimony supporting the
21 reasonableness and necessity of the specific affiliate classes that he or
5
Entergy’s regulated affiliates include the Operating Companies as well as System Fuels, Inc.
(“SFI” or “System Fuels”); EOI; ESI; System Energy Resources, Inc. (“SERI” or “System
Energy”); and Entergy New Nuclear Utility Development, LLC.
6
Schedule G-6 is a section within the Public Utility Commission of Texas’ (“Commission’s”)
Rate Filing Package (“RFP”). It includes a summary of test year affiliate transactions.
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1 she sponsors. These affiliate witnesses will also support the
2 appropriateness of the billing methods that are used for the classes that
3 they address. Exhibits that show, in consistent formats, the affiliate
4 expenses for each class accompany each witness’s testimony. As the
5 affiliate overview witness, my testimony collects and assembles all of
6 those individual class exhibits into one exhibit for ease of review.
7 Affiliate Transaction-Related Issues: In connection with my
8 discussion of the affiliate billing processes, I will:
9 (a) provide background information regarding Entergy
10 Corporation and its regulated and non-regulated
11 subsidiaries;
12 (b) describe the affiliate billing process, including
13 discussions regarding project billings, loaned
14 resource billings, co-owner billings, and controls;
15 (c) discuss the ESI service billings, including an overview
16 of the billing process, a summary of ESI charges to
17 affiliated companies, the service company recipient
18 allocation process, billing methods, and allocation
19 rates and statistics;
20 (d) discuss billings to ETI during the test year; and
21 (e) describe the pro forma adjustments associated with
22 the affiliate billings to ETI included in this filing and
23 discuss those pro forma adjustments that I sponsor.
24 In addition to the overview of affiliates charges, I sponsor three specific
25 classes of affiliate costs: (1) Depreciation (which pertains to depreciation
26 and amortization of ESI assets used in providing services); (2) Service
27 Company Recipient Offsets (sometimes referred to as “Shared Services
28 Loader Offsets”); and (3) Other Expenses.
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1 Q. WHAT EXHIBITS ARE YOU INCLUDING AS PART OF YOUR
2 TESTIMONY?
3 A. The exhibits that I am including as part of my testimony appear in the list
4 following the Table of Contents. Because these exhibits are voluminous
5 and include a number of spreadsheets, I have provided all of my exhibits,
6 workpapers, and schedule information on the attached CD, labeled
7 Exhibit SBT-F, rather than in paper form.
8
9 Q. DO YOU SPONSOR OR CO-SPONSOR ANY SCHEDULES IN THE
10 RATE FILING PACKAGE?
11 A. Yes, I co-sponsor several Rate Filing Package (“RFP”) schedules filed in
12 this proceeding. I am co-sponsoring with other witnesses the following
13 schedules:
14  Schedule G-6
15  Schedule G-6.1
16  Schedule G-6.2
17 I am also co-sponsoring the following workpapers included in
18 support of Schedule G-6 of the RFP:
19 G-6 WPs G-6.1 WPs G-6.2 WPs
20 WP/G-6 (set 1) WP/G-6.1 (set 1) WP/G-6.2 (set 1)
21 WP/G-6 (set 2) WP/G-6.1 (set 2) WP/G-6.2 (set 2)
22 WP/G-6 (set 3) WP/G-6.1 (set 3) WP/G-6.2 (set 3)
23 WP/G-6 (set 4) WP/G-6.1 (set 4) WP/G-6.2 (set 4)
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1 WP/G-6 (set 5) WP/G-6.1 (set 5) WP/G-6.2 (set 5)
2 WP/G-6 (set 6) WP/G-6.1 (set 6) WP/G-6.2 (set 6)
3 These schedules and supporting workpapers were prepared by me
4 or under my direct supervision.
5
6 Q. ON WHAT BASIS WERE THE SCHEDULES THAT YOU JUST
7 MENTIONED PREPARED?
8 A. They were prepared from the books and records of ESI and its affiliates
9 and are accurate summaries of the business records on which they are
10 based. Deloitte & Touche LLP (“D&T”), the independent auditor for
11 Entergy Corporation and subsidiaries, has performed a review of the
12 historical financial information included in Schedules A through W
13 (excluding L and R) of the RFP, and have reported its findings in
14 Schedule S.
15
16 Q. WHAT TEST YEAR IS ETI USING IN THIS FILING?
17 A. The test year in this case is the twelve months ended June 30, 2011.
18
19 Q. WHAT IS THE DOLLAR AMOUNT OF AFFILIATE CHARGES THAT ETI
20 HAS INCLUDED IN THE TEST YEAR COST OF SERVICE?
21 A. RFP Schedule G-6 shows that the Company’s “Total ETI Adjusted”
22 amount for affiliate charges for the test year is $78,998,777.
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1 Additionally, there are capitalized affiliate charges included in the
2 ETI capital additions that the Company is seeking to place in rate base.
3 These capital additions are addressed by other witnesses. ESI costs are
4 directly charged or allocated to capital work orders in the same manner as
5 costs are allocated to operations and maintenance expense-based project
6 codes, the latter of which are discussed in detail in my testimony.
7
8 Q. WHAT TYPE OF SYSTEM DO THE ENTERGY COMPANIES USE TO
9 CAPTURE COSTS?
10 A. The Entergy Companies use a project costing application (PowerPlant)
11 that provides a single point of entry for all PCs (that is, “project codes”). A
12 PC is an alpha numeric code that is assigned to individual projects
13 established within organizations (also referred to as “departments”). Each
14 PC is applicable to a specific assignment or activity. For example, a PC
15 would be assigned to a project to develop a specific software application,
16 a specific construction project, an employee training project, or any of a
17 myriad of activities that are necessary to run a utility.
18
19 III. BACKGROUND INFORMATION REGARDING ENTERGY
20 CORPORATION AND ITS SUBSIDIARIES
21 Q. PLEASE BRIEFLY DESCRIBE ENTERGY CORPORATION.
22 A. Entergy Corporation owns both regulated and non-regulated companies.
23 Exhibit SBT-2 provides a detailed discussion of Entergy Corporation
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1 subsidiaries. Exhibit SBT-3 is an organization chart for Entergy
2 Corporation and its subsidiaries, including both regulated and direct non-
3 regulated companies, as of June 30, 2011.
4
5 Q. PLEASE BRIEFLY DESCRIBE ENTERGY CORPORATION AND ITS
6 WHOLLY-OWNED REGULATED SUBSIDIARIES.
7 A. Entergy Corporation owns all of the outstanding common stock of six retail
8 Operating Company subsidiaries: ETI, EAI, EGSL, ELL, EMI, and ENOI.
9 As of June 30, 2011, these Operating Companies provided electric service
10 to approximately 2.7 million customers in the states of Arkansas,
11 Louisiana, Mississippi, and Texas.
12 Entergy Corporation also owns all of the outstanding common stock
13 of System Energy, ESI, and EOI, which are regulated by the Nuclear
14 Regulatory Commission (“NRC”) and/or the FERC. System Energy is a
15 nuclear generating company that sells the generating capacity and energy
16 from its 90% interest in the Grand Gulf nuclear plant at wholesale to its
17 only customers: EAI, ELL, EMI, and ENOI. ESI is a service company
18 established to provide professional services primarily to Entergy’s
19 regulated utilities or Operating Companies.
20 EOI is also a service company, and was established to provide
21 nuclear management and operations and maintenance services to
22 Entergy’s regulated nuclear plants: Arkansas Nuclear One; River Bend;
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1 Waterford 3; and Grand Gulf. Although these plants are operated by EOI,
2 they are owned by: EAI; EGSL; ELL; and System Energy, respectively.
3
4 Q. PLEASE PROVIDE AN OVERVIEW OF ENTERGY’S NON-REGULATED
5 SUBSIDIARIES.
6 A. Entergy’s non-regulated subsidiaries include, among others, EEI, Entergy
7 Power, LLC (“EPL”), a wholesale power producer that is a subsidiary of
8 Entergy Asset Management, Inc., and ENUC, a service company
9 established to provide nuclear management and operations services to
10 Entergy’s non-regulated nuclear plants. For a more detailed discussion of
11 Entergy’s direct non-regulated affiliates, please refer to Exhibit SBT-2.
12
13 Q. FROM WHICH OF THE ENTERGY SUBSIDIARIES DOES ETI RECEIVE
14 THE MOST SIGNIFICANT LEVEL OF AFFILIATE CHARGES?
15 A. ETI receives the most significant level of affiliate charges from ESI. In
16 addition to affiliate charges from ESI, ETI receives charges from the other
17 Operating Companies, EOI, and from certain non-regulated affiliates.
18
19 Q. WHY IS ESI THE SOURCE OF MOST OF ETI’S AFFILIATE CHARGES?
20 A. Centralization of activities through the creation of service companies
21 results in economies of scale and provides a pool of centralized expertise
22 for Entergy Corporation’s regulated utility affiliates. As noted previously,
23 ESI, EOI, EEI, and ENUC are the four primary service companies. EOI
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1 provides services to the regulated nuclear plants, and EEI and ENUC
2 provide services to non-regulated affiliates, as more fully described in
3 Exhibit SBT-2. I provide an overview of the services provided by ESI.
4
5 Q. PLEASE DESCRIBE THE PURPOSE AND FUNCTION OF ESI.
6 A. ESI is authorized to conduct business as a service company by a
7 temporary order issued by the Securities and Exchange Commission
8 (“SEC”) in March 1963, which was made permanent in March 1965. ESI
9 was formed as, and continues to be, primarily a service company for the
10 Operating Companies. Costs incurred by ESI to provide services to all
11 regulated companies, including ETI, are billed at cost and do not produce
12 a profit. ESI also performs services for some of Entergy’s non-regulated
13 companies through ESI’s Service Agreement with EEI. These services
14 are billed at cost plus 5%. Exhibit SBT-2 provides a more detailed
15 discussion of ESI’s purpose and function.
16
17 Q. WHAT TYPES OF SERVICES DOES ESI PROVIDE?
18 A. The services ESI provides to its affiliates include general executive,
19 management, advisory, administrative, human resources, accounting,
20 legal, regulatory, and engineering services. These services are provided
21 in accordance with Service Agreements entered into by ESI and the
22 respective affiliates to which it provides services. The Service
23 Agreements between ESI and its affiliates are included as Exhibits SBT-
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2011 Rate Case
1 4A through SBT-4P. These Service Agreements outline the general types
2 of services that ESI provides.
3 ESI provides services according to functional groupings that reflect
4 the way ESI is organized. See Exhibits SBT-5 and SBT-6 for details,
5 which I discuss in more detail later in my testimony. These groupings are
6 reflected in the presentation of ETI’s affiliate expenses in this filing and
7 represent a compilation of the services that are provided to ETI by ESI.
8 The types of services outlined in the Service Agreements between
9 ESI and the affiliates that it serves have been grouped in classes that are
10 discussed later in my testimony for the purpose of presentation in this
11 filing. Exhibit SBT-7 shows the affiliates that receive services from ESI.
12
13 Q. IS THE SERVICE AGREEMENT BETWEEN ESI AND ETI DIFFERENT
14 IN SUBSTANCE FROM THE SERVICE AGREEMENTS ESI HAS WITH
15 THE OTHER AFFILIATED COMPANIES?
16 A. No. The Service Agreements between ESI and each of the other Entergy
17 affiliates discussed previously are the same in substance. However, the
18 types and amounts of services vary among the companies.
19
20 Q. ARE ALL NON-REGULATED ENTERGY COMPANIES PARTIES TO
21 SERVICE AGREEMENTS WITH ESI?
22 A. No. ESI does not directly provide services to all of the non-regulated
23 affiliates. ESI, however, does provide services directly to EPL and EEI,
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1 and has service agreements with these two non-regulated companies.
2 When ESI provides services to EEI, the provision of these services is
3 often the result of a request for services made by a non-regulated
4 company to EEI. When that situation arises, the billing for that service is
5 made by ESI to EEI and, in turn, EEI bills the non-regulated company for
6 the service. As shown on Exhibit SBT-8, total ESI billings to EPL and EEI
7 were .03% and 16.06%, respectively, of ESI’s total billings to all affiliates
8 during the test year.7 As indicated in Exhibit SBT-9, total ESI billings to
9 EPL declined from 2008 to 2010, while billings to EEI increased from 2008
10 to 2010.
11
12 Q. WHAT TYPES OF SERVICES ARE PROVIDED BY ESI TO THE NON-
13 REGULATED AFFILIATES THROUGH EEI?
14 A. Although ESI was formed to serve primarily Entergy Corporation’s
15 regulated utility operations, there are three general categories of services
16 that ESI provides to the non-regulated companies through EEI. The first
17 type of services provided by ESI through EEI are those provided solely to
18 EEI or a non-regulated affiliate. For instance, ESI provides services with
19 regard to specific non-routine projects, tax issues, legal issues, or
20 accounting issues directly associated with EEI or a non-regulated affiliate.
21 These costs are billed 100% to EEI.
7
Exhibit SBT-8 includes a schedule of ESI billings to affiliates during the test year.
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1 The second type of services provided by ESI through EEI is the
2 type of services that concurrently are used by both the regulated and
3 non-regulated Entergy affiliates. For example, non-regulated companies
4 participate in certain payroll, human resources, benefits, accounts
5 payable, communications, and support services primarily provided to the
6 regulated companies. However, the level of such services may differ
7 between the regulated and non-regulated affiliates. For example, ESI
8 processes all of the payroll transactions for the regulated affiliates,
9 whereas ESI processes some, but not all, of the non-regulated companies’
10 payroll transactions. In this instance, the billing method for allocating the
11 costs assigned to the associated PC is calculated based on the number of
12 paychecks issued for those companies for which the services are
13 provided.
14 The third type of ESI service provided and billed to EEI is for EEI’s
15 allocable share of ESI’s overhead and departmental costs. ESI, like any
16 corporation, incurs costs that are necessary to maintain and support its
17 existence. Therefore, ESI’s expenses for its own overhead costs, such as
18 accounting, tax, legal, and other support, must be distributed reasonably
19 to all of the legal entities that ESI serves, including EEI.
20 Further, each department (also referred to as “organization”) within
21 ESI must incur costs that are not related to any specific service, but which
22 are costs that are attributable to a department. EEI is billed for a portion
23 of these costs. These include items such as administrative labor costs
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2011 Rate Case
1 associated with office and general service employees (including not only
2 salaries and wages but also other related employment costs), rent and
3 utilities, depreciation, materials and supplies, telephone use, and postage.
4
5 Q. DOES ESI PROVIDE ANY SERVICES TO THE REGULATED OR NON-
6 REGULATED COMPANIES FREE OF CHARGE OR AT A DISCOUNT?
7 A. No. ESI costs incurred to provide services to its regulated affiliates are
8 billed at cost and to non-regulated affiliates at cost plus 5% (in accordance
9 with a June 1999 SEC order).
10
11 IV. AFFILIATE TRANSACTION REGULATION
12 Q. ARE YOU FAMILIAR WITH THE STANDARDS USED BY THE PUBLIC
13 UTILITY COMMISSION OF TEXAS (“COMMISSION”) TO DETERMINE
14 THE REASONABLENESS OF EXPENSES ASSOCIATED WITH
15 AFFILIATE TRANSACTIONS AND THE ELIGIBILITY OF SUCH
16 EXPENSES FOR INCLUSION IN COST OF SERVICE?
17 A. Yes. I am not an attorney, but part of my job responsibility is to be familiar
18 with the legal standards (rules, statutes, and court cases) governing
19 affiliate transactions and cost recovery in Commission proceedings.
20 Section 36.058 of the Public Utility Regulatory Act (“PURA”) and Railroad
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2011 Rate Case
1 Commission of Texas v. Rio Grande Valley Gas Company8 set forth the
2 affiliate standard applicable to Commission rate proceedings. This
3 standard involves a four-part inquiry that addresses: (1) the necessity of
4 the affiliate services on a class of items basis; (2) the reasonableness of
5 the costs related to the class; (3) the compliance with the “no higher than”
6 standard, which requires that the price for the same or similar services
7 provided be no higher for one affiliate or non-affiliated person than for
8 another affiliate or non-affiliated person;9 and (4) whether the price
9 charged reasonably approximates (or represents) the actual cost of the
10 services. I also explain that the price charged excludes costs that may not
11 be allowed for ratemaking purposes, and that charges are not duplicated.
12
13 Q. ARE YOU FAMILIAR WITH THE REQUIREMENTS OF SUB-SECTION (f)
14 OF PURA SECTION 36.058?
15 A. Yes. It is my understanding that if the Commission determines that the
16 requested amount of an affiliate expense during the test period is
17 unreasonable, then, instead of disallowing the entire affiliate expense, the
18 Commission must determine the reasonable level of the affiliate expense
19 and include that reasonable level in the utility’s cost of service.
8
683 S.W.2d 783 (Tex. App.-Austin 1984 no writ).
9
ESI does not provide services to non-affiliated entities.
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2011 Rate Case
1 Q. DOES THE COMMISSION’S RFP APPLICABLE TO ETI PROVIDE ANY
2 GUIDANCE REGARDING HOW TO DEMONSTRATE THE
3 REASONABLENESS AND NECESSITY OF AFFILIATE CHARGES?
4 A. No. ETI is required to use, and is using for this case, the Electric Utility
5 Rate Filing Package for Generating Utilities (Sept. 9, 1992). This is the
6 RFP for fully-bundled electric utilities such as ETI. Section V of the
7 Commission’s RFP for unbundled transmission and distribution utilities,10
8 however, provides a set of “guiding principles” with illustrative types of
9 evidence that may be used to support the affiliate charges, including
10 historical cost trends, process improvements, benchmarking, outsourcing,
11 third-party reviews, operating statistics, and other metrics. These guiding
12 principles are not, strictly speaking, applicable to this case because ETI is
13 not an “unbundled” transmission and distribution utility. Nonetheless,
14 each Company affiliate cost witness has relied upon these guiding
15 principles to marshal the evidence to support his or her affiliate costs.
16
17 Q. HOW DO THE AFFILIATE COSTS INCLUDED IN THE COMPANY’S
18 REVENUE REQUIREMENT COMPLY WITH APPLICABLE STANDARDS
19 IN TEXAS STATUTES AND RULES?
20 A. Each affiliate cost witness sponsors testimony supporting his or her
21 specific affiliate classes. Their testimony, in conjunction with my
10
Investor Owned Utility Transmission & Distribution Cost of Service Rate Filing Package
(April 2, 2003).
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1 testimony, demonstrates that the affiliate costs meet the standards I
2 describe above for recovery of affiliate charges. Also, Company witness
3 Jeanne J. Kenney presents additional support by demonstrating the
4 reasonableness of ETI’s costs from an overall benchmarking perspective.
5 Other witnesses support the reasonableness of categories of costs, such
6 as compensation and benefits (by ETI witness Kevin G. Gardner) and the
7 supplies and acquisition processes (by ETI witness Joseph M. Hunter).
8
9 Q. WHAT OTHER REGULATORY REQUIREMENTS REGARDING
10 AFFILIATE TRANSACTIONS ARE RELEVANT TO A REVIEW OF
11 AFFILIATE TRANSACTIONS?
12 A. I am advised that prior to February 8, 2006, Entergy Corporation was a
13 holding company registered under the Public Utility Holding Company Act
14 of 1935 (“PUHCA 1935”) and, therefore, was subject to the oversight of
15 the SEC. ESI, which is a service company established in accordance with
16 PUHCA 1935, was subject to regulation by the SEC. Effective February 8,
17 2006, however, pursuant to the Energy Policy Act of 2005 (“EPAct 2005”),
18 PUHCA 1935 was repealed and the Public Utility Holding Company Act of
19 2005 (“PUHCA 2005”) was enacted. Section 1275(b) of EPAct 2005
20 provides that:
21 In the case of non-power goods or administrative or
22 management services provided by an associate company
23 organized specifically for the purpose of providing such
24 goods or services to any public utility in the same holding
25 company system, at the election of the system or a State
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1 commission having jurisdiction over the public utility, the
2 [FERC], after the effective date of this subtitle, shall review
3 and authorize the allocation of the costs for such goods or
4 services to the extent relevant to that associate company.
5
6 Q. WHAT REGULATIONS HAS FERC ISSUED RELATED TO SERVICE
7 COMPANIES TO REPLACE THE SEC REGULATIONS?
8 A. On December 8, 2005, the FERC issued Order No. 667, which added Part
9 366 to its regulations to implement the repeal of PUHCA 1935 and the
10 enactment of PUHCA 2005. Under the definitions provided in the PUHCA
11 2005 regulations, ESI is a “service company” in that it was organized
12 specifically for the purpose of providing non-power goods or services to a
13 “public utility” within the same holding company system. Each of the
14 Operating Companies is a “public utility” as defined in the PUHCA 2005
15 regulations. The PUHCA 2005 regulations also include Section 366.5,
16 which essentially mirrors the language of Section 1275(b) of the EPAct
17 2005, and adds that “[s]uch election to have the [FERC] review and
18 authorize cost allocations shall remain in effect until further [FERC] order.”
19 On October 19, 2006, the FERC issued Order No. 684, “Financial
20 Accounting, Reporting and Records Retention Requirements under the
21 Public Utility Holding Company Act of 2005.” This order establishes
22 regulations for service companies related to the Uniform System of
23 Accounts (“USofA”), the filing of the FERC Form 60, and records
24 retention requirements.
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1 On February 21, 2008, the FERC issued Order No. 707,
2 “Cross-Subsidization Restrictions on Affiliate Transactions.” This order
3 codified, among other things, the FERC requirements for the pricing of
4 non-power goods and services provided by a service company and
5 between other affiliates. On July 17, 2008, the FERC issued Order No.
6 707-A, “Order on Rehearing.” This order granted rehearing and
7 clarification, in part, of Order No. 707.
8
9 Q. WHAT ARE THE FERC REQUIREMENTS FOR THE PRICING OF NON-
10 POWER GOODS AND SERVICES PROVIDED BY A SERVICE
11 COMPANY?
12 A. FERC Order Nos. 667 and 667-A allowed traditional, centralized service
13 companies that previously used the SEC’s “at cost” standard for the
14 pricing of sales of non-fuel, non-power goods and services to
15 FERC-jurisdictional utilities to continue to use that “at cost” standard (the
16 “at cost” standard means, as I understand it, that cost of the services does
17 not include a component of profit.) Further, in its Order Nos. 667 and 667-
18 A, the FERC indicated that “at cost” pricing of non-power goods and
19 services provided by traditional, centralized service companies such as
20 ESI to associate public utilities is presumed to be reasonable.
21 Specifically, in Order No. 667 the FERC stated:
22 Fundamentally, we agree…that centralized provision of
23 accounting, human resources, legal, tax and other such
24 services benefits ratepayers through increased efficiency
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1 and economies of scale. Further we recognize that it is
2 frequently difficult to define the market value of the
3 specialized services provided by centralized service
4 companies. Accordingly, the Commission will apply a
5 rebuttable presumption that costs incurred under “at cost”
6 pricing of such services are reasonable.
7 FERC Order Nos. 707 and 707-A prohibit, among other things, a
8 franchised public utility with “captive customers” from receiving non-power
9 goods and services from a centralized service company at a price above
10 cost. This “at cost” pricing requirement for service company billings is
11 consistent with previous FERC and SEC requirements. ESI is in
12 compliance with the pricing requirements of FERC Order Nos. 707 and
13 707-A. ESI’s compliance with the FERC’s “at cost” requirement helps to
14 ensure that ESI affiliate costs charged to ETI are reasonable.
15
16 Q. DID THE ENTERGY COMPANIES REQUEST A REVIEW OF COST
17 ALLOCATIONS BY FERC FOLLOWING THE ENACTMENT OF PUHCA
18 2005?
19 A. Yes. On October 13, 2006, ESI, on behalf of the Operating Companies,
20 submitted a filing to the FERC requesting that FERC: (a) review and
21 accept the cost allocation methods included in the service agreements
22 used for the sale of non-power goods and services by ESI and EOI to the
23 Operating Companies; and (b) accept the existing service agreements
24 effective as of February 8, 2006. The filing was made pursuant to Section
25 1275(b) of the EPAct 2005, Section 205 of the Federal Power Act, and
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1 Section 366.5(a) and Part 35 of the FERC’s regulations (18 C.F.R.). In
2 electing to make this filing, ESI sought a determination by the FERC with
3 respect to the appropriate allocation and pricing of services provided by
4 ESI and EOI to the Operating Companies.
5
6 Q. DID THE FERC ISSUE AN ORDER IN CONNECTION WITH THE
7 ENTERGY COMPANIES’ FILING IN THIS MATTER?
8 A. Yes. On December 12, 2006, the FERC issued an order accepting the
9 service agreements and proposed methods of cost allocation effective
10 February 8, 2006, as requested in the Entergy Companies’ filing. In that
11 order, the FERC agreed that Section 1275(b) of EPAct 2005 was intended
12 to vest authority in a federal regulator to help avoid disparate regulatory
13 treatments with respect to service company cost allocations. The FERC
14 order accepting ESI’s and EOI’s service company cost allocation request
15 is included as Exhibit SBT-10A.
16
17 Q. DOES PUHCA 2005 CONTAIN ANY PROCEDURES FOR CHANGING
18 COST ALLOCATIONS REVIEWED AND ACCEPTED BY THE FERC?
19 A. No. PUHCA 2005 does not separately specify procedures for changing
20 cost allocations reviewed and accepted by the FERC. However, in its
21 December 12, 2006 order discussed above, the FERC explained that any
22 changes to a FERC-filed rate, including the cost allocation provisions,
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1 must be made in accordance with Section 205 and 206 of the Federal
2 Power Act.
3
4 Q. HAVE THERE BEEN ANY MODIFICATIONS TO THE ENTERGY
5 COMPANIES’ COST ALLOCATION FORMULAS DURING THE TEST
6 YEAR?
7 A. Yes. On October 28, 2010, ESI, on behalf of the Operating Companies,
8 submitted a filing to the FERC requesting that FERC review and accept a
9 proposed new cost allocation formula based on the historical usage of
10 servers, platforms, and mainframes. On December 20, 2010, the FERC
11 issued an order accepting ESI’s October 28, 2010 cost allocation request.
12 The FERC order accepting ESI’s cost allocation request is included as
13 Exhibit SBT-10B.
14
15 Q. DOES THE FERC EXERCISE ANY ADDITIONAL OVERSIGHT
16 AUTHORITY OVER ENTERGY’S SERVICE COMPANIES?
17 A. Yes. The FERC, in its oversight role, is authorized to conduct periodic
18 audits of service company transactions. The FERC also requires that
19 centralized service companies file an annual report on FERC Form 60.
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1 Q. HAS THE FERC CONDUCTED ANY AUDITS OF ENTERGY
2 CORPORATION’S SERVICE COMPANIES?
3 A. Yes. As noted above, the FERC, under the authority of the Public Utility
4 Holding Company Act of 2005, is authorized to periodically conduct audits
5 of service companies. These service company audits include an
6 examination of each service companies’ compliance with
7 cross-subsidization restrictions on affiliate transactions at 18 C.F.R. Part
8 35, accounting, recordkeeping, and reporting requirements at 18 C.F.R.
9 Part 366, compliance with the Uniform System of Accounts (“USofA”) for
10 centralized service companies at 18 C.F.R. Part 367, and preservation of
11 records requirements for service companies at 18 C.F.R. Part 368. During
12 the most recent FERC audit of Entergy Corporation’s four service
13 companies, including ESI, covering the period January 2006 through
14 December 2008, the FERC tested for compliance with the aforementioned
15 regulations by conducting tests of the service companies’ cost allocations
16 and the charges billed by the service companies. The FERC reviewed
17 and tested the supporting details for the service companies’ cost allocation
18 methodologies, tested the centralized service companies’ costs and
19 accounting, and reviewed selected service companies’ billings and the
20 corresponding associated franchised public utilities’ accounting for the
21 billings. The FERC letter order dated December 9, 2009 in connection
22 with this audit found there were no significant deficiencies related to the
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2011 Rate Case
1 allocation methodologies, accounting, or pricing of service
2 company transactions.11
3
4 V. AFFILIATE CASE LAYOUT
5 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?
6 A. This section of my testimony provides an overview of how the Company’s
7 affiliate transaction case is organized to meet the affiliate standard in
8 Texas, including: an explanation of why the case is organized in this
9 manner; an explanation of how the testimony and exhibits of each of the
10 affiliate witnesses link to G-6 Schedules; and an explanation of how the
11 testimony, exhibits and G-6 Schedules relate to the PCs that I describe in
12 more detail later in my testimony.
13
14 Q. HOW DO THE AFFILIATE COSTS PRESENTED IN THIS CASE RELATE
15 TO THE RATES THE COMPANY SEEKS TO ESTABLISH IN THIS
16 CASE?
17 A. The Company’s cost of providing services includes both costs incurred
18 directly by the Company and affiliate charges. As discussed earlier, the
19 Commission determines the eligibility of affiliate costs for recovery in rates
20 based on the standards required by law. The Company has presented its
21 affiliate information in a manner that will permit the Commission to review
11
Workpaper WP/SBT-1 includes the FERC letter order dated December 9, 2009.
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 its affiliate costs for compliance with the affiliate standard. The affiliate
2 costs are a component of the rates the Company is requesting to
3 implement in this docket.
4
5 Q. PLEASE DESCRIBE THE COMPANY’S ORGANIZATION OF ITS
6 AFFILIATE CASE.
7 A. The Company’s affiliate case is organized to correspond to the way in
8 which ETI and ESI are organized and managed. ESI’s business is divided
9 into two basic functional groupings or “families.” These families are (1)
10 Corporate Support, and (2) Operations.
11
12 Q. ARE THE TWO FAMILIES FURTHER BROKEN DOWN INTO SMALLER
13 GROUPINGS?
14 A. Yes. Within each of these families, we have more discrete functions or
15 service categories. Thus, for example, as shown in Exhibit SBT-6, entitled
16 “Families and Functions,” the “Operations” family (shorthand for Utility
17 Operations Group) is comprised of traditional utility functions such as
18 Generation, Transmission, Distribution, and Customer Service.
2011 ETI Rate Case 9-372
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q. ARE THESE “FUNCTIONS” THE “CLASSES” THAT THE COMPANY
2 HAS IDENTIFIED FOR PURPOSES OF MEETING THE AFFILIATE
3 STANDARD IN PURA, WHICH REQUIRES COSTS TO BE ORGANIZED
4 ON AN ITEM OR CLASS OF ITEMS BASIS?
5 A. Not necessarily. In some cases, there is only one class within a function.
6 But the functions are not always the classes the Company proposes for
7 purposes of proving its compliance with the affiliate standard set forth in
8 PURA. The Company determined that some of these functions may be
9 too broad for purposes of meeting the affiliate standard and may not
10 permit the detailed review of affiliate transactions envisioned by the
11 Commission. Further, the Company wanted to ensure that the witnesses
12 who explain the affiliate services provided to ETI have the requisite degree
13 of accountability and technical knowledge to provide sufficient detailed
14 information concerning each class of services (that is “class of items”) that
15 they sponsor.
16
17 Q. HOW DID THE COMPANY SEPARATE THESE FUNCTIONS INTO
18 CLASSES OF SERVICES FOR PURPOSES OF PROVING
19 COMPLIANCE WITH THE AFFILIATE STANDARD?
20 A. The Company and ESI focused on the way they organize and operate
21 their businesses in order to identify classes of services for purposes of
22 meeting the affiliate standard. Thus, the Company looked at the various
23 departments that compose each function and grouped these departments
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 into classes based on factors such as the extent to which the departments
2 provided interrelated services or had some other logical connection to
3 each other. For example, departments such as accounts payable and
4 cash operations, payroll, fixed asset operations, revenue operations,
5 external reporting, and Affiliate Accounting and Allocations were included
6 in the Financial Services Class of services. A similar process was
7 followed for identifying classes within each of the functions shown on
8 Exhibit SBT-5. Additionally, some cost items were grouped based on
9 resource code instead of department code12 (examples of these include
10 depreciation and income taxes) and based on physical location for Nelson
11 6 co-owner costs.
12
13 Q. HOW MANY CLASSES OF AFFILIATE CHARGES ARE THERE IN THE
14 COMPANY’S CASE, AND WHO SPONSORS THEM?
15 A. Affiliate services provided to ETI are grouped into 25 classes of items in
16 the Company’s filing. Exhibit SBT-5 shows the functions composing each
17 family as well as the classes that make up each function. For example,
18 Exhibit SBT-5 shows that there are six functions within the Corporate
19 Support family. Below each function are the classes that compose that
20 function and the name of the witness who sponsors that affiliate class of
12
A resource code indicates the type of costs used or consumed in the conduct of work
activities, while a department code indicates which organization provides the services (and
budgets, captures and reports on the related costs for those services).
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2011 Rate Case
1 services. This exhibit also shows the Total ETI Adjusted amount for each
2 class of affiliate services. For example, the Financial Services class,
3 which is sponsored by Company witness Donna S. Doucet, is in the
4 Finance function. This exhibit does not include the level of test year
5 affiliate charges for capital additions.
6
7 Q. WHAT INFORMATION DOES EACH WITNESS PROVIDE WITH
8 RESPECT TO THE CLASSES OF SERVICES THAT HE OR SHE
9 SPONSORS?
10 A. Although the testimony of each of the affiliate witnesses varies depending
11 on subject matter, there are certain common elements that I will explain.
12 Each witness who sponsors a class of services describes why those
13 services are necessary; explains why the costs of those services are
14 reasonable; discusses the billing methods used to ensure that prices paid
15 by ETI are no higher than the prices paid by other Entergy affiliates for the
16 same or similar services; and also explains that the costs paid by ETI
17 represent the actual costs of the services provided. In addition, each
18 affiliate witness has included as exhibits to his or her testimony a
19 schematic that highlights by family and function the class or classes that
20 he or she is supporting, i.e., an exhibit identical to my Exhibits SBT-5 and
21 SBT-6.
2011 ETI Rate Case 9-375
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q. ARE THERE ANY OTHER EXHIBITS THAT ARE COMMON TO ALL
2 AFFILIATE WITNESSES?
3 A. Yes. Each affiliate witness sponsors key affiliate cost-related exhibits that
4 are designated by letters (i.e., A, B, C, D) instead of numbers. For ease of
5 reference, I will refer to them as Exhibits A, B, C, and D. For example, the
6 affiliate cost exhibits supporting Company witness Doucet’s testimony are
7 labeled Exhibits DSD-A, DSD-B, DSD-C, and DSD-D. These exhibits
8 present the cost of affiliate services in various levels of detail for each
9 class of services included in Schedule G-6 of the Company’s Application.
10 For each class of services sponsored by the witness, Exhibits A, B and C
11 include all affiliate billings that originate at ESI, billings to ETI from the
12 other Operating Companies (EAI, EGSL, ELL, EMI, or ENOI), and billings
13 to ETI from other affiliates. In addition, Exhibit D contains information
14 about test year pro forma adjustments, if any, affecting each class of
15 services sponsored by the witness. For the convenience of the parties, I
16 have included my Exhibits SBT-A, SBT-B, SBT-C, and SBT-D, which are
17 compilations of all witnesses’ Exhibits A, B, C, and D, respectively. My
18 Exhibit SBT-D differs slightly from the witnesses’ Exhibit D in that it
19 includes FERC accounts.13
13
Workpaper WP/SBT-2 provides, among other things, FERC account information for pro forma
adjustments included on Exhibit SBT-D.
2011 ETI Rate Case 9-376
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q. PLEASE DESCRIBE THE INFORMATION THAT IS CONTAINED IN
2 EXHIBIT A.
3 A. Exhibit A is entitled, “Affiliate Billings – by Witness, Class and
4 Department.” Exhibit A shows for each class of services sponsored by
5 that witness the amounts by department for the test year. The information
6 presented in Exhibit A permits the reviewer to examine which departments
7 had charges within each class of services and the amounts of test year
8 costs for each department within the class.
9
10 Q. PLEASE SUMMARIZE HOW TO CALCULATE THE TEST YEAR
11 AMOUNT FOR EACH CLASS OF SERVICES DESCRIBED IN EXHIBIT A
12 OF EACH WITNESS’ TESTIMONY.
13 A. To calculate the test year amount for a class of service described in
14 Exhibit A, the reviewer need only add Column “E” (ETI Per Books) +
15 Column “F” (Exclusions) + Column “G” (Pro Forma Amount) to arrive at
16 the Total ETI Adjusted amount shown in Column “H,” which is the amount,
17 by billing entity, included in the G-6 workpapers for this class of services.
18
19 Q. HAVE YOU PREPARED AN EXHIBIT THAT SUMMARIZES THE
20 CONTENTS OF COLUMN “F” (EXCLUSIONS) IN EXHIBITS A, B, C,
21 AND D?
22 A. Yes. Exhibit SBT-11, entitled “Affiliate Billing Exclusions by Class,” shows
23 by function and by class all exclusions from ETI’s test year affiliate
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 expenses for the Corporate Support family and the Operations family. As
2 shown in this exhibit, test year exclusions totaled approximately
3 $17.7 million. Exclusions include amounts charged to FERC USofA
4 capital accounts (FERC accounts 107 to 118); other balance sheet
5 accounts (FERC accounts 152 to 242); and below the line accounts
6 (FERC accounts 408202 to 426500). With the exception of amounts
7 charged to certain capital accounts, these exclusions are made in order to
8 arrive at a total cost amount that does not include costs that may not be
9 recovered in rates, such as expenses prohibited from being included in
10 rates by Texas law. Amounts included in the exclusions category do not
11 represent pro forma adjustments.
12
13 Q. HAVE YOU PREPARED AN EXHIBIT TO ASSIST THE REVIEWER IN
14 TRACKING THE DATA PRESENTED IN EXHIBIT A?
15 A. Yes. I have prepared Exhibit SBT-A.1 for that purpose. This “roadmap”
16 exhibit illustrates in a brief and easily understandable way, what specific
17 information is provided in each column of Exhibit A.
18
19 Q. PLEASE DESCRIBE EXHIBIT B THAT IS ATTACHED TO EACH
20 WITNESS’ S TESTIMONY.
21 A. Exhibit B is entitled, “Affiliate Billings – by Witness, Class and Project.”
22 Exhibit B shows for each class of services sponsored by that witness the
23 amounts by project code (also referred to as a “PC”) for the test year. The
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2011 Rate Case
1 information presented in Exhibit B permits the reviewer to examine the
2 following: which PCs were charged within each class of services; which
3 billing method was used; and the amounts included in test year costs for
4 each PC within the class. From here, the reviewer can, in turn, refer to the
5 Project Summaries included as Exhibit SBT-E for additional detail
6 concerning each PC included in each class within the Company’s filing. I
7 discuss the information presented in the Project Summaries in greater
8 detail later in my testimony.
9
10 Q. PLEASE DESCRIBE EXHIBIT C.
11 A. Exhibit C, which is entitled “Affiliate Billings – by Witness, Class,
12 Department and Project,” is a combination of Exhibits A and B. This
13 additional sort of the data, by department and project, allows the reviewer
14 to determine which department charged a particular PC for the particular
15 services. For example, Company witness Doucet’s Exhibit DSD-C allows
16 the reviewer to trace a total of $26,678 Total ETI Adjusted test year
17 amount, including pro forma adjustments, to the Financial Services Class
18 billings to project code “F3PPF72700.” Exhibit DSD-C further shows that
19 these services were performed by the following billing departments:
20 FA256, FA259, FA26A, FN2F1, and RA2IA.14
14
Workpaper WP/SBT-3 provides the department descriptions for each department code.
2011 ETI Rate Case 9-379
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q. PLEASE DESCRIBE EXHIBIT D.
2 A. Exhibit D, entitled “Affiliate Billings – Pro Forma Summary – by Witness,
3 Class and Pro Forma,” contains information about test year pro forma
4 adjustments affecting the class or classes that a particular Company
5 witness sponsors. The witnesses’ Exhibit D contains a brief description of
6 the nature of the pro forma adjustment, assigns the adjustment an
7 identifying number, shows the billing entity of the transaction, shows which
8 witness supports the pro forma, and presents the amount of the pro forma
9 that is included in the “Total” column of Schedule G-6.2. In addition to the
10 items described above, Exhibit SBT-D also contains the FERC account for
11 each pro-forma adjustment.
12
13 Q. HAVE YOU PREPARED ANY DOCUMENTS REGARDING THE PRO
14 FORMA ADJUSTMENTS INCLUDED IN EXHIBIT SBT-D?
15 A. Yes. Exhibit SBT-12 includes summary information regarding each pro
16 forma adjustment included in Schedule G-6.2. This Exhibit includes the
17 pro forma number, title, description, ETI pro forma amount, and supporting
18 witness. The main purpose of this exhibit is to accumulate in one place all
19 originating affiliate pro forma adjustments to the test year, and to provide
20 additional supporting detail for why the pro forma was made.
21 Also, workpapers WP/SBT-2a through WP/SBT-2s include
22 calculations for each pro forma adjustment. WP/SBT-2 is an index to the
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 calculations included to assist the reviewer in locating the calculation for
2 any pro forma adjustment listed in Schedule G-6.2.
3
4 Q. HAVE YOU PREPARED ANY ADDITIONAL DOCUMENTS THAT WILL
5 ASSIST REVIEWERS IN UNDERSTANDING THE INFORMATION
6 CONTAINED IN EACH COLUMN OF EXHIBITS B THROUGH D?
7 A. Yes. Although the Company believes that the level of detail that it has
8 provided in this filing is more than sufficient to enable the Commission to
9 evaluate the Company’s affiliate costs, the Company recognizes that it
10 may be difficult for a reviewer to recall the type of information that is
11 provided in each column of each of these exhibits. For this reason, I have
12 included in my testimony as Exhibits SBT-B.1, SBT-C.1, and SBT-D.1
13 “roadmaps” that show what question is answered by each column in each
14 exhibit, similar to “roadmap” Exhibit SBT-A.1 that I described earlier.
15
16 Q. ARE YOU SPONSORING ALL COSTS CONTAINED IN EXHIBITS
17 SBT-A, SBT-B, SBT-C, AND SBT-D?
18 A. No. My Exhibits SBT-A, SBT-B, SBT-C, and SBT-D are an aggregation of
19 all the Exhibits A, B, C, and D for each affiliate witness in the Company’s
20 case. Although the affiliate witnesses have attached their Exhibits A, B, C,
21 and D to their direct testimony, it may be more convenient for the reviewer
22 to have a single copy of all these exhibits in one place to facilitate review
23 of the Company’s filing. I am a co-sponsor of these exhibits because
2011 ETI Rate Case 9-381
Entergy Texas, Inc. Page 36 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 these cost exhibits include the classes of costs I sponsor (that is, the
2 Depreciation, Service Company Recipient Offsets, and the Other
3 Expenses classes), the exclusions and pro forma adjustments (some of
4 which I sponsor) to the test year affiliate charges for all classes of costs,
5 and the application of the cost allocation methods to the PCs.
6
7 Q. HAVE YOU PREPARED ADDITIONAL WORKPAPERS SUPPORTING
8 EACH OF THE G-6 SCHEDULES?
9 A. Yes. I have prepared six different sorts of the G-6 schedules, which are in
10 addition to the required FERC account presentation contained in
11 Schedules G-6, G-6.1 and G-6.2. The Company is providing this
12 information in its direct filing in this case to facilitate an efficient, timely
13 review of the Company’s affiliate case.
14
15 Q. HAS THE COMPANY MADE THIS INFORMATION AVAILABLE IN
16 ELECTRONIC FORM?
17 A. Yes. As I explained above, Exhibit SBT-F is a compact disc that includes
18 this information. The Company has invoked Microsoft Excel’s “Auto Filter”
19 command in the spreadsheet files to help users find information quickly.
2011 ETI Rate Case 9-382
Entergy Texas, Inc. Page 37 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q. PLEASE DESCRIBE THE VARIOUS WORKPAPERS THAT THE
2 COMPANY HAS PREPARED IN CONNECTION WITH ITS SCHEDULES
3 G-6, G-6.1, AND G-6.2.
4 A. There are six variations of Schedules G-6, G-6.1, and G-6.2 included in
5 the workpapers to the G-6 schedules. They are:
6 1) Affiliate billings by billing entity to ETI by billing method and
7 project code (WP/G-6 (set 1); WP/G-6.1 (set 1); and WP/G-
8 6.2 (set 1));
9 2) Affiliate billings by billing entity to ETI by FERC account and
10 class (WP/G-6 (set 2); WP/G-6.1 (set 2); and WP/G-6.2 (set
11 2));
12 3) Affiliate billings by billing entity to ETI by class, project code,
13 and billing method (WP/G-6 (set 3); WP/G-6.1 (set 3); and
14 WP/G-6.2 (set 3));
15 4) Affiliate billings by billing entity to ETI by class, by FERC
16 account, project code, and billing method (WP/G-6 (set 4);
17 WP/G-6.1 (set 4); and WP/G-6.2 (set 4));
18 5) Affiliate billings by billing entity to ETI by FERC account,
19 project code, and billing method (WP/G-6 (set 5); WP/G-6.1
20 (set 5); and WP/G-6.2 (set 5)); and
21 6) Affiliate billings by billing entity to ETI by project code, billing
22 method, and FERC account (WP/G-6 (set 6); WP/G-6.1 (set
23 6); and WP/G-6.2 (set 6)).
24
25 Q. WHAT IS THE RELATIONSHIP BETWEEN EXHIBITS A, B, C, AND D
26 AND THE COMPANY’S G-6 SCHEDULES?
27 A. The G-6 schedules present the Company’s request for all affiliate billings,
28 for the test year, by FERC account and billing entity, as follows:
29 1) Schedule G-6 – Total ETI Adjusted amount of affiliate
30 billings,
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 2) Schedule G-6.1 – total per books affiliate billings (after
2 exclusions), and
3 3) Schedule G-6.2 – pro forma adjustments to affiliate billings.
4 The Commission’s RFP requires the G-6 schedules to be
5 presented by FERC account.
6 Exhibits A, B, and C present the same amounts that are in the
7 Schedules G-6, G-6.1, and G-6.2, but in various sorts of detail within each
8 class arranged in a way so that the witnesses can further show that the
9 costs meet the Commission’s affiliate standards. As stated previously, the
10 Company has sorted the amounts by department, by project code, and by
11 both department and project code in Exhibits A, B, and C, respectively.
12 Exhibit D presents for each class of services additional detail on the pro
13 forma adjustments included in Schedule G-6.2. With the use of the
14 workpaper set WP/G-6 (set 4), the reviewer can follow amounts in Exhibits
15 A through D through to the G-6 schedules, which are presented in the
16 required FERC account format. Thus, for example, the reviewer can trace
17 cost data related to a particular class to a FERC account, to a project
18 code, and to a billing method by referring to WP/G-6 (set 4). Similarly, if a
19 reviewer desired to determine what other types of projects or activities
20 were billed utilizing a particular billing method shown in a Company
21 witness’s Exhibit C, the reviewer need only turn to WP/G-6 (set 1) in order
22 to ascertain this information. I have prepared a chart illustrating how the
23 affiliate cost information fits together (see Exhibit SBT-13).
2011 ETI Rate Case 9-384
Entergy Texas, Inc. Page 39 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q. PLEASE EXPLAIN HOW ONE WOULD GET FROM YOUR COST
2 EXHIBITS TO THE G-6 SCHEDULES.
3 A. Note that the same process I will describe below can be used for any of
4 the Exhibits A through C. I will use as an example my Depreciation
5 Affiliate Class, which can be found on Exhibit SBT-A. To trace the data
6 into the G-6 schedules, one would first need to obtain the subtotals of the
7 class by billing entity. The subtotal in Column H (Total ETI Adjusted) of
8 $1,777,986 for billing entity ESI agrees with the workpaper set WP/G-6
9 (set 4), which is sorted by billing entity, class, FERC account, project
10 code, and billing method. The Depreciation Class is billed to various
11 FERC accounts, as seen on WP/G-6 (set 4). Each of these FERC
12 account totals for the Depreciation Class can be traced into workpaper set
13 WP/G-6 (set 2), which is sorted by billing entity, FERC account and then
14 by class. On WP/G-6 (set 2), each FERC account is subtotaled.
15
16 Q. HOW COULD A REVIEWER OBTAIN MORE DETAILED INFORMATION
17 ABOUT A PARTICULAR PROJECT CODE?
18 A. For each project code, a reviewer could “drill down” to a very detailed level
19 of information contained in the Project Summaries included in my Exhibit
20 SBT-E. The Project Summaries, which are supported by all witnesses of
21 classes that charged to a particular project code, are arranged in project
22 code order and are indexed by page number.
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q. WHAT INFORMATION IS INCLUDED IN EACH PROJECT SUMMARY?
2 A. Each Project Summary shows the following information for each project
3 code:
4  test year billings to ETI by FERC account;
5  test year billings to ETI by class of services;
6  a statement of the purpose of the project code;
7  the primary activities encompassed by the project code;
8  the products or deliverables resulting from the project code;
9 and
10  the billing method associated with the project code and a
11 justification for that billing method.
12
13 Q. HOW ELSE CAN THE PROJECT SUMMARIES BE USED AS A TOOL
14 FOR REVIEWING AFFILIATE DATA?
15 A. The Project Summaries can be used to trace project code data from the
16 Exhibits B and C into the G-6 Schedules. For example, Financial Services
17 Class costs related to Project Code F3PPF72700, entitled “Cognos
18 Reporting Support,” can be found on Exhibit SBT-B. The Total ETI
19 Adjusted amount for the Financial Services Class for this project is
20 $26,678 for the test year. From Exhibit B, one can obtain a good deal of
21 information about the services provided – billing method, project
22 description, Total ETI Adjusted amount, etc. For example, Billing Method
23 GENLEDAL is applied to Project Code F3PPF72700. If more detail is
24 required to verify why Billing Method GENLEDAL is appropriate, or which
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2011 Rate Case
1 other classes may have charged this project, or the types of activities
2 being provided, one could go to the index of Project Summaries included
3 with Exhibit SBT-E and locate the page number for the Project Summary
4 for Project Code F3PPF72700 (page 961 of Exhibit SBT-E). The FERC
5 account amounts for this PC can be traced into workpaper set 5 - billings
6 by FERC account, project code, and billing method (WP/G-6 (set 5),
7 WP/G-6.1 (set 5), and WP/G-6.2 (set 5)). On WP/G-6 (set 5), each FERC
8 account is subtotaled by billing entity, and this subtotal will agree to
9 Schedule G-6 for that FERC account.
10
11 VI. THE AFFILIATE BILLING PROCESS
12 Q. PLEASE DESCRIBE THE AFFILIATE TRANSACTIONS THAT
13 PRIMARILY AFFECT ETI’S COST OF SERVICE IN THIS APPLICATION.
14 A. Two categories of affiliate costs affected ETI’s cost of service for the test
15 year:
16  the cost of the services ESI provides that are directly billed
17 or allocated to ETI; and
18  charges from other Operating Companies and from ETI’s
19 other affiliates that are directly billed to ETI for services
20 rendered.
21 Exhibit SBT-14 depicts the relationship between affiliate costs and
22 ETI’s cost of service. To understand these categories of affiliate
23 transactions, it is important to understand the affiliate billing process.
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2011 Rate Case
1 Q. PLEASE DESCRIBE THE PROCESS USED BY THE ENTERGY
2 COMPANIES TO CHARGE AFFILIATES FOR SERVICES PROVIDED.
3 A. ESI and the other Entergy-affiliated companies use three mechanisms to
4 bill affiliates for services rendered: (1) project billings; (2) loaned resource
5 billings; and (3) co-owner billings. These mechanisms are included in the
6 affiliate billing process (“billing process”). Project billings are transactions
7 billed to affiliates for services rendered using PCs to determine how costs
8 should be billed to affiliates. Loaned resource billings are transactions
9 that bill charges directly to the Department and/or Business Unit that is the
10 recipient of the services provided. Loaned resource billings include
11 charges for the payroll applicable to “loaned” employees (for example line
12 crews from one Operating Company sent to assist another Operating
13 Company in storm restoration), transportation, and materials and supplies.
14 Co-owner billings include costs incurred by one affiliate for the operation
15 and maintenance of a jointly-owned plant, and subsequently transferred to
16 another affiliate based on their ownership. During the test year, EGSL
17 transferred costs to ETI related to the jointly-owned Nelson 6 plant using
18 the co-owner billing process. The co-owner billing process and the Nelson
19 6 billings are discussed more fully in the Direct Testimony of Company
20 witness Winfred W. Garrison. Service companies such as ESI typically bill
21 via project billings. Other affiliates can only use loaned resource billings
22 or co-owner billings when billing or transferring costs to an affiliate.
2011 ETI Rate Case 9-388
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2011 Rate Case
1 Q. PLEASE SUMMARIZE THE CONTROLS THAT HAVE BEEN
2 ESTABLISHED TO HELP ENSURE THAT BILLINGS TO AFFILIATES
3 PROPERLY REFLECT THE ACTUAL COST OF AN ITEM OR SERVICE.
4 A. There are several controls in place to help ensure that billings to affiliates
5 represent the actual costs of items or services provided to such affiliates.
6 These process controls include:
7  Multiple Approvals of PCs
8  Approval of Loaned Resource Billing Transactions
9  Co-owner Allocation Rules
10  Approval of Source Documentation
11  Budget Process Activities
12  Monthly Allocation Results and Billing Analysis
13  Authorization Required to Access Corporate Applications
14  Billing Analysis Review Team (“BART”) Monthly Reviews of
15 ESI Billings
16  Employee Training
17  Internal Reviews of Affiliate Transactions and Processes
18  External Reviews and Audits of Affiliate Transactions and
19 Processes
20  Sarbanes-Oxley Controls and Testing
21  FERC Compliance Controls and Testing
22  Affiliate Transactions Policy
23 Each of the controls is an integral part of a multi-faceted process
24 that is designed to bill the appropriate share of reasonable and necessary
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1 costs to the Operating Companies. A more detailed description of these
2 billing controls is included in Attachment 8 to my Exhibit SBT-15. Exhibit
3 SBT-15 is an exhibit that explains a number of different aspects of the ESI
4 billing process.
5
6 VII. ESI SERVICE BILLINGS
7 A. Overview of the ESI Billing Process
8 Q. PLEASE PROVIDE A BRIEF EXPLANATION OF YOUR EXHIBIT
9 SBT-15: “AFFILIATE BILLING PROCESS DISCUSSION.”
10 A. As I discussed earlier, ESI and the other Entergy-affiliated companies use
11 three mechanisms to bill affiliates for services rendered: (1) project
12 billings; (2) loaned resource billings; and (3) co-owner billings. These
13 mechanisms are included in the affiliate billing process, which is discussed
14 in detail in my Exhibit SBT-15, “Affiliate Billing Process Discussion.” For
15 further clarification, I have included nine attachments to Exhibit SBT-15:
16 1) SBT-15 Attachment 1 – Comparison of Affiliate Billing
17 Mechanisms Overview;
18 2) SBT-15 Attachment 2 – Affiliate Billings by Billing Type;
19 3) SBT-15 Attachment 3 – Project Code Set-Up and Use
20 Flowchart;
21 4) SBT-15 Attachment 4 – Guidelines for Completing a Project
22 Scope Statement;
23 5) SBT-15 Attachment 5 – The Service Company Billing
24 Process Flowchart;
25 6) SBT-15 Attachment 6 – ESI Billing Method Tables;
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2011 Rate Case
1 7) SBT-15 Attachment 7 –Billing Method Summary;
2 8) SBT-15 Attachment 8 – Affiliate Billing Process Controls;
3 and
4 9) SBT-15 Attachment 9 – Deloitte & Touche, LLP’s 2010
5 Independent Accountant’s Report on Applying Agreed-Upon
6 Procedures (dated June 23, 2011).
7
8 Q. PLEASE DESCRIBE THE ESI BILLING PROCESS.
9 A. As shown in Attachment 2 to Exhibit SBT-15, the vast majority of ESI’s
10 billings to ETI are project billings. In order to bill an affiliate for services
11 provided via a project billing, a transaction must have an assigned PC.
12 Each PC is assigned a single billing method that determines how costs
13 captured under the PC will be distributed. The billing method results in
14 either a “direct” billing (billed 100% to one affiliate) or an “allocation” to
15 multiple affiliates. When services are provided to multiple affiliates,
16 charges for services rendered by ESI are allocated using billing methods
17 based on FERC-accepted formulae.
18
19 Q. WHEN IS THE PROJECT CODE ASSIGNED TO A TRANSACTION?
20 A. The PC is assigned at the time the transaction is entered into a source
21 system (e.g., Time Entry System, Accounts Payable). The employee
22 submitting the charge is most familiar with the charge, and is responsible
23 for applying the correct PC to the transaction. In addition, the employee’s
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2011 Rate Case
1 budget coordinator may assist in determining the correct PC for a
2 specific cost.
3 In addition, several allocations, such as payroll and other loaders,
4 will create additional transactions. They will typically follow the PCs used
5 on the source transactions for which they are based.
6
7 Q. PLEASE DESCRIBE THE TIME ENTRY SYSTEMS USED BY THE
8 ENTERGY COMPANIES.
9 A. The Entergy Companies use both the PeopleSoft Time & Labor system
10 and the ESTER system for time entry. ESTER is the acronym for
11 “Entergy’s System for Time Entry and Reporting.” Both systems are
12 electronic time and attendance systems and are an important part of the
13 Entergy Companies’ cost and service tracking process. Employees or
14 timekeepers are responsible for populating electronic timesheets each pay
15 period with appropriate accounting codes, including PCs, and actual hours
16 worked, among other things. At the end of each pay period, the
17 employee’s supervisor is responsible for reviewing and approving the
18 timesheet data.
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Entergy Texas, Inc. Page 47 of 98
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2011 Rate Case
1 Q. PLEASE SUMMARIZE THE CONTROLS THAT ARE IN PLACE TO
2 ENSURE THE ACCURACY OF THE INFORMATION RECORDED ON
3 THE TIMESHEETS IN TIME & LABOR AND ESTER.
4 A. In addition to the individual responsibilities of employees and supervisors
5 described above, both the Time & Labor and ESTER systems have been
6 programmed with certain validation functionality (e.g., validity and
7 compatibility edits for the accounting code input data) and notification
8 procedures to alert the employee when accounting code values, including
9 PCs, are invalid, incompatible, or incomplete. Training on the Time &
10 Labor and ESTER systems is conducted within each department.
11 Assistance is also available through the payroll administrator and through
12 the Financial Processes Help Desk, also referred to as the Financial
13 Operations Center (“FOC”) Help Desk.
14 Each ESI employee is ultimately responsible for charging the costs
15 that he or she incurs to the appropriate PC, and thus appropriately billing
16 the companies receiving the services. As a guide, ESI Time and Expense
17 Training materials are posted on the Affiliate Accounting and Allocations
18 section of the Entergy Companies’ internal web. All ESI employees are
19 required to acknowledge their review of these training materials on an
20 annual basis. This training stresses the importance of choosing the
21 correct PC. It also discusses the role of billing methods in billing the
22 appropriate companies for services rendered, and emphasizes that direct
23 billing is preferred over allocating charges where possible. The training
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2011 Rate Case
1 also reviews how to determine which PC should be used for specific
2 services. These ESI Time and Expense Training materials are included
3 as Exhibit SBT-16.
4 As discussed earlier in my testimony, and as discussed in
5 Attachment 8 of Exhibit SBT-15, there are several other controls in place
6 to ensure that billings to affiliates properly reflect the actual cost of an item
7 or service.
8
9 Q. HOW ARE PROJECT CODES INITIATED AND MADE AVAILABLE FOR
10 USE?
11 A. As I previously mentioned, the Entergy Companies use a project costing
12 application (PowerPlant) that provides a single point of entry for all PCs.
13 When a particular department determines that a new project or service is
14 being initiated, PowerPlant is used by that department to set up the PC.
15 During set-up, the preparer of the PC request enters several elements to
16 establish a PC. The preparer provides a descriptive title for the PC and
17 determines the appropriate billing method, which may directly bill one
18 affiliate or allocate costs to multiple affiliates. The billing method is
19 determined based on cost causation principles for the particular project.
20 The preparer also describes the scope of the PC, including its overall
21 purpose, the primary activities to be performed, the products or
22 deliverables expected, and a justification of the billing method selected.
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2011 Rate Case
1 This scope, as well as all of the attributes associated with the PC, are
2 stored in PowerPlant and can be referenced by users as needed.
3 Exhibit SBT-15 includes a more detailed discussion of the project
4 billing process used by ESI. A breakdown of ESI’s billings by project code
5 is shown in Exhibit SBT-8.
6
7 Q. DOES THE AFFILIATE BILLING PROCESS ENSURE THAT THE COSTS
8 CHARGED BY ESI TO ETI ARE NO HIGHER THAN THE COSTS
9 CHARGED TO OTHER AFFILIATES FOR THE SAME OR SIMILAR
10 ACTIVITIES AND SERVICES?
11 A. Yes. The following features of the billing system help ensure that ESI
12 does not charge a higher unit cost to ETI than to other affiliates for the
13 same or similar activities and services:
14 1) ESI always bills its services to regulated companies at cost,
15 with no profit added, based on cost causation;
16 2) the billing method is selected based on the principle of cost
17 causation to ensure that every affiliate that causes the cost
18 in the PC is appropriately included in the allocation of costs;
19 and
20 3) because each PC has only one billing method associated
21 with it, all affiliates that receive the service are charged at
22 the same unit rate for a given PC; therefore, the cost for a
23 given unit of service is equal for all affiliates receiving the
24 service.
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2011 Rate Case
1 Q. HOW DOES THE AFFILIATE BILLING PROCESS ENSURE THAT THE
2 PRICE CHARGED BY ESI TO ETI REPRESENTS THE ACTUAL COST
3 OF SERVICES?
4 A. With respect to direct billings, because ESI charges no more than actual
5 costs for services provided to regulated companies, the price charged to
6 ETI represents the actual cost. With respect to allocated costs, because
7 ESI charges the regulated companies at cost and utilizes the principle of
8 cost causation in identifying a billing method, the unit price charged to ETI
9 represents the actual cost.
10
11 Q. DOES YOUR TESTIMONY INCLUDE A SUMMARY OF CONTROLS TO
12 ENSURE THE ACCURACY OF THE ESI AFFILIATE BILLINGS?
13 A. Yes. Those controls are generally summarized in the Affiliate Billing
14 Process section of my testimony. In addition, these controls are
15 discussed in more detail in Attachment 8 of Exhibit SBT-15.
16
17 Q. ARE THERE ANY REVIEWS OF THE CONTROLS OVER THE
18 ACTIVITIES AND SERVICES AND THE RELATED COSTS THAT ESI
19 PROVIDES?
20 A. Yes. Internal Audit reviews the controls and performs tests of transactions
21 and balances related to affiliate billings. Specifically related to the
22 implementation of the Sarbanes-Oxley Act, Internal Audit reviews the
23 risks, control activities, and testing of those control activities associated
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Entergy Texas, Inc. Page 51 of 98
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2011 Rate Case
1 with the affiliate billing process. Their review includes the related funding,
2 allocations, and intercompany account reconciliation processes
3 associated with the overall affiliate billing process.
4 In addition, external reviews and audits of affiliate transactions and
5 processes are conducted routinely. For instance, D&T performs certain
6 agreed upon procedures annually at the request of the Entergy
7 Companies to satisfy a requirement included in an October 1992
8 Settlement Agreement, as amended, between certain regulators and the
9 Entergy Companies that pertains to billings from affiliates to EEI. D&T
10 selects several intercompany transactions billed to EEI by affiliates to
11 ensure that they were billed in accordance with PUHCA 2005 affiliate
12 billing requirements. D&T’s “Independent Accountants’ Report on
13 Applying Agreed-Upon Procedures” for the year ended December 31,
14 2010, is included as Attachment 9 to Exhibit SBT-15.
15 In addition, the annual external audit of Entergy Corporation and its
16 subsidiaries’ financial statements performed by D&T helps to detect
17 whether the inter-company accounts and billing processes are producing
18 any material misstatements in the financial statements. The Sarbanes-
19 Oxley Act also requires that an independent auditor attest to the accuracy
20 of the Entergy Companies’ disclosure regarding the effectiveness of its
21 internal controls. In this connection, D&T also reviews risks, control
22 activities, and testing of control activities associated with the affiliate
23 billing processes.
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Entergy Texas, Inc. Page 52 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Further, in its oversight role under PUHCA 2005, the FERC is
2 authorized to conduct audits of Entergy service company transactions. As
3 discussed earlier in my testimony, the most recent FERC audit of the four
4 service companies, including ESI, covered the period January 2006
5 through December 2008.
6
7 Q. DO YOU HAVE ANY INDEPENDENT VERIFICATION THAT THE
8 CONTROLS ARE FUNCTIONING PROPERLY?
9 A. Yes. PwC performed an independent attestation examination of
10 management’s assertion on the presentation of costs billed by ESI and
11 other Entergy affiliates to ETI for the twelve-months ended June 30,
12 2011.15 PwC’s attestation examination included, among other things,
13 (1) consideration of controls surrounding the affiliate billing process;
14 (2) documentation included in the PC scope statements, including a
15 description of the PC’s use and purpose, the activities associated with that
16 particular project, the expected deliverables from activities in the project,
17 and justification for the billing method to be used for billing the costs
18 accumulated in the project; and (3) testing of affiliate service charges
19 billed during the test year for this docket.
15
Workpaper WP/SBT-4 includes ESI’s management assertion and PwC’s report in connection
with this attestation examination.
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2011 Rate Case
1 Q. PLEASE EXPLAIN WHAT YOU MEAN BY “PC SCOPE STATEMENTS.”
2 A. A PC scope statement is a narrative description of the work that is to be
3 undertaken to which each PC is assigned. The PC scope statements,
4 included as part of the Project Summaries in my Exhibit SBT-E, provide
5 information regarding the purpose of the project, the primary activities to
6 be undertaken under the project, the primary products or deliverables of
7 the project, the billing method that applies to the project, and the
8 justification for that billing method. I have discussed the contents of these
9 Project Summaries in more detail previously in my testimony.
10
11 Q. PLEASE SUMMARIZE YOUR UNDERSTANDING OF PWC’S
12 CONCLUSIONS RELATING TO AFFILIATE SERVICE CHARGES.
13 A. PwC’s independent attestation examination of management’s assertion on
14 the presentation of costs allocated by ESI and other affiliates to ETI
15 concluded that management’s assertion was fairly stated in all material
16 respects. Management asserted that ESI has allocated costs
17 accumulated in identified PCs on a cost causative basis using billing
18 methods that ensure accurate recording and billing of the costs associated
19 with the provision of the related services. Management further asserted
20 that billing methods used to allocate costs by ESI ensure that costs
21 charged to ETI reasonably approximate the actual costs of services
22 provided and are no higher than the costs charged to other affiliates for
23 similar services.
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q. PLEASE SUMMARIZE YOUR UNDERSTANDING OF PWC’S
2 CONCLUSIONS RELATING TO PC SCOPE STATEMENTS.
3 A. PwC concluded that management’s assertion regarding the PC scope
4 statements was fairly stated in all material respects, i.e., the PC scope
5 statements adequately described the project purpose, primary activities,
6 products or deliverables, and rationale for billing method assignment.
7
8 Q. DOES THE TOTAL ETI ADJUSTED AMOUNT ON THE G-6
9 SCHEDULES INCLUDE THE RECOMMENDATIONS MADE BY PWC AS
10 A RESULT OF ITS ATTESTATION EXAMINATION OF MANAGEMENT’S
11 ASSERTION ON THE PRESENTATION OF COSTS ALLOCATED BY
12 ESI AND OTHER AFFILIATES TO ETI?
13 A. Yes. The Total ETI Adjusted amount on the G-6 schedules reflects all of
14 the pro forma adjustments on Exhibit SBT-D. This exhibit includes various
15 adjustments due to PC billing method changes (Pro Forma Number AJ21-
16 04). The net effect of these adjustments is an increase in costs billed to
17 ETI of $7,368 which is included in the Total ETI Adjusted amount in test
18 year affiliate charges.
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 B. Summary of ESI Billings to Affiliated Companies
2 Q. WHAT WERE TOTAL BILLINGS FROM ESI TO THE AFFILIATED
3 COMPANIES DURING THE TEST YEAR?
4 A. ESI billed approximately $883 million to its affiliate companies during the
5 test year for services provided. The following exhibits to my testimony
6 contain schedules that present views of ESI billings to affiliates:
7  Exhibit SBT-8 - ESI Test Year Per Book Billings to Affiliates
8 by Project
9  Exhibit SBT-17 – Direct vs. Allocated ESI Test Year Per
10 Book Billings to Affiliates
11
12 Q. WHAT HAPPENS TO CHARGES THAT ARE BILLED BY ESI TO THE
13 OTHER SERVICE COMPANIES, SUCH AS EOI AND EEI?
14 A. After ESI bills another service company for services rendered, the billed
15 service company affiliate in turn bills the costs to its affiliates. For
16 instance, when ESI bills EOI for services rendered, EOI will bill one or
17 more of the regulated nuclear plants that it serves (e.g., EGSL’s River
18 Bend facility) for the cost. When ESI bills EEI for services rendered, the
19 costs are billed by EEI to one or more of its affiliates. No costs billed by
20 ESI to EOI and EEI are subsequently billed by those Business Units
21 to ETI.
2011 ETI Rate Case 9-401
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q. WHAT IS THE LEVEL OF CHARGES FROM ESI TO ETI DURING THE
2 TEST YEAR?
3 A. ESI billed ETI approximately $84 million during the test year, or
4 approximately 9.5% of ESI’s total billings to all affiliates during the test
5 year (as seen on Exhibit SBT-8). This figure is a total per book number,
6 which includes expense and capital amounts billed to ETI. After taking
7 into account exclusions and pro forma adjustments for ESI charges billed
8 to ETI, the Total ETI Adjusted number is approximately $69 million (the
9 remaining $10 million of the Total Requested amount relates to charges
10 from other Entergy affiliates).
11
12 Q. HAVE THERE BEEN ANY CHANGES TO THE ESI BILLING PROCESS
13 SINCE THE COMMISSION’S LAST REVIEW OF THE AFFILIATE
14 BILLING PROCESS IN DOCKET NO. 37744?
15 A. With the exception of the changes in the Service Company Recipient
16 allocation process discussed later in my testimony, there have been no
17 substantive changes to the ESI billing process since the Commission’s
18 last review of ETI’s rates in Docket No. 37744.
2011 ETI Rate Case 9-402
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 C. Billing Methods
2 1. Billing Method Overview
3 Q. IN SECTION VII.A ABOVE YOU DESCRIBED HOW A BILLING METHOD
4 CHOSEN FOR A PROJECT CODE ENSURES THAT ETI IS BILLED
5 ONLY THOSE COSTS ATTRIBUTABLE TO ETI. DO YOU HAVE AN
6 EXHIBIT THAT PROVIDES MORE INFORMATION REGARDING THE
7 BILLING METHOD ASSIGNMENT PROCESS?
8 A. Yes. As described in the billing process discussion in Exhibit SBT-15,
9 after the preparer of a PC request selects a billing method, it is reviewed
10 for reasonableness by both the intermediate approver of the PC and the
11 Affiliate Accounting and Allocations team that I oversee. If the billing
12 method selected does not appear to reflect cost-causation, the approver
13 may contact the preparer for clarification as to why the billing method was
14 chosen, or may reject the request until the billing method is adequately
15 justified or another billing method is selected to ensure that the billing
16 method is appropriate for the services provided under the PC.
17 Attachment 4 to Exhibit SBT-15 contains guidelines for preparing PC
18 scope statements, including the selection and justification of a cost-
19 causative billing method.
2011 ETI Rate Case 9-403
Entergy Texas, Inc. Page 58 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q. PLEASE EXPLAIN HOW ESI DEFINES “DIRECT” VERSUS
2 “ALLOCATED” BILLINGS.
3 A. ESI defines direct billings as those that are billed 100% to one affiliate.
4 Costs included in direct billings are incurred exclusively for the benefit of
5 one affiliate. ESI defines allocated billings as those that are distributed
6 using a formula that allocates costs to two or more affiliates. Costs
7 included in allocated billings are incurred for the benefit of more than
8 one affiliate.
9
10 Q. PLEASE DISTINGUISH BETWEEN THE TERMS “DIRECT,”
11 “ALLOCATED,” “INDIRECT,” AND “OVERHEAD.”
12 A. Each of these terms has been defined by ESI and the FERC. They are
13 also defined within the Service Agreements between ESI and its affiliates
14 that were accepted by the FERC in its December 12, 2006 order in
15 connection with ESI’s October 13, 2006 request for review and
16 acceptance of service company cost allocations. ESI’s definitions of the
17 terms “direct” and “allocated,” as used throughout this testimony, are
18 described in the preceding paragraph. These terms relate to how costs
19 are distributed – to one affiliate (direct), or to more than one affiliate
20 (allocated). The term “overhead” refers to costs that include (1) costs
21 necessary for the existence of ESI as an entity, and (2) costs that are
22 attributable to a department but aren’t related to any one specific project.
23 “Indirect” is a term used by ESI to also describe those costs that are
2011 ETI Rate Case 9-404
Entergy Texas, Inc. Page 59 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 attributable to the overall operation of a department and not to a specific
2 service. Exhibit SBT-18 is a chart showing how these terms are defined
3 by the three groups (ESI, the FERC, and the Service Agreements
4 accepted by the FERC) listed above.
5
6 Q. DOES ESI BILL DIRECTLY FOR SERVICES PROVIDED TO THE
7 REGULATED AFFILIATES WHENEVER APPROPRIATE?
8 A. Yes. The former SEC regulations required that service costs be billed
9 directly to an affiliate as long as such costs can be reasonably identified
10 as caused by an affiliate. Under PUHCA 2005, the FERC adopted this
11 “carryover” SEC provision.
12 However, it is important to note that the fundamental purpose of a
13 service company such as ESI is to achieve benefits from consolidation
14 and economies of scale for multiple companies. Therefore, the bulk of
15 ESI’s costs may necessarily be incurred to provide common services
16 required by multiple companies, which require an allocation of costs. For
17 example, there are several filings that are required by regulatory agencies
18 that include information for numerous affiliates. Because one filing often
19 serves multiple legal entities, the employees working on that document will
20 charge their time using a PC that employs an allocation factor that
21 represents a cost-causative relationship to the work performed.
22 Direct billings from ESI to ETI were 26.36% of ETI’s total charges
23 from ESI during the test year. Although each of the Operating Companies
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2011 Rate Case
1 received a similar mix between allocated and direct billings, ETI had the
2 second highest percentage of direct ESI billings of all Entergy Operating
3 Companies during the test year. Exhibit SBT-17 depicts the percentage of
4 direct versus allocated billings from ESI to each of the affiliates to which
5 ESI provides service.
6
7 Q. DOES ESI DIRECTLY BILL EEI FOR SERVICES PROVIDED TO EEI ON
8 BEHALF OF THE NON-REGULATED AFFILIATES WHENEVER
9 APPROPRIATE?
10 A. Yes. As noted above, the Operating Companies have similar operations,
11 which provide opportunities for consolidation of services provided to them
12 by ESI. Although the provision of similar services by a single provider
13 results in economies of scale, this often requires an allocation of costs
14 instead of direct charging. However, because Entergy Corporation’s
15 non-regulated subsidiaries require many services that are not similar to
16 those of the regulated utility Operating Companies, the non-regulated
17 companies are not likely to share as many “consolidated” services as the
18 regulated companies. Instead, because of the variation in requested
19 services provided to the non-regulated affiliates, direct billings to the non-
20 regulated affiliates occur more often than direct billings to the Entergy
21 Operating Companies. As shown on Exhibit SBT-17, direct billings to EEI
22 (which receives the majority of non-regulated billings and, in turn, bills the
23 appropriate subsidiary) represent 46.5% of the total billings by ESI to EEI.
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2011 Rate Case
1 As noted above, many services provided by ESI to non-regulated affiliates
2 are billed by ESI to EEI, rather than to the individual non-regulated
3 affiliates that receive those services. This does not mean, however, that
4 ESI is “underbilling” the non-regulated affiliates for the services they
5 receive. The billing methods applied to the project codes applicable to
6 these services ensure that the non-regulated affiliates are paying for their
7 applicable share of these costs (if allocated), or the full cost if the project
8 code direct bills the entire cost to EEI. Exhibit SBT-15 Attachment 6c
9 includes the statistics of each non-regulated company that were included
10 in calculating billing methods.
11
12 Q. DOES ESI EVER USE MORE THAN ONE BILLING METHOD FOR A
13 GIVEN PC?
14 A. No. Because each PC captures a specific service, each PC has only one
15 billing method assigned to it, and the billing method is selected to ensure
16 that every affiliate receiving the service also receives an appropriate
17 allocation. Therefore, the costs related to all services performed under a
18 PC that is not directly billed are allocated among affiliates using the same
19 criterion (such as number of accounts payable transactions or number of
20 customers). The use of a single billing method ensures that all affiliates
21 causing costs to be incurred and receiving the service pay an appropriate
22 proportion of the costs. This also ensures that the affiliates are, in total,
23 charged no more and no less than 100% of the costs for services provided
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2011 Rate Case
1 under the PC. Also, the use of a single billing method, which is assigned
2 based on cost causation principles, ensures that each affiliate is paying
3 the same per unit price for the same service, and that the prices charged
4 to ETI are no higher than the prices charged by ESI to the other affiliates
5 for similar services.
6
7 Q. AFTER THE COSTS OF ESI’S SERVICES ARE CAPTURED BY A PC,
8 HOW ARE COSTS ALLOCATED AMONG THE APPROPRIATE
9 COMPANIES?
10 A. One billing method is assigned to each PC for each service company.
11 Depending on the assigned billing method, the cost of services rendered
12 will be billed directly to a single affiliate or allocated among several
13 affiliates. Billing methods are based on allocation formulae. Under
14 PUHCA 2005, these allocation formulae must be reviewed and accepted
15 by the FERC. Each allocation formula is based on data relevant to the
16 affiliated companies.
17 There are approximately 50 formulae currently in use by ESI that
18 are used to derive billing methods. The FERC has reviewed and accepted
19 each of these formulae. Examples of these allocation formulae are: total
20 average number of customers, number of personal computers, and
21 transmission line miles.
22 One allocation formula may be the basis of several billing methods
23 used in the project billing process. For example, ESI has several billing
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2011 Rate Case
1 methods that use the total number of customers allocation formula,
2 including: Billing Method CUSEOPCO, based on average electric
3 customers for the utility Operating Companies; and Billing Method
4 CUSTEGOP, based on average electric and gas customers for the utility
5 Operating Companies. Billing methods that use a common basis for
6 allocation, such as those mentioned above, are referred to collectively as
7 a “billing method family.” Attachment 6b to Exhibit SBT-15 provides the
8 billing methods used during the test year. This exhibit includes each
9 billing method, the title of each billing method, and the percentage of total
10 costs allocated to each affiliate for each billing method.
11
12 Q. PLEASE SUMMARIZE HOW THE BILLING METHODS WORK.
13 A. Services that are provided by ESI to only one affiliate are billed using
14 direct billing methods, which by definition bill only one affiliate. Services
15 that are provided to more than one affiliate are allocated in accordance
16 with formulae reviewed and accepted by FERC. As previously discussed,
17 billing methods that distribute costs using these formulae are often termed
18 allocation methods. There were 179 direct and allocated billing methods
19 derived from FERC-accepted formulae in order to bill ESI affiliate costs to
20 the affiliated companies during the test year. Of these billing methods,
21 approximately 40% are direct billing methods (one billing method for each
22 business unit ESI serves directly), and the remainder represent variations
23 of the allocation formulae, as discussed above. However, as noted on
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2011 Rate Case
1 Attachment 7 of SBT-15, only 74 of the 179 ESI billing methods were used
2 to bill costs to ETI during the test year as reflected in the Total ETI
3 Adjusted amount.
4
5 2. Billing Method Calculations
6 Q. WHAT ARE THE ESI ALLOCATION BILLING METHODS (“ALLOCATION
7 METHODS”) THAT WERE USED TO BILL COSTS FOR SERVICES TO
8 ETI DURING THE TEST YEAR?
9 A. Exhibit SBT-19 is a chart that includes each ESI allocation method that
10 was used to bill costs to ETI during the test year. The chart provides the
11 billing method number, the billing method family to which each method is
12 associated, the basis on which the method is calculated, and the types of
13 costs that are allocated using each method.
14
15 Q. DID ESI USE ANY ALLOCATION METHODS TO ALLOCATE COSTS TO
16 ETI DURING THE TEST YEAR OTHER THAN THOSE INCLUDED IN
17 EXHIBIT SBT-19?
18 A. No.
19
20 Q. PLEASE DESCRIBE HOW EACH ALLOCATION METHOD EMPLOYED
21 BY ESI DURING THE TEST YEAR IS CALCULATED.
22 A. Each allocation method is calculated by taking each business unit’s pro
23 rata share of the cost driver statistics (such as number of accounts
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2011 Rate Case
1 payable transactions or number of employees). For each allocation
2 method, Attachment 6 of Exhibit SBT-15 includes the percentages
3 allocated to each affiliate as well as the statistics used to come up with
4 those percentages. For Attachment 6b, all non-regulated percentages
5 and statistics are included in the “EEI” column. Attachment 6c was
6 prepared to provide the individual non-regulated companies included in
7 the statistics for “EEI.”
8 Previously required by the SEC under PUHCA 1935 and now
9 recognized by FERC under PUHCA 2005, all ESI services to ETI are
10 billed at cost. The specific billing method chosen for a particular type of
11 charge is selected to provide an appropriate matching of costs with the
12 cost drivers. Every affiliate that causes the cost and receives the service
13 provided is included in the cost allocation.
14
15 D. Service Company Recipient Allocation (also referred to as Shared
16 Services Loader)
17 Q. DOES THE ESI AFFILIATE BILLING PROCESS INCLUDE A
18 MECHANISM THAT CAPTURES AND ALLOCATES THE COSTS
19 ASSOCIATED WITH SERVICES THAT ESI PROVIDES TO ITSELF?
20 A. Yes. In addition to being the provider of services to affiliates, ESI also
21 provides services to itself so that it, in turn, can provide services to its
22 affiliates. Therefore, under cost causation billing, ESI is also a receiver of
23 costs associated with the services it provides. The mechanism that
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2011 Rate Case
1 allocates the costs associated with the services ESI receives is currently
2 known as the “Service Company Recipient Allocation.” This allocation is
3 actually comprised of several types of costs, including information
4 technology, desktops and telephones (discussed more specifically by
5 Company witness Julie F. Brown), facilities-related costs such as rents
6 and space management (discussed more specifically by Company witness
7 Thomas C. Plauché), Human Resources-related costs (discussed more
8 specifically by Company witness Kevin G. Gardner), and the like.
9
10 Q. HOW DOES ESI CAPTURE THE COSTS ASSOCIATED WITH ESI
11 SERVICES RECEIVED?
12 A. ESI captures the costs associated with ESI services received by including
13 ESI as one of the legal entities to which ESI costs may be billed.
14 Examples of cost causative allocation methods of which ESI is a recipient
15 are APTRNALL (Accounts Payable Transactions), GENLEDAL (General
16 Ledger Transactions), and PRCHKALL (Payroll Checks Issued). Because
17 ESI creates Accounts Payable (“AP”) invoices, has its own General
18 Ledger (“GL”) transactions, and has employees who receive payroll
19 checks, a portion of the costs are caused by ESI. Also, like other
20 affiliates, ESI may directly bill costs to itself for services solely caused by
21 ESI using a direct billing method. Examples of costs that may be directly
22 billed to ESI are office supplies, professional fees, and rent associated
23 with ESI employees only.
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2011 Rate Case
1 Q. WHERE DOES ESI RECORD THE COSTS ASSOCIATED WITH ESI
2 SERVICES THAT ARE BILLED TO ESI?
3 A. During the PC billing process, all ESI expenses billed to ESI are deferred
4 on the balance sheet using a clearing account (Account 184SSL). In
5 particular, all of the costs received by ESI in the PC billing process are
6 assigned to Account 184SSL and further separated by the following
7 functions: Information Technology, Support – Operations, Support –
8 Corporate, Supply Power – Nuclear, and President/CEO.
9
10 Q. HOW ARE THE COSTS ACCUMULATED IN ACCOUNT 184SSL
11 ALLOCATED?
12 A. A second-tier allocation called Service Company Recipient Allocation
13 clears the Account 184SSL balance and distributes the costs to the
14 affiliates that are using the services of ESI employees. This is also
15 consistent with cost causation principles. It is appropriate to bill
16 companies a pro-rata share of ESI costs based on the amount and type of
17 ESI services they receive because the demand for ESI services drives the
18 costs associated with ESI.
19
20 Q. PLEASE DESCRIBE THE SERVICE COMPANY RECIPIENT
21 ALLOCATION PROCESS.
22 A. During the PC billing process, both the “pool” and “basis” for the Service
23 Company Recipient Allocation are created. The pool is the portion of
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2011 Rate Case
1 monthly costs associated with services received by ESI, which occurs
2 when ESI bills itself. Such costs within this pool are identified by function.
3 The basis is the total monthly labor billings to each affiliate to which ESI
4 provides services in a given month. Such billings are also identified by
5 function. Thus, a loader rate for each function can be calculated.
6
7 Q. HOW IS THE LOADER RATE CALCULATED?
8 A. The loader rate for each function is determined by dividing the total
9 amount of costs in the pool for a function for that month by the total
10 amount of labor billings (the basis) to affiliates for each function for the
11 same month. Though typically stable, the monthly loader rates may vary
12 as the functional pool and basis vary. The loader rate then is applied to
13 labor billing results to distribute the costs in the pool. The Affiliate
14 Accounting and Allocations group reviews the pool and basis amounts
15 monthly to ensure that they are reasonable.
16
17 Q. PLEASE PROVIDE AN EXAMPLE OF THE SERVICE COMPANY
18 RECIPIENT ALLOCATION PROCESS.
19 A. In the following example, the Human Resources (“HR”) department
20 provides staffing services to the Fossil organization. The HR employees
21 assign their time to a PC that bills based on the number of fossil-fueled
22 generation plant (“Fossil”) employees within each Entergy Corporation
23 subsidiary. Because ESI has Fossil employees, ESI receives a portion of
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2011 Rate Case
1 the billing, which is assigned to the 184SSL account. This is classified as
2 an overhead cost for ESI Fossil employees. During the same billing
3 process, ESI Fossil employees bill their labor out to those companies
4 receiving their services via the billing method assigned to each PC used.
5 Once the PC billing process described above is complete, the
6 Service Company Recipient Allocation begins. In this second-tier
7 allocation, the total dollar amount that was billed to ESI for services
8 provided to ESI Fossil employees by Human Resources (contained within
9 the Support-Corporate pool) is distributed to the labor amounts that were
10 billed by the ESI Fossil group (the basis), thereby loading the Fossil
11 organization’s labor billings with their share of service company
12 recipient charges.
13
14 Q. WHY DOES ESI USE THIS TWO-TIERED APPROACH FOR BILLING?
15 A. The two-tiered approach is used to ensure that all the costs (both
16 overhead and direct) are paid for by the affiliates that cause the costs. It
17 is important that ETI be able to determine the total cost associated with its
18 projects and services. The Service Company Recipient Allocation
19 ensures that overheads associated with managing each ESI function are
20 loaded to the projects to which those functional employees charged their
21 time. This enables each project to be fully-loaded with both the direct
22 costs assigned to the project as well as service company
23 recipient charges.
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2011 Rate Case
1 Q. HAVE THERE BEEN ANY CHANGES IN THIS PROCESS SINCE THE
2 COMMISSION’S LAST REVIEW IN DOCKET NO. 37744?
3 A. Yes. The Service Company Recipient Allocation’s basis was adjusted in
4 January 2010 to include not only labor billings to ESI affiliates, but also
5 labor costs that remain at ESI such as capital or other balance sheet items
6 maintained at ESI. Prior to the change, the basis included only labor
7 billings to affiliates from ESI. As a result of the change, ESI-owned capital
8 projects (not included in cost of service) are loaded with the service
9 company recipient charges as well. In addition, beginning in January
10 2010, the number of functional rates was changed from sixteen to five.
11 This change was implemented to streamline the process so that internal
12 customers could more easily analyze and predict their service company
13 recipient costs.
14
15 E. Payroll Loaders
16 Q. WHAT ARE PAYROLL LOADERS?
17 A. Payroll loaders allocate payroll-related costs, specifically payroll taxes,
18 employee benefits, post-employment benefits, stock options, certain
19 incentive compensation, and paid time off. Each of these costs has its
20 own loader. These payroll-related costs are loaded to projects so that
21 each project is fully-loaded with both the direct labor costs and the
22 associated payroll loaders.
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2011 Rate Case
1 Q. PLEASE SUMMARIZE THE PAYROLL LOADERS PROCESS.
2 A. The Human Resources department provides Affiliate Accounting and
3 Allocations with base standard rates for employee benefits, post-
4 employment benefits, and stock options, while the Compensation and
5 Benefits Design department provides the base standard rates for
6 incentives. These base standard rates are based on total payroll. The
7 base standard rate for payroll taxes is calculated by the Affiliate
8 Accounting and Allocations group based on payroll taxes paid during the
9 prior year as a percentage of the total payroll paid during the prior year.
10 Because payroll allocations load only on productive payroll rather than
11 total payroll, the Affiliate Accounting and Allocations group adjusts these
12 base standard rates by productive factors to generate actual loader rates.
13 The actual loader rate for paid time off is also calculated by the Affiliate
14 Accounting and Allocations group based on the percentage of non
15 productive payroll to productive payroll.
16 The loader rates for employee benefits, post-employment benefits,
17 stock options, incentives, and paid time off are applied to productive
18 straight-time payroll (excluding overtime). The loader rate for payroll taxes
19 is applied to total productive payroll (including overtime). All loaders are
20 assigned the same PC as the labor, so that they properly follow the same
21 billing distribution as the labor dollars on which they are based. As I
22 explained earlier in my testimony, each PC is assigned one billing method
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2011 Rate Case
1 that will most appropriately allocate the charges to the companies
2 receiving the services based on cost-causation principles.
3
4 Q. HOW OFTEN ARE LOADER RATES REVIEWED AND ADJUSTED, IF
5 NEEDED?
6 A. The loader rates for payroll taxes, employee benefits, post-employment
7 benefits, stock options, incentives, and paid time off, are reviewed for
8 reasonableness by the Affiliate Accounting and Allocations group on a
9 quarterly basis and adjusted, or trued-up, on an annual basis.
10
11 Q. HAVE THERE BEEN ANY CHANGES IN THIS PROCESS SINCE THE
12 COMMISSION’S LAST REVIEW IN DOCKET NO. 37744?
13 A. Yes. In Docket No. 37744 (test period including the twelve months ended
14 June 30, 2009) the payroll loaders included employee benefits, post-
15 employment benefits, incentives, payroll taxes, and paid time off. The
16 post-employment benefits loader was comprised of payroll related costs
17 associated with stock options, pensions, and other post-employment
18 benefits. In July 2010, the payroll related costs associated with stock
19 options were separated into its own payroll loader. The stock option
20 payroll loader was created to identify those costs with a separate, unique
21 resource code. The post-employment benefits loader now excludes the
22 payroll related costs associated with stock options.
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 VIII. OTHER AFFILIATE BILLINGS
2 Q. BESIDES ESI, WHICH ENTERGY COMPANIES BILLED ETI FOR
3 SERVICES RENDERED DURING THE TEST YEAR?
4 A. Each of the Operating Companies billed ETI for services rendered. There
5 are several reasons for the Operating Companies to provide services to
6 one another. For instance, materials from the storeroom of one Operating
7 Company are often transferred to another. Also, one Operating Company
8 may assist another in an emergency situation, such as during a storm and
9 subsequent storm restoration. An Operating Company affiliate can also
10 transfer a percentage of the operating costs of a shared plant to another
11 Operating Company affiliate through the co-owner billing process. As
12 noted previously, during the test year, EGSL transferred operating costs to
13 ETI related to the jointly-owned Nelson 6 plant. In addition, certain of
14 Entergy Corporation’s non-regulated affiliates also loaned services to ETI.
15 These services primarily relate to loaned labor and material transfers.
16 The following exhibits provide a listing of test year per book billings
17 by project/activity code for each Operating Company to its affiliates and for
18 non-regulated affiliates to the regulated affiliates:
19  Exhibit SBT-20 – Entergy Arkansas Billings to Affiliates;
20  Exhibit SBT-21 – Entergy Gulf States Louisiana Billings to
21 Affiliates;
22  Exhibit SBT-22 – Entergy Louisiana Billings to Affiliates;
23  Exhibit SBT-23 – Entergy Mississippi Billings to Affiliates;
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1  Exhibit SBT-24 – Entergy New Orleans Billings to Affiliates;
2 and
3  Exhibit SBT-25 – Entergy Non-Regulated Affiliates Billings to
4 Regulated Affiliates
5
6 IX. SPONSORED CLASSES OF AFFILIATE COSTS
7 A. Overview
8 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?
9 A. I sponsor the following three classes of affiliate costs:
10 (1) Depreciation. The Depreciation Class includes the cost for
11 the depreciation and amortization of ESI assets. These
12 assets are used by ESI in the provision of services to its
13 affiliate companies;
14 (2) Service Company Recipient Offsets. The Total ETI Adjusted
15 amount for the Service Company Recipient Offsets Class is
16 zero. This class is set up for Accounting purposes only; and
17 (3) Other Expenses. The Other Expenses Class primarily
18 includes payroll-related costs that have not yet been loaded
19 to individual departments, the credit ETI received from the
20 5% upcharge to the non-regulated affiliates, and other
21 miscellaneous costs not associated with other specific
22 classes.
23 As shown on my Exhibits SBT-5 and SBT-6, these three classes
24 are in the Accounting Entries function, which is included in the Corporate
25 Support family.
26
27 Q. WITH REGARD TO THE THREE CLASSES THAT YOU SPONSOR, DO
28 THE BILLINGS PROVIDED TO ETI DURING THE TEST YEAR MEET
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 THE COMMISSION STANDARDS FOR INCLUSION OF SUCH COSTS
2 IN RATES?
3 A. Yes. The billings to ETI during the test year in the three classes of costs
4 that I sponsor meet the Commission standards for inclusion of such costs
5 in rates (noting, again, that there are no costs from the Service Company
6 Recipient Offsets Class included in the Total ETI Adjusted amounts in this
7 case). Specifically:
8 1. The charges billed to ETI during the test year were
9 reasonable and necessary for the operation of ETI.
10 2. The amount charged to ETI through the PC billing process,
11 the co-owner billing process, and the loaned resource billing
12 process for each cost or class of costs during the test year
13 are no higher than the amount charged to the other affiliates
14 or non-affiliated persons for these classes of costs.
15 3. The amounts charged to ETI during the test year represent
16 the actual costs of services provided to ETI.
17 4. As with all other classes of affiliate costs, expenses that are
18 not allowed for ratemaking purposes are included in the
19 billed expenses, but are excluded from the Total ETI
20 Adjusted amount as below-the-line expenses in accounts
21 such as Account No. 426, and/or are included in the pro
22 forma adjustments shown on Schedule G-6.2, and,
23 therefore, are not included in cost of service.
24 5. The items charged to ETI are not duplicative of items already
25 provided by or for ETI.
2011 ETI Rate Case 9-421
Entergy Texas, Inc. Page 76 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 B. Depreciation Class
2 1. Description of Class
3 Q. PLEASE BRIEFLY DESCRIBE THE DEPRECIATION CLASS OF
4 AFFILIATE COSTS.
5 A. This class represents the cost of depreciation and amortization of ESI
6 assets. These assets are used by ESI for the provision of services to its
7 affiliate companies.
8
9 Q. WHAT IS THE TOTAL ETI ADJUSTED AMOUNT FOR THIS CLASS OF
10 SERVICES?
11 A. As shown in Exhibits SBT-A, SBT-B, and SBT-C, the Total ETI Adjusted
12 amount for this class of services is $1,777,986. Of this amount, ESI
13 directly billed 27% of the amount, and allocated 73% of the amount, to
14 ETI. The following table summarizes this information for the Depreciation
15 Class. The table shows for each class the following information:
2011 ETI Rate Case 9-422
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
Total Billings Dollar amount of total Test Year billings and
charges from ESI to all Entergy Business
Units, plus the dollar amount of all other
affiliate charges to ETI that originated from
any Entergy Business Unit. This is the
amount from Column (C) of the cost exhibits
SBT-A, SBT-B, and SBT-C.
Total ETI Adjusted ETI’s adjusted amount for electric cost of
service after pro forma adjustments and
exclusions.
% Direct Billed The percentage of the ETI adjusted test year
amount that was billed 100% to ETI.
% Allocated The percentage of the ETI adjusted test year
amount that was allocated to ETI.
Total ETI Adjusted
Class Total Billings Amount % Direct % Allocated
Depreciation $26,406,546 $1,777,986 27% 73%
1 Q. PLEASE DESCRIBE THE EXHIBITS THAT SUPPORT THE
2 INFORMATION INCLUDED IN THE TABLE ABOVE.
3 A. Please see Exhibits SBT-A, SBT-B, and SBT-C, which I described above
4 in connection with my affiliate overview presentation. For each of these
5 exhibits, the amounts in the columns represent the following information:
2011 ETI Rate Case 9-423
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
Column (A) – Dollar amount of total Test Year billings and
Support charges from ESI to all Entergy Business Units,
plus the dollar amount of all other affiliate
charges to ETI that originated from any Entergy
Business Unit.
Column (B) – Dollar amount that was included in the service
Service Company company recipient allocation. Service company
Recipient recipient charges are the cost of services that
ESI provides to itself, which in turn are charged
to affiliates that receive those services. The
service company recipient allocation process is
described earlier in my testimony.
Column (C) – Represents the sum of Columns (A) and (B).
Total
Column (D) – That portion of Column (C) that was billed and
All Other BU’s charged to Business Units other than ETI.
Column (E) – Represents the difference between Columns (C)
ETI Per Books and (D).
Column (F) – Represents amounts that are excluded from ETI
Exclusions electric cost of service. The exclusions are
described in my testimony.
Column (G) – Pro Forma Amounts include adjustments for
Pro Forma Amount known and measurable changes, and
corrections.
Column (H) – ETI adjusted amount requested for recovery in
Total ETI Adjusted this case for this class (Column (E) plus
Columns (F) and (G)).
1 I have explained the adjustments with respect to Column F
2 (Exclusions) and Column G (Pro Forma Amount) earlier in my testimony.
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q. ARE THERE ANY PRO FORMA ADJUSTMENTS TO THIS CLASS?
2 A. Yes. The pro forma adjustments for the Depreciation Class are shown on
3 Exhibit SBT-D, which also indicates the Company witnesses who sponsor
4 those pro forma adjustments, and lists the pro forma adjustments by
5 account. As indicated on Exhibit SBT-D, I sponsor three pro forma
6 adjustments to the Depreciation Class. Exhibit SBT-12 describes the pro
7 forma adjustments to the Depreciation Class in greater detail.
8
9 2. Necessity
10 Q. WHAT KINDS OF ASSETS ARE OWNED BY ESI THAT RESULT IN THE
11 DEPRECIATION THAT IS THEN CHARGED TO THE AFFILIATE
12 COMPANIES?
13 A. In order to provide services to its affiliate companies, ESI must invest in
14 certain depreciable assets to support its operations. These assets consist
15 primarily of computer equipment, computer software systems,
16 communications equipment, furniture, fixtures, leasehold improvements,
17 and aircraft. However, a pro forma adjustment was made to remove
18 Company aircraft costs, including depreciation on aircraft, from the
19 Company’s cost of service.
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q. PLEASE DESCRIBE HOW THE DEPRECIATION OF ESI’S ASSETS IS
2 CALCULATED.
3 A. The purpose of depreciation is to distribute the cost of an asset over its
4 expected useful life. Total depreciation expense over the life of an asset
5 is equal to the asset’s cost (less any proceeds realized upon disposal).
6 ESI uses the straight-line method to calculate the annual depreciation
7 expense for its assets. Use of this depreciation method results in the cost
8 of an asset being distributed evenly over the expected useful life of the
9 asset. For example, an asset costing $1,000 that has an expected service
10 life of 10 years would result in depreciation expense for this asset of $100
11 per year for a period of 10 years ($1,000 divided by 10 years = $100 per
12 year or 10% a year). This method of calculating depreciation is
13 appropriate under generally accepted accounting principles. The straight-
14 line method is also the most commonly used and accepted depreciation
15 method. According to an American Institute of Certified Public
16 Accountants survey of 544 companies in 2009, 89% use the straight-line
17 method of depreciation versus other methods, which are primarily
18 accelerated methods of depreciation.16 Exhibit SBT-26 is a summary of
19 ESI’s assets, including plant in service, accumulated depreciation, net
20 plant, and the service life used to calculate depreciation.
16
American Institute of Certified Public Accountants (AICPA); Accounting Trends &
Techniques – 2010.
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q. PLEASE EXPLAIN WHY THE DEPRECIATION COSTS BILLED TO ETI
2 ARE NECESSARY.
3 A. ESI requires certain assets to support the operations that provide services
4 to its affiliates, including ETI. The depreciation cost is the result of
5 distributing the cost of these assets over their expected service lives to the
6 recipients of the services provided by ESI. These assets enable ESI to
7 provide the services required by its affiliates, including ETI, in the most
8 efficient, effective, and reliable manner possible. Without such assets to
9 support its operations, ESI could not provide the services that are required
10 by its affiliates, including ETI. Depreciation of those assets is a necessary
11 and proper component of the cost of owning and using the assets to
12 provide services.
13
14 3. Reasonableness
15 Q. HAVE YOU REVIEWED THE DEPRECIATION EXPENSE TO
16 DETERMINE WHETHER THE CHARGES WERE REASONABLE?
17 A. Yes. The charges to ETI for the costs I sponsor are reasonable for the
18 operation of ETI because the method of calculating depreciation
19 (straight-line method) is appropriate under generally accepted accounting
20 principles and is the most common method used. In addition, the price
21 charged by ESI to ETI for this item represents the actual cost of this item.
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2011 Rate Case
1 Q. WHAT OBJECTIVE SOURCES SUPPORT YOUR OPINION THAT THE
2 DEPRECIATION COSTS BILLED BY ENTERGY SERVICES TO ETI ARE
3 REASONABLE?
4 A. Exhibit SBT-27 is a benchmarking study prepared under my supervision
5 that compares the dollar amount of assets per employee for ESI to the
6 dollar amount of assets per employee for other PUHCA 2005 service
7 companies. This measure, cost of assets per employee, is appropriate
8 because employees drive the need for assets in service companies.
9 Because the number of employees would be the primary determinant of
10 the level of the assets that would be required, assets per employee is a
11 valid measure. Exhibit SBT-27 compares the service company property
12 per employee of ESI to the service company property per employee of six
13 other PUHCA 2005 service companies with at least $100 million of service
14 company property as of December 31, 2010. This exhibit shows ESI’s
15 cost of assets per employee, while slightly higher than the average, is
16 reasonable compared to that of the other PUHCA 2005 service
17 companies. This comparison is based on service company headcount
18 information contained in the respective corporate Forms 10-K and service
19 company property information contained in each service company’s FERC
20 Form 60 Annual Report for the period ending December 31, 2010.
21 However, the service company property for Southern Company
22 Services, Inc., Entergy Services, Inc., Exelon Business Services
23 Company, and American Electric Power Service Corporation on Exhibit
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 SBT-27 differs from what was reported on the companies’ 2010 FERC
2 Form 60s. These were the only companies that included Transportation
3 Equipment in their Service Company Property. Beginning with the FERC
4 Form 60 Annual Report for the period ending December 31, 2008, the
5 service company property category “Aircraft and Airport Equipment” was
6 eliminated and included in “Transportation Equipment.” A pro forma
7 adjustment was made (AJ21-01) to remove Company aircraft costs from
8 the Company’s cost of service. Therefore, to be consistent with the costs
9 included in this case, the Transportation Equipment was removed from the
10 total Service Company Property for all companies before the
11 benchmarking study was completed. Because the benchmarking study
12 supports the reasonableness of the level of assets being depreciated, and
13 the procedures used to depreciate the assets are appropriate and
14 consistent with well accepted accounting practices, the ultimate level of
15 depreciation is likewise reasonable.
16 With the exception of depreciation on aircraft, ESI distributes the
17 costs associated with the depreciation and amortization of ESI assets
18 based on the labor cost billed to each affiliate. Distributing ESI’s
19 depreciation and amortization costs in this manner is an appropriate
20 allocation of these costs because ESI employee labor is a reasonable
21 measure of the level of services provided by ESI employees to affiliates,
22 and employees and the services they provide drive the need for the assets
23 utilized by ESI in its operations. Depreciation on aircraft is included as a
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Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 component of total flight costs of ESI aircraft. Flight costs are charged to
2 specific PCs based on the PC(s) associated with the ridership and
3 purpose of a particular flight. However, as noted above, a pro forma
4 adjustment was made to remove Company aircraft costs, including
5 depreciation on aircraft, from the Company’s cost of service.
6
7 4. How Costs are Charged
8 Q. DO THE DEPRECIATION COSTS CHARGED BY ENTERGY SERVICES
9 TO ETI UNDER THIS CLASS REASONABLY APPROXIMATE THE
10 COSTS OF THOSE ITEMS?
11 A. Yes. The depreciation costs charged are based on the actual costs of the
12 assets supporting ESI’s operations and do not include any profit
13 or markup.
14
15 Q. IS THE PRICE CHARGED TO ETI FOR DEPRECIATION NO HIGHER
16 THAN THE PRICE CHARGED TO OTHER AFFILIATES?
17 A. Yes. The price charged to ETI is no higher than the price charged by ESI
18 to the other affiliates for depreciation on a per unit basis. With the
19 exception of depreciation on aircraft, ESI depreciation expense is loaded
20 onto each ESI labor dollar, and then billed out to affiliates. The
21 depreciation loader is assigned the same PC as labor, so that it properly
22 follows the same billing distribution as the labor dollars on which it is
23 based. As explained in my testimony, each PC is assigned one billing
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2011 Rate Case
1 method that will most appropriately allocate the charges to the companies
2 receiving the services based on cost-causation principles. Thus,
3 depreciation cost is billed to each affiliate at the same rate for each dollar
4 of labor charged, ensuring that costs are equitably distributed to
5 each affiliate.
6
7 Q. HOW ARE THE COSTS OF THIS CLASS CAPTURED AND BILLED TO
8 ETI?
9 A. With the exception of depreciation on aircraft, the cost associated with this
10 class is initially captured in Project Code F5PCZUDEPX, Depreciation and
11 Amortization, and then these costs are distributed directly to ESI PCs
12 based on the labor charged to the project codes. The receiving PCs then
13 bill the depreciation costs (along with all other costs charged to the PC) to
14 ESI’s affiliates based on the assigned billing method for each project.
15 During the test year, projects receiving depreciation costs billed
16 $1,777,986 Total ETI Adjusted, which includes pro forma adjustments, to
17 ETI. Exhibit SBT-B shows the costs included in this class by project code.
18
19 Q. WHAT BILLING METHOD IS USED TO ALLOCATE THIS EXPENSE
20 ITEM TO THE VARIOUS ENTITIES THAT RECEIVE SERVICES FROM
21 ESI?
22 A. As noted, with the exception of depreciation on aircraft, ESI assigned
23 depreciation costs to projects based on labor charged to projects and then
2011 ETI Rate Case 9-431
Entergy Texas, Inc. Page 86 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 billed these costs to affiliates based on the billing method assigned to
2 each project. The use of assets required to support ESI employee service
3 functions results in the depreciation and amortization cost. Labor charged
4 to projects is an appropriate allocation for this cost because ESI employee
5 labor is a reasonable measure of the level of services provided by ESI
6 employees to affiliates. This process distributes the depreciation and
7 amortization of assets necessary for the ESI employees to provide
8 services to its affiliates in a manner consistent with the distribution of ESI
9 labor to the affiliates that receive services.
10
11 C. Service Company Recipient Offsets (also referred to as Shared Services
12 Loader Offsets)
13 1. Description of Class
14 Q. PLEASE BRIEFLY DESCRIBE THIS CLASS OF AFFILIATE COSTS.
15 A. This class represents the corresponding credit to Service Company
16 Recipient Allocation transactions. As discussed earlier in my testimony,
17 the Service Company Recipient Allocation is the mechanism by which the
18 costs of services provided by ESI employees to operate ESI that are
19 initially billed to ESI through the PC billing process are distributed to ESI’s
20 affiliates in a second tier allocation. ESI records the costs associated with
21 ESI services received in a “clearing account” on its balance sheet. These
22 costs reside temporarily in this clearing account until they are distributed
23 to affiliates that are using the services of ESI employees. There are two
2011 ETI Rate Case 9-432
Entergy Texas, Inc. Page 87 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 components of the Service Company Recipient Allocation process: the
2 recording of costs in the clearing account during the PC billing process;
3 and removal from or credit to the clearing account during the second tier
4 allocation process. Because the costs are distributed to all affiliates based
5 on the labor billings of ESI employees, the allocated costs are reflected in
6 the other affiliate classes. The loader offset, which is charged to a
7 balance sheet clearing account, is reflected in the Service Company
8 Recipient Offsets Class. Because the loader offset is charged to a
9 balance sheet account at ESI, loader offset amounts are not included in
10 the Total ETI Adjusted, as shown on my Exhibits SBT-A, SBT-B, and
11 SBT-C.
12
13 D. Other Expenses Class
14 1. Description of Class
15 Q. PLEASE DESCRIBE THIS CLASS OF AFFILIATE COSTS.
16 A. This class reflects $1,756,009 of costs resulting from certain accounting
17 adjustments. It primarily includes costs related to payroll, the credit from
18 the 5% upcharge to the non-regulated affiliates, and other miscellaneous
19 costs that are not associated with any other specific affiliate class.
2011 ETI Rate Case 9-433
Entergy Texas, Inc. Page 88 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q PLEASE DESCRIBE THE ADJUSTMENTS THAT RESULTED IN THE
2 PAYROLL-RELATED COSTS INCLUDED IN THIS CLASS.
3 A. Certain payroll-related adjustments, which resulted in the payroll-related
4 costs in this class, are primarily the result of the use of standard estimated
5 rates throughout the year, which differ from actual recorded charges at the
6 end of the year. The costs resulting from the payroll-related adjustments
7 account for approximately $2.3 million. (As I explain below, there is a
8 credit that offsets this amount by $500,000.) Company witness Gardner
9 discusses the reasonableness of various types of payroll-related costs,
10 including employee benefits, teamsharing, and other incentive
11 compensation and payroll taxes. I address the residual amount of these
12 payroll-related costs that have not been loaded to specific departments.
13
14 Q. BESIDES THESE PAYROLL-RELATED COSTS, WHAT OTHER COSTS
15 ARE INCLUDED IN THE OTHER EXPENSES CLASS?
16 A. Also included in the Other Expenses Class is a credit of approximately
17 $500,000 of other expenses. The other expenses within this class are
18 primarily made up of credits related to the 5% upcharge to the non-
19 regulated companies, and other miscellaneous accounting adjustments of
20 approximately $240,000.
2011 ETI Rate Case 9-434
Entergy Texas, Inc. Page 89 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q. WHAT PERCENTAGES OF THE TOTAL ETI ADJUSTED FOR THIS
2 CLASS WERE DIRECT BILLED AND ALLOCATED TO ETI?
3 A. As shown on Exhibit SBT-A, SBT-B, and SBT-C, the Total ETI Adjusted
4 amount for this class of services is $1,756,009. Of this amount, ESI
5 directly billed the $500,000 credit described above (which is -13.9% of the
6 Total ETI Adjusted amount) and allocated the payroll-related costs (which
7 is 113.9% of the Total ETI Adjusted amount) to ETI. The following table
8 summarizes this information for the Other Expenses Class. I described
9 the column names previously in the Depreciation Class section of my
10 testimony.
Total ETI Adjusted
Class Total Billings Amount % Direct % Allocated
Other Expenses
$36,585,596 $1,756,009 -13.9% 113.9%
11 Q. PLEASE DESCRIBE THE EXHIBITS THAT SUPPORT THE
12 INFORMATION INCLUDED IN THE TABLE ABOVE.
13 A. Exhibits SBT-A through SBT-C support the information for this class in the
14 same manner as I discussed earlier in my testimony. For each exhibit, the
15 amounts in the columns represent the same information as described
16 above with regard to my Depreciation Class.
2011 ETI Rate Case 9-435
Entergy Texas, Inc. Page 90 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q. ARE THERE ANY PRO FORMA ADJUSTMENTS TO THIS CLASS?
2 A. Yes. The pro forma adjustments for the Other Expenses Class are shown
3 on Exhibit SBT-D, which also indicates the Company witnesses who
4 sponsor those pro forma adjustments. As indicated on Exhibit SBT-D,
5 there were eleven pro forma adjustments made to the Other Expenses
6 Class. Exhibit SBT-12 describes the pro forma adjustments to this Class
7 in greater detail.
8
9 Q. WHAT ARE THE MAJOR COST COMPONENTS OF THE CHARGES
10 FOR THIS CLASS?
11 A. The major cost components for charges from ESI to ETI are as follows:
Cost Component Dollars % of Total
Payroll and Employee
$2,280,649 129.88%
Costs
Outside Services $112,325 6.4%
Office and Employee
$1 0%
Expenses
Service Company
$105,361 6%
Recipient
Other $-742,327 -42.27%
TOTAL $1,756,009 100%
12 Q. WHAT IS THE IMPORTANCE OF THESE COST CATEGORIES?
13 A. The foregoing table is common to most affiliate witnesses in this case. I
14 directly sponsor the costs shown in this table because they comprise the
2011 ETI Rate Case 9-436
Entergy Texas, Inc. Page 91 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Total ETI Adjusted amount for the Other Expenses Class. This breakout
2 of costs provides an additional view of the components of the costs in this
3 class. For example, the table demonstrates that 129.88% of the costs are
4 for compensation, employee benefits, and other labor-related expenses
5 (“Payroll and Employee Costs”). These costs are the result of certain
6 payroll-related adjustments, which I discussed earlier in this section.
7 Company witness Gardner discusses overall payroll and benefits-related
8 structure and practices. The Other expenses in this class, as I previously
9 discussed, include the credits related to the 5% upcharge to the
10 non-regulated affiliates, and other miscellaneous accounting adjustments.
11
12 2. Necessity
13 Q. PLEASE EXPLAIN WHY THE ADJUSTMENTS THAT RESULTED IN
14 THE COSTS BILLED TO ETI UNDER THE OTHER EXPENSES CLASS
15 ARE NECESSARY.
16 A. As explained above, the adjustments resulting in the payroll-related costs
17 included in the Other Expenses Class are necessary to reflect costs
18 associated with reasonable and necessary compensation and benefit
19 programs that Company witness Gardner discusses in his direct
20 testimony. The remaining costs in this class were necessary to properly
21 reflect accounting entries in the Company’s books in accordance with
22 generally accepted accounting standards.
2011 ETI Rate Case 9-437
Entergy Texas, Inc. Page 92 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 3. Reasonableness
2 Q. HAVE YOU REVIEWED THE COSTS IN THE OTHER EXPENSES
3 CLASS TO DETERMINE WHETHER THE ADJUSTMENTS WERE
4 REASONABLE?
5 A. Yes. The adjustments that result in the payroll-related costs in the Other
6 Expenses Class are reasonable because they were made in accordance
7 with generally accepted accounting standards to reflect timing differences
8 associated with book entries. There is no duplication or over-recovery of
9 actual costs. The reasonableness of the compensation and benefit
10 programs associated with these payroll-related costs are discussed by
11 Company witness Gardner. As stated, the remaining adjustments are
12 reasonable (and necessary) to reflect proper and accepted accounting
13 practices with regard to the Company’s books.
14
15 4. How Costs are Charged
16 Q. DO THE COSTS CHARGED BY ESI TO ETI UNDER THE OTHER
17 EXPENSES CLASS REASONABLY APPROXIMATE THE COSTS OF
18 THOSE ITEMS?
19 A. Yes, they do. The costs charged under the Other Expenses Class, which
20 are the result of certain adjustments, are based on actual costs and do not
21 include any profit or markup.
2011 ETI Rate Case 9-438
Entergy Texas, Inc. Page 93 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q. IS THE PRICE CHARGED TO ETI FOR ADJUSTMENTS CHARGED
2 UNDER THIS CLASS NO HIGHER THAN THE PRICE CHARGED TO
3 OTHER AFFILIATES?
4 A. Yes. The adjustments that resulted in the costs in this class ensure that
5 the total costs charged to ETI are no higher than the price charged by ESI
6 to the other affiliates for the costs charged under the Other Expenses
7 Class. The adjustments that resulted in the payroll-related costs in this
8 class are part of a true-up process to adjust payroll-related account
9 balances for the use of standard estimated rates during the year. The
10 account balance true-ups follow the same billing distribution as the original
11 payroll loaders with the same PCs used for labor costs. As I explained
12 earlier in my testimony, each PC is assigned one billing method that will
13 most appropriately allocate the charges to the companies receiving the
14 services based on cost-causation principles. This basis of cost allocation
15 ensures that the price charged to ETI is no higher than the price charged
16 to other affiliates.
17
18 X. SPONSORED AFFILIATE PRO FORMA ADJUSTMENTS
19 Q. DO YOU SPONSOR ANY OF THE PRO FORMA ADJUSTMENTS TO
20 THE TEST YEAR INCLUDED IN EXHIBIT SBT-12?
21 A. Yes. Exhibit SBT-12 identifies the pro forma adjustments that I sponsor.
2011 ETI Rate Case 9-439
Entergy Texas, Inc. Page 94 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q. PLEASE DISCUSS THE PRO FORMA ADJUSTMENTS TO THE TEST
2 YEAR COSTS THAT YOU SPONSOR.
3 A. The adjustments to the test year affiliate costs that I sponsor are listed
4 below.
5  AJ21-04 – PwC Changes in Billing Methods
6  AJ21-11 – Correct Capital Project Codes
7  AJ21-14 – Billing Method Change for Project Code
8 F3PCTDOR01
9 These test year pro forma adjustments are described in greater
10 detail in Exhibit SBT-12 and Exhibit SBT-D, which includes details of the
11 pro forma adjustments by account.
12
13 Q. ARE THERE ANY ADDITIONAL AFFILIATE PRO FORMA
14 ADJUSTMENTS TO THE TEST YEAR THAT ARE SPONSORED BY
15 SOMEONE OTHER THAN YOU?
16 A. Yes. Please refer to Exhibit SBT-12 for a listing and description of the
17 affiliate pro forma adjustments to the test year sponsored by other
18 Company witnesses.
19
20 XI. BENCHMARKING OF ESI COSTS
21 Q. ARE ESI’S COSTS OF PROVIDING ITS SUPPORT SERVICES
22 COMPARABLE TO OTHER SERVICE COMPANIES?
23 A. ESI’s costs are generally in line with those of peer service companies.
2011 ETI Rate Case 9-440
Entergy Texas, Inc. Page 95 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q. HAVE YOU DONE ANY TYPE OF ANALYSIS TO REACH THE
2 CONCLUSION THAT ESI’S COSTS ARE GENERALLY IN LINE WITH
3 THOSE OF PEER SERVICE COMPANIES?
4 A. Yes, I conducted a benchmarking analysis comparing ESI’s costs with the
5 costs of peer service companies using publicly available information in the
6 December 31, 2010 FERC Form 60 for a peer group of service companies
7 and the December 31, 2010 Form 10-K for the related holding companies.
8
9 Q. PLEASE DESCRIBE HOW YOU DEVELOPED YOUR LIST OF PEER
10 GROUP SERVICE COMPANIES.
11 A. I identified the list of service companies that submitted a December 31,
12 2010 Form 60 to the FERC. The FERC Form 60 is required to be filed by
13 all utility service companies serving multiple jurisdictions. For 2010, 38
14 service companies, including ESI, submitted the FERC Form 60. Several
15 of these companies have multiple service companies that provide specific
16 services that are not comparable to ESI, including those that provide
17 nuclear generation operations. My analysis excluded those service
18 companies that provide specific services that are not comparable to ESI.
19 In order to ensure direct comparability, my analysis also excluded service
20 companies with a non-U.S. based parent company and companies with
21 fewer than 1 million customers. To ensure that the analysis was
22 performed among similar companies, I then included only those
23 companies whose holding company systems were classified as “Electric
2011 ETI Rate Case 9-441
Entergy Texas, Inc. Page 96 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Utilities” by the Global Industry Classification Standard. Lastly, I excluded
2 those companies whose service company headcount information is not
3 publicly available in the Form 10-K or whose FERC Form 60 does not
4 include service company property. The resulting 2010 ESI peer group
5 used in my benchmarking analysis includes Allegheny, AEP, Exelon,
6 FirstEnergy, Northeast Utilities, PEPCO, and Southern Company. A high
7 level overview of the peer group selection process is included in
8 Exhibit SBT-28A.
9
10 Q. PLEASE DESCRIBE THE FERC FORM 60 DATA AND THE FORM 10-K
11 DATA THAT WAS USED IN YOUR BENCHMARKING ANALYSIS.
12 A. My benchmarking analysis captured service company O&M expense as a
13 percentage of total company O&M, service company O&M expense as a
14 percentage of total company revenue, service company O&M expense as
15 a percentage of total company assets, and service company O&M
16 expense per service company employee. The service company O&M
17 expense is publicly available in the FERC Form 60. The total company
18 O&M, total company revenue, total company assets, and service company
19 headcount are publicly available in the Form 10-K. Cost comparisons
20 were calculated on a per-unit basis rather than a total cost basis due to
21 differing levels of granularity and aggregation in the total costs.
2011 ETI Rate Case 9-442
Entergy Texas, Inc. Page 97 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 Q. WHAT WERE THE RESULTS OF YOUR BENCHMARKING ANALYSIS
2 FOR EACH OF THE COST COMPARISONS LISTED ABOVE?
3 A. As shown in Exhibit SBT-28B, ESI O&M expense represents 21.50% of
4 total company O&M expense, which is below the peer group average of
5 26.33%. As shown in Exhibit SBT-28C, ESI O&M expense represents
6 9.49% of total company revenue, which is below the peer group average
7 of 10.77%. As shown in Exhibit SBT-28D, ESI O&M expense represents
8 1.79% of total company assets, which is below the peer group average of
9 2.05%. Lastly, as shown in Exhibit SBT-28E, ESI O&M expense is
10 $220,325 per ESI employee, which is below the peer group average of
11 $248,142 per service company employee.
12
13 Q. HOW SHOULD COMPARATIVE PERFORMANCE RELATIVE TO A
14 PEER GROUP, AS CALCULATED THROUGH BENCHMARKING, BE
15 VIEWED?
16 A. In general, service company costs that are at or better than average
17 provide an indication that a company is providing services in a cost
18 effective manner.
19
20 Q. WHAT DO YOU CONCLUDE FROM THE BENCHMARKING ANALYSIS
21 THAT YOU PERFORMED?
22 A. The overall benchmarking analysis indicated that ESI performed slightly
23 better than the peer group average. As a result of my benchmarking
2011 ETI Rate Case 9-443
Entergy Texas, Inc. Page 98 of 98
Direct Testimony of Stephanie B. Tumminello
2011 Rate Case
1 analysis, I have concluded that ESI’s costs are generally in line with those
2 of peer service companies, which supports the conclusion that ESI costs
3 charged to ETI are reasonable.
4
5 XII. CONCLUSION
6 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
7 A. Yes, at this time.
2011 ETI Rate Case 9-444
Exhibit SBT-15
2011 TX Rate Case
Attachment 8
Page 1 of 12
Affiliate Billing Process Controls
Overview
Several process controls have been established and are in place to help ensure
that billings to affiliates represent the actual costs of items or services provided to
such affiliates. A brief discussion of each of these controls is provided below.
Billing Process Controls – General
Multiple Approvals of Project Codes:
Multiple approvals by various parties are required for newly initiated project
codes. The preparer of a project code (PC) request is responsible for assigning
an appropriate billing method(s) to the PC, based on the scope and nature of the
work to be performed. The preparer is often the person with the most knowledge
about the project and, therefore, is most qualified to choose the appropriate
billing method. As a check to make sure the PC has been set up correctly, a
minimum of two review points exist. When a new PC is initiated in PowerPlant,
the budget coordinator or department manager reviews the PC request. If the PC
request is appropriate, then it is routed to the Affiliate Accounting and Allocations
(AAA) Outlook inbox for approval. An AAA employee will review the project to
ensure that the appropriate billing method is assigned. This is done by reading
the scope statement to see what the scope, primary activities, primary products
or deliverables, and justification of billing method are for the project. If the scope
Exhibit SBT-15
2011 TX Rate Case
Attachment 8
Page 2 of 12
statement and the billing method chosen are appropriate, then the PC is
approved by the AAA employee. If the project code is above a certain dollar
amount, then the project will also need manager approval. Depending on the PC,
other reviews may also be required to further ensure that the PC is set up
correctly. For instance, projects that result in capital expenditures must be
reviewed by the Property Accounting department. Once the project code request
is approved, the project is ready to receive charges. These charges will proceed
through the automated affiliate billing process also known as Service Company
Billings. Personnel involved in establishing or reviewing PCs receive training on
the selection of an appropriate billing method(s), and on proper procedures for
capturing data using project codes. To see the project code set-up in flowchart
form, please see Attachment 3 that depicts the process of setting up a billable
project code.
Approval of Loaned Resource Billing Transactions:
Manager approval is required before an employee can initiate a loaned resource
transaction involving labor. This ensures that the process is being used correctly
and when appropriate.
Co-owner Allocation Rules:
The co-owner billing process uses allocation rules to capture costs that meet the
criteria for co-owner billing. These rules use a combination of FERC account,
physical location code, resource code and PC as the criteria for capturing costs
Exhibit SBT-15
2011 TX Rate Case
Attachment 8
Page 3 of 12
to be billed through this process. Co-owner allocation results are reviewed
monthly by the allocation owners in the Fuel & Generation Accounting group.
Approval of Source Documentation:
Prior to the recording of a transaction on the Company’s books, the appropriate
personnel must review and approve source documentation (such as timesheets,
accounts payable vouchers, and journal entries), in accordance with the
requirements of Entergy's approval policies.
Budget Process Activities:
The budget process also serves as a method of control. Specifically, budget
coordinators are directed during budget training to review the project codes used
by their departments to ensure that they are appropriate for the services being
provided, including the billing method(s) assigned to the project code(s).
In addition, the management of each department reviews actual charges
on a monthly basis and compares them to budget. This is accomplished through
review of the department’s cost reports, which provide actual versus budget
comparisons in several ways, e.g., by project, activity, and resource codes.
Monthly Allocation Results and Billing Analysis:
Reasonableness testing is performed on a monthly basis as a control to ensure
the reasonableness of affiliate charges. This process includes reviewing
variances within each account. Once a material variance is discovered, it is
Exhibit SBT-15
2011 TX Rate Case
Attachment 8
Page 4 of 12
analyzed and any necessary adjustments are made. Specifically, personnel
have the opportunity to identify billing exceptions (not previously identified)
through the review, analysis, and reconciliation of variances. If, during the
monthly analysis of financial results, a charge by an affiliate to another Business
Unit is questioned by management, functional budget coordinators, the Billing
Analysis Review Team (BART), or others, then the charges are investigated by
Affiliate Accounting and Allocations or another responsible party and handled
appropriately. The charge can be traced back to the original entry that created
the billing to the company to best analyze the charge. For example, if the
analysis of ETI's non-fuel operation and maintenance (“O&M”) expenses
indicates that a charge originated from ESI, then the PC generating the billing
can be identified. The charges to the PC can then be researched in ESI's
general ledger to see what sources initiated the charge and if the charge was
billed appropriately.
In addition, Affiliate Accounting and Allocations tests the billing results and
other allocation results monthly to ensure that project code transactions are
billing correctly and allocation results are accurate. Preliminary allocations are
run at various times throughout the month in order get a preliminary view of the
allocation results before the final allocation run. The final allocation run is always
the last business day of the month. Allocation owners are emailed after
preliminary allocation runs as a notification and reminder to check preliminary
allocation results. Each individual allocation owner will check allocations and
notify AAA’s EPM owner of any issues, so that issues can be resolved before the
Exhibit SBT-15
2011 TX Rate Case
Attachment 8
Page 5 of 12
final allocation run. In addition, AAA sends out net income reports during the
close period that will identify any PC that didn’t bill out costs. Specifically, these
reports indicate the amount of net income, if any, at each service company by
PC. AAA employees will analyze the issues and resolve them in a timely manner.
Authorization Required to Access Corporate Applications:
Another control is the authorization required to access certain software.
Employees must be given permission, and must be issued an ID, prior to
obtaining access to corporate applications such as PeopleSoft applications,
Accounts Payable systems, and Payroll systems. Each user is also often
restricted to specific functions within each system relative to his or her
requirements and position. Also, these programs are protected by user
passwords. These controls help ensure that affiliate costs are properly
supported, and no unauthorized changes are made for project billings, loaned
resource billings and co-owner billings. Quarterly reviews of system access are
required under SOX testing.
Billing Process Controls – ESI
In addition to the controls discussed above, ESI has the following additional
controls:
BART Monthly Reviews of ESI Billings:
BART was established in 1995 by Affiliate Accounting and Allocations to develop
and implement a process to review ESI billings with representatives from each of
Exhibit SBT-15
2011 TX Rate Case
Attachment 8
Page 6 of 12
the regulated companies in order to provide assurance to the Entergy Utility
Presidents and jurisdictional regulators that the ESI bill is descriptive and
reasonable and that ESI costs are properly allocated. As a result of this team's
work, several monthly service billing reports were developed for use as tools to
help monitor the cost allocation process on an ongoing basis. One report, listing
each Business Unit, also lists each PC charging that Business Unit by PC
number, PC description, and billing method utilized. The data is summarized by
month and includes a year-to-date total. The second report provides total
monthly charges for each PC by Business Unit. Additional reports list all new
PCs and PCs with billing method changes during the current month. This report
includes PC descriptions, project manager names, and the budgetable and
chargeable status of the projects. The BART team is comprised of Affiliate
Accounting and Allocations, Regulatory Accounting, Nuclear - Business Services
employees, Jurisdictional Finance Directors, Business Analysis Managers and
Regulatory Affairs representatives from the operating companies. The BART
team has regularly scheduled monthly meetings to review billing results of the
preceding month and to discuss billing issues.
During the monthly BART meetings, team members review billing results,
inquire about specific project billings, and challenge project billing method
assignments. Some issues raised during the course of a BART meeting are
successfully resolved during the meeting. Unresolved issues are maintained and
resolved by AAA after the meeting. The resolution of these issues is later
communicated with BART team members.
Exhibit SBT-15
2011 TX Rate Case
Attachment 8
Page 7 of 12
Employee Training:
Each ESI employee is ultimately responsible for charging the costs that he or she
incurs to the appropriate PC, and thus billing the companies receiving the
services appropriately. As a guide, ESI Time and Expense Training materials
are posted on the Affiliate Accounting and Allocations section of Entergy’s
internal web. All ESI employees are required to acknowledge their review of
these training materials on an annual basis via our Corporate Training
application, WebTap (Web-based Training Administration Program). This
training stresses the importance of choosing the correct PC. It also discusses
the role of billing methods in billing the appropriate companies for services
rendered, and emphasizes that direct billing is preferred over allocating charges
where possible. The training also reviews how to determine which PC should be
used for specific services. These ESI Time and Expense Training materials are
included in Exhibit SBT-16.
Internal Reviews of Affiliate Transactions and Processes
Internal Audit reviews the controls and performs tests of transactions and
balances related to affiliate billings. Specifically, related to the implementation of
the Sarbanes-Oxley Act, Internal Audit reviews the risks, control activities, and
testing of those control activities associated with the affiliate billing process.
Their review includes the related funding, allocations, intercompany account
Exhibit SBT-15
2011 TX Rate Case
Attachment 8
Page 8 of 12
reconciliations, and access request processes associated with the overall affiliate
billing process.
External Reviews and Audits of Affiliate Transactions and Processes:
There are several reviews or audits of affiliate transactions and processes that
occur routinely. For instance, Deloitte & Touche LLP performs certain agreed
upon procedures annually at the request of Entergy to satisfy a requirement
included in an October 1992 Settlement Agreement, as amended, between
certain regulators and Entergy.
In connection with the performance of their procedures, Deloitte & Touche
LLP selects several intercompany transactions billed to Entergy Enterprises Inc.
by Entergy affiliates to ensure that they were billed in accordance with PUHCA
2005 affiliate billing requirements. Deloitte & Touche LLP’s “Independent
Accountants’ Report on Applying Agreed-Upon Procedures” for the year ended
December 31, 2010 is included in the Attachment 9.
In addition, the annual external audit of Entergy Corporation and its
subsidiaries’ financial statements performed by Deloitte & Touche LLP helps to
detect whether the intercompany accounts and billing processes are producing
any material misstatements in the financial statements. The Sarbanes-Oxley Act
also requires that an independent auditor attest to the accuracy of the
Company’s disclosure regarding the effectiveness of its internal controls. In this
connection, D&T also reviews risks, controls activities, and testing of control
activities associated with the affiliate billing processes.
Exhibit SBT-15
2011 TX Rate Case
Attachment 8
Page 9 of 12
Further, the FERC, under the authority of the Public Utility Holding Act of
2005, is authorized to periodically conduct audits of service companies. These
service company audits include an examination of each service companies’
compliance with cross-subsidization restrictions on affiliate transactions at 18
C.F.R. Part 35, accounting, recordkeeping, and reporting requirements at 18
C.F.R. Part 366, compliance with the Uniform System of Accounts for centralized
service companies at 18 C.F.R. Part 367, and preservation of records
requirements for service companies at 18 C.F.R. Part 368. During the most
recent FERC audit of Entergy’s four service companies, including ESI, covering
the period January 2006 through December 2008, the FERC tested for
compliance with the aforementioned regulations by conducting tests of the
service companies’ cost allocations and the charges billed by the service
companies. The FERC reviewed and tested the supporting details for the
service companies’ cost allocation methodologies, tested the centralized service
companies’ costs and accounting, and reviewed selected service companies’
billings and the corresponding associated franchised public utilities’ accounting
for the billings. The FERC letter order dated December 9, 2009 in connection
with this audit found there were no significant deficiencies related to the
allocation methodologies, accounting, or pricing of service company transactions.
Exhibit SBT-15
2011 TX Rate Case
Attachment 8
Page 10 of 12
Sarbanes-Oxley Controls and Testing:
In accordance with Section 404 of the Sarbanes Oxley Act, Entergy is charged
with supporting its evaluation of internal controls with sufficient evidence
including documentation. Affiliate billings are tested for compliance with
Sarbanes Oxley quarterly. AAA keeps documentation current as it relates to
processes, risks, controls and test plans, evaluates the effectiveness of internal
controls, documents test results in eCART (Entergy’s Compliance and Risk Tool)
and actively manages issues. Such tests for internal controls, as they relate to
affiliate billings, include Record Payroll Loaders and Payroll Accruals, SAIC
Outsourced Billings, Transportation Clearing, Funding and Repayment of Service
Billings, Calculate and Record Service Billings, Account Reconciliation Testing,
various other allocations, and quarterly reviews of system access. Each process
has been evaluated for control risks and each risk has been identified and
documented. Testing includes review of process flowcharts and tests for the
controls associated with each designated risk.
On an annual basis, Internal Audit, accounting personnel, and our external
auditors (Deloitte & Touche) evaluate internal controls tests. The external
auditors assess the adequacy of documentation in eCART, test and validate the
effectiveness of controls, and issue a 404 attestation to the investing community
via Entergy’s 10-K. If any deficiencies are reported, immediate steps are taken
to resolve issues through the use of the eCART system where an action plan is
created.
Exhibit SBT-15
2011 TX Rate Case
Attachment 8
Page 11 of 12
FERC Compliance Controls and Testing
In accordance with FERC policies and guidelines, Entergy has established a
formal FERC compliance program that identifies risks, control activities, test
procedures, and test results for Entergy’s key FERC requirements. Similar to
Sarbanes-Oxley controls and testing, Entergy maintains the documentation for
these requirements, risks, control activities, test procedures, test results, and any
related issues in eCART. The tests of FERC control activities, as they relate to
affiliate billings, include testing related to FERC pricing requirements as set forth
under FERC Order Nos. 707 and 707-A, which became effective as of March 31,
2008. These orders include asymmetrical pricing requirements for transactions
between franchised public utilities and their non-utility affiliates. The control
activities related to FERC pricing requirements are tested on a quarterly basis to
ensure compliance with the FERC requirements.
In addition, Entergy reports the methods of allocation in the annual FERC
Form 60 filed by each of its service companies. The related FERC Form 60
schedule indicates the service department or function and the basis for the
allocation used when employees render services to more than one department or
functional group. Further, new methods of allocation are submitted to the FERC
for review and acceptance prior to implementation.
Affiliate Transactions Policy
The Entergy System Accounting Policy entitled “Affiliate Transactions” is posted
on Entergy’s internal web. This policy is maintained by the Affiliate Accounting
Exhibit SBT-15
2011 TX Rate Case
Attachment 8
Page 12 of 12
and Allocations group and sets forth the standards for affiliate transactions
related to affiliate controls and pricing. This policy is reviewed annually and
updated as necessary.
Summary
The use of project codes and cost-causative allocation factors filed with the
FERC, as well as the internal review of charges among all affiliates, including
ETI, help to ensure that all affiliates bear only those charges for services each
receives. Each of the controls discussed above is an integral part of a multi-
faceted process that is designed to bill the appropriate share of reasonable and
necessary charges to the affiliates.
Entergy Services, Inc. Exhibit SBT-26
Net Book Value of Assets 2011 TX Rate Case
Page 1 of 1
As of June 30, 2011
Plant Accumulated Life
Asset Description Plant In Service Net Plant
Account Depreciation (Months)
303 Externally Purchased Software Systems $45,299,093 $32,159,946 $13,139,146 60/120
303 Internally Developed Software Systems 47,545,691 28,356,365 19,189,326 60/120
303 Misc. Computer Software 23,033,402 15,931,317 7,102,084 60/120
3891 Land 2,212,516 0 2,212,516 N/A
390 Capital Lease - Structures 32,137,871 3,079,879 29,057,992 LED*
390 Leasehold Improvements 33,841,914 17,220,908 16,621,007 LED*
390 Owned Buildings 39,717,801 4,466,429 35,251,372 378
3911 Furniture & Fixtures 10,840,746 5,702,565 5,138,181 120
3912 Computer Equipment 67,201,729 44,457,299 22,744,431 60
3913 Data Handling Equipment 402,506 189,154 213,352 120
392 Transportation - Auto 1,903 1,903 0 60
392 Transportation - Cessna 83,558,696 7,658,629 75,900,068 120
392 Transportation - Falcon 23,843,613 6,868,734 16,974,879 120
392 Transportation - Other 67,891 34,927 32,964 60
395 Laboratory Equipment 68,333 7,694 60,639 60
3971 Fiber Optic Equipment 3,975,059 2,089,724 1,885,335 120
3971 Microwave Equipment 2,570,585 2,570,585 0 120
3971 Other Communication Equipment 19,529,933 10,220,235 9,309,698 60/120
398 Miscellaneous Equipment 10,330,439 5,414,646 4,915,794 120/180
Total $446,179,722 $186,430,939 $259,748,783
* LED = Lease End Date. Leasehold improvements are depreciated using the straight-line depreciation
method. The number of months used to depreciate the improvements are generally the months
between the creation of the asset and the end of the lease.
Exhibit SBT-26
2011 TX Rate Case
Amounts may not add or tie to other schedules due to rounding. Page 1 of 1
WP/SBT-4
2011 TX Rate Case
Page 1 of 7
Entergy Texas, Inc.
Summary of Costs Billed by Entergy Services, Inc.
and Other Entergy Affiliates to Entergy Texas, Inc.
for the year ended June 30, 2011
Entergy Texas, Inc. WP/SBT-4
2011 TX Rate Case
Index Page 2 of 7
For the year ended June 30, 2011
Page(s)
Report of Independent Accountants ............................................................................................................ 1
Management’s Assertion Regarding the Summary of Costs Billed by Entergy Services, Inc. and
Other Entergy Affiliates to Entergy Texas, Inc. ............................................................................................ 2
Summary of Costs Billed by Entergy Services, Inc. and
Other Entergy Affiliates to Entergy Texas, Inc. ............................................................................................ 3
Notes to Summary of Costs Billed by Entergy Services, Inc. and
Other Entergy Affiliates to Entergy Texas, Inc. ......................................................................................... 4-5
WP/SBT-4
2011 TX Rate Case
Page 3 of 7
Report of Independent Accountants
To the Management of Entergy Services, Inc.
We have examined management’s assertion, included in the accompanying Management’s Assertion
Regarding the Summary of Costs Billed by Entergy Services, Inc. (“ESI”) and Other Entergy Affiliates to
Entergy Texas, Inc. (“ETI”), that the Summary of Costs Billed by Entergy Services, Inc. and Other Entergy
Affiliates to Entergy Texas, Inc. for the year ended June 30, 2011 (“Summary of Costs Billed”), is an
accurate presentation of costs billed to ETI based on the criteria set forth in management’s assertion as
further described by the Notes to the Summary of Costs Billed. ESI’s management is responsible for the
assertion. Our responsibility is to express an opinion based on our examination.
Our examination was conducted in accordance with attestation standards established by the American
Institute of Certified Public Accountants and, accordingly, included examining, on a test basis, evidence
supporting management’s assertion and performing such other procedures as we considered necessary
in the circumstances. We believe that our examination provides a reasonable basis for our opinion.
In our opinion, management’s assertion referred to above is fairly stated, in all material respects, based on
the criteria set forth in management’s assertion, as further described in the Notes to the Summary of
Costs Billed.
This report is intended solely for the information and use of Duggins Wren Mann & Romero, LLP,
ETI, ESI and the Texas Public Utility Commission, and is not intended to be and should not be used by
anyone other than these specified parties.
October 31, 2011
PricewaterhouseCoopers LLP, 639 Loyola Avenue, Suite 1800, New Orleans, LA 70113
T: (504) 558 8200, F: (504) 558 8960, www.pwc.com/us
WP/SBT-4
2011 TX Rate Case
Page 4 of 7
Management’s Assertion Regarding the Summary of Costs Billed by Entergy Services, Inc. and
Other Entergy Affiliates to Entergy Texas, Inc.
Management of Entergy Services, Inc. has prepared the accompanying Summary of Costs Billed by
Entergy Services, Inc. (“ESI”) and Other Entergy Affiliates to Entergy Texas, Inc. (“ETI”) for the year
ended June 30, 2011 (“Summary of Costs Billed”). The Summary of Costs Billed includes only amounts
recognized as expense by ETI and does not include any costs charged to project codes used for capital
projects. Management asserts that the Summary of Costs Billed is an accurate presentation of costs billed
to ETI based on the criteria set forth below.
ESI has established systems and processes to accumulate costs and bill them on a cost causative basis
to affiliates, including ETI. The billing methods used to bill costs ensure that costs billed to ETI reasonably
approximate the actual costs of services provided and are no higher than the costs billed to other affiliates
for similar services. In addition to the ESI costs billed to ETI, other Entergy affiliates have directly billed
ETI for loaned resources or co-owner billings.
For purposes of this assertion, management has defined the accurate presentation of costs billed to ETI
as inclusion of only costs (i) charged to a project code related to a project scope statement filed as part of
the rate case and subsequently billed to ETI based on the billing method in the respective project code or
(ii) other affiliate costs directly charged to ETI as further described in the Notes to the Summary of Costs
Billed by Entergy Services, Inc. and Other Entergy Affiliates to Entergy Texas, Inc.
Entergy Texas, Inc. WP/SBT-4
2011 TX Rate Case
Summary of Costs Billed by Entergy Services, Inc. and Page 5 of 7
Other Entergy Affiliates to Entergy Texas, Inc.
For the year ended June 30, 2011
(dollars in thousands)
Final Costs Billed $78,998,777
The Notes to Summary of Costs Billed by Entergy Services, Inc. and Other Entergy Affiliates to
Entergy Texas, Inc. for the year ended June 30, 2011 are an integral part of this summary
3
Entergy Texas, Inc. WP/SBT-4
2011 TX Rate Case
Notes to the Summary of Costs Billed by Entergy Services, Inc. and Page 6 of 7
Other Entergy Affiliates to Entergy Texas, Inc.
For the year ended June 30, 2011
1. Background
Entergy Texas, Inc. (“ETI” or the “Company”) is a wholly-owned subsidiary of Entergy Corporation
(“Entergy”). Entergy Corporation and Subsidiaries is an integrated energy company engaged
primarily in electric power production and the operation of a retail electric distribution system (the
“Entergy System” or “System”). Through a series of wholly-owned subsidiaries, Entergy owns and
operates power plants with approximately 30,000 MW of electric generating capacity and delivers
electricity to 2.7 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. ETI is one
of Entergy Corporation’s integrated utility companies serving customers in Texas.
Entergy Services, Inc. (“ESI”), a corporation wholly-owned by Entergy Corporation, provides
management, administrative, accounting, legal, engineering, and other services to ETI, as well as
other Entergy subsidiaries. ESI provides its services to ETI on an “at cost” basis, determined using
billing methods based on cost causative factors (for example, total assets, number of customers,
payroll checks, IT spending, insurance premiums, server / mainframe usage, number of personal
computers, accounts payable and receivable metrics, number of employees, general ledger
transactions, distribution and transmission line mileage, distribution and transmission substations,
generating capacity, generating capability, and customer load ) pursuant to service agreements
that were previously approved by the Securities and Exchange Commission (“SEC”) under PUHCA
1935 and those subsequently accepted by the Federal Energy Regulatory Commission (“FERC”)
following adoption of PUHCA 2005.
ETI maintains its accounting books and records in accordance with FERC and other regulatory
guidelines, as well as in accordance with accounting principles generally accepted in the United
States (GAAP).
2. Costs Billed by ESI and Other Entergy Affiliates
ESI's costs incurred in providing services to ETI and other Entergy affiliates are set forth in the
service agreements and include, but are not limited to, labor and related overhead costs (e.g.,
salaries of officers and other employees, employee welfare expenses such as social security taxes,
life insurance, pensions, post-retirement benefits other than pension, medical, dental and other
welfare expenses), training costs, facilities costs, information technology costs and costs related to
vendor and other contract services.
ESI has established systems and processes to accumulate costs and bill them on a cost causative
basis to affiliates, including ETI. The key objectives of these systems and processes are to ensure
that:
Charges to affiliates reasonably approximate the cost of services provided,
Prices charged to and paid by each affiliate are no higher than the prices charged to and paid
by other affiliates for similar services,
Cost causative correlation exists between the services provided and the affiliates receiving the
services, and
Billing methods used to bill costs ensure accurate recording and billing of the costs associated
with the provision of the related services.
4
Entergy Texas, Inc. WP/SBT-4
2011 TX Rate Case
Notes to the Summary of Costs Billed by Entergy Services, Inc. and Page 7 of 7
Other Entergy Affiliates to Entergy Texas, Inc.
For the year ended June 30, 2011
To achieve these objectives, ESI accumulates its actual costs incurred in project codes. The
project codes function as the primary cost control element from which costs are billed to the
affiliates. For each project code, a project scope statement documents a description of the project
code’s use and purpose, the activities associated with that particular project, the expected
deliverables from activities in the project, and justification for the billing methodology to be used for
billing the costs accumulated in the project. Only one ESI billing methodology may be used for
each project code to bill ESI costs to Entergy’s legal entities (including ETI).
ESI charges no more than actual costs for services provided to ETI and other regulated affiliates.
The monthly billing process includes only the costs accumulated in the project codes. There is no
markup or profit included in billings to the regulated companies. The billings are based on the
billing methodologies designated and described above. Accordingly, the unit cost (price) charged
to these affiliates, including ETI, is intended to reasonably approximate the actual costs of
providing such services.
Entergy affiliates other than ESI also have the ability to bill ETI through the use of loaned resources
and co-ownership transactions. In these cases, services are provided directly to ETI and as such
are billed 100% to ETI.
3. Billing Adjustments
ESI completed an analysis of project codes and related billing methods in connection with the
preparation of the Summary of Costs Billed for the year ended June 30, 2011. Final Costs Billed in
the Summary of Costs Billed includes additional expenses of $7,368, which increase the amounts
originally billed to ETI during the year ended June 30, 2011.
5
SOAH Docket No. XXX-XX-XXXX
PUC Docket No. 39896
ETI 2011 Rate Case
ETI EXHIBIT NO. 50
SOAH DOCKET NO. XXX-XX-XXXX
PUC DOCKET NO. 39896
APPLICATION OF ENTERGY §
TEXAS, INC. FOR AUTHORITY TO § BEFORE THE
CHANGE RATES, RECONCILE § STATE OFFICE OF
FUEL COSTS, AND OBTAIN § ADMINISTRATIVE HEARINGS
DEFERRED ACCOUNTING §
TREATMENT §
REBUTTAL TESTIMONY
OF
KEVIN G. GARDNER
ON BEHALF OF
ENTERGY TEXAS, INC.
APRIL 2012
1
ENTERGY TEXAS, INC.
REBUTTAL TESTIMONY OF KEVIN G. GARDNER
PUC DOCKET NO. 39896
TABLE OF CONTENTS
Page
I.  Introduction 1
II.  Incentive Compensation 2
III.  Allegations Regarding Base Pay and Benefits Levels 10
IV.  Supplemental Executive Retirement Benefits Plans 14
V.  Relocation Costs 17
2
Entergy Texas, Inc. Page 1 of 18
Rebuttal Testimony of Kevin G. Gardner
Docket No. 39896
1 I. INTRODUCTION
2 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
3 A. My name is Kevin G. Gardner. My business address is 639 Loyola
4 Avenue, New Orleans, Louisiana 70113.
5
6 Q. DID YOU PREVIOUSLY FILE DIRECT TESTIMONY ON BEHALF OF
7 ENTERGY TEXAS, INC. (“ETI” OR “THE COMPANY”) IN THIS
8 PROCEEDING?
9 A. Yes, I did.
10
11 Q. WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY?
12 A. The purpose of my rebuttal testimony is to address issues raised in the
13 Direct Testimonies of Public Utility Commission of Texas (“Commission” or
14 “PUCT”) Staff witness Anna Givens, Cities witness Mark Garrett, and
15 Texas Industrial Energy Consumers (“TIEC”) witness Jeffry Pollock
16 regarding ETI’s requested recovery of its incentive compensation costs. I
17 also address Mr. Garrett’s recommendations to disallow amounts
18 associated with allegedly above-market base pay and employee benefits.
19 Finally, I address the recommendations of Mr. Garrett and Office of Public
20 Utility Counsel (“OPUC”) witness Carol Szerszen to disallow the
21 supplemental retirement benefits costs included in ETI’s cost of service.
3
Entergy Texas, Inc. Page 2 of 18
Rebuttal Testimony of Kevin G. Gardner
Docket No. 39896
1 II. INCENTIVE COMPENSATION
2 Q. DO YOU HAVE ANY OVERALL OBSERVATIONS ON THE PROPOSED
3 TREATMENT OF THE COMPANY’S INCENTIVE COMPENSATION BY
4 OTHER PARTIES?
5 A. Yes. The Staff, Cities, and TIEC propose significant disallowances for the
6 Company’s incentive compensation programs. In some instances, their
7 recommendations exceed the treatment of these types of costs in prior
8 PUCT proceedings. The Company’s incentive programs play an important
9 role in serving ETI’s customers. Primarily, the Company’s incentive
10 programs achieve the following indispensable goals:
11 1. Allow the Company to attract and retain reliable, experienced, and
12 highly trained employees who ensure that ETI provides safe and
13 reliable electric service to our customers.
14 2. Maintain compensation within reasonable market levels by
15 establishing a balanced portfolio of “at risk” incentives to be paid
16 only when established customer-focused goals are met.
17 3. Ensure “at risk” compensation is only delivered when performance
18 goals are met and allow the Company’s total compensation costs to
19 be more directly tied to performance.
20 4. Create safety, operational, customer, and cost control goals that
21 help establish a clear line of sight between employees and the
22 customers they serve.
4
Entergy Texas, Inc. Page 3 of 18
Rebuttal Testimony of Kevin G. Gardner
Docket No. 39896
1 For these reasons and as detailed in my direct testimony, the
2 Commission should further evaluate its stance in general on incentive
3 compensation. The Company has attempted to resolve many of the
4 concerns raised in those prior proceedings by changing the annual
5 incentive program for the majority of employees to be even more customer
6 focused. This “line of sight” between employees and current annual
7 incentive goals, which focus on safety, operational, and cost control,
8 provide an increased benefit to its customers. My direct testimony and
9 that of Company witness Dr. Jay Hartzell explained these changes and
10 provided additional evidence on the customer benefits of all incentive
11 compensation.
12
13 Q. PLEASE SUMMARIZE STAFF AND INTERVENOR WITNESS
14 RECOMMENDATIONS FOR ETI’S INCENTIVE COMPENSATION
15 COSTS.
16 A. In her pages 15-22, Staff witness Givens recommends that portions of the
17 annual and long-term incentive compensation costs tied to financial goals
18 should be disallowed. She calculates a total of $5,609,093 in such costs.
19 As summarized on his page 45, TIEC witness Pollock recommends
20 a $6.2 million disallowance for costs related to annual and long-term
21 incentive compensation plan goals that are tied to financial measures.
22 Mr. Pollock bases his proposed disallowance on Commission precedent of
23 disallowing incentive compensation based on financial measures.
5
Entergy Texas, Inc. Page 4 of 18
Rebuttal Testimony of Kevin G. Gardner
Docket No. 39896
1 As detailed in Table 3 on his page 49, Cities witness Garrett
2 recommends removing 100% of ETI’s costs related to the Company’s
3 long-term incentive compensation because all of these programs are tied
4 to “financial” goals. He also recommends removing 35% of the costs of
5 each of the Company’s annual incentive plans based on his determination
6 that 35% of the goals used in these plans are “financial” in nature.
7 Further, he recommends on his pages 52-53 that the pro forma rate base
8 should be decreased by $9,835,111 for capitalized annual and long-term
9 incentive compensation costs going back as far as January 2008 related
10 to “financial” goals. Finally, Mr. Garrett asserts on his pages 50-51 that
11 the Commission might consider disallowing all of ETI’s incentive
12 compensation costs because the Company uses the Entergy Achievement
13 Multiplier (“EAM”) as a funding mechanism as part of its annual incentive
14 compensation plans.
15
16 Q. DO YOU AGREE THAT INCENTIVE COMPENSATION COSTS
17 RELATED TO FINANCIAL GOALS SUCH AS PROFITIBILITY AND
18 STOCK PRICE SHOULD BE DISALLOWED BY THE COMMISSION?
19 A. No. The Company should be able to recover its financially related
20 incentive compensation costs because (1) customers benefit from these
21 costs and goals, (2) such costs are a necessary business expense, and
22 (3) the Company’s level of such costs was reasonable. Because they are
23 necessary, reasonable, and benefit customers, the Company’s financially
6
Entergy Texas, Inc. Page 5 of 18
Rebuttal Testimony of Kevin G. Gardner
Docket No. 39896
1 related incentive compensation costs should be recoverable whether such
2 costs are related to the Company’s annual incentive plans, long-term
3 incentive plans, or the Company’s capital costs.
4
5 Q. HOW DO CUSTOMERS BENEFIT FROM FINANCIALLY BASED GOALS
6 SUCH AS PROFITIBILITY AND STOCK PRICE?
7 A. Having incentive compensation related to financial goals is standard for
8 companies such the Entergy Companies, and the Entergy Companies
9 must offer competitive incentive compensation programs in order to
10 compete and retain talented employees. Customers benefit from a utility
11 that attracts and retains qualified personnel. Further, having only
12 operational and safety goals in the incentive compensation plans could
13 encourage utility personnel to overspend in some areas and would result
14 in an unbalanced incentive compensation program. Customers benefit by
15 having the utility personnel balance the operational/safety goals with
16 financial goals. The direct testimony of Company witness Hartzell
17 identifies other important benefits to customers.
7
Entergy Texas, Inc. Page 6 of 18
Rebuttal Testimony of Kevin G. Gardner
Docket No. 39896
1 Q. ON HIS PAGES 47-48, MR. GARRETT RECOMMENDS
2 DISALLOWANCE OF ALL INCENTIVE COMPENSATION EXPENSES
3 THAT ARE BASED ON COST CONTROL MEASURES. DO YOU
4 AGREE WITH THIS RECOMMENDATION?
5 A. No, rejecting incentive compensation linked to cost control measures is
6 short-sighted and ignores the benefits to customers that result from these
7 measures. It is difficult to accept that the Commission would penalize a
8 utility’s efforts to foster cost control as a goal. Neither TIEC witness
9 Pollock nor Staff witness Givens seeks to disallow incentive costs tied to
10 cost control measures. Mr. Garrett even admits on his page 31, line 6 that
11 incentive plans that motivate employees to achieve increased cost control
12 efficiencies should be encouraged. The Commission should encourage
13 cost control efficiencies by allowing the Company to recover its incentive
14 compensation costs related to cost control goals.
15
16 Q. PLEASE EXPLAIN THE NATURE OF THE COST CONTROL
17 MEASURES AND HOW CUSTOMERS BENEFIT FROM THOSE GOALS.
18 A. The Entergy Companies’ cost control goals focus on the customer by
19 encouraging increased productivity and improved efficiencies in
20 operational performance. Almost every business, non-profit organization,
21 governmental agency, and household uses a budget as a tool to meet its
22 cost control objectives. Customers benefit from cost control goals in
23 multiple ways:
8
Entergy Texas, Inc. Page 7 of 18
Rebuttal Testimony of Kevin G. Gardner
Docket No. 39896
1  When the cost control efforts affect fuel, purchased power
2 energy, and energy efficiency costs, customers are directly
3 benefited through the periodic adjustment of the rates that
4 recover these costs and the Commission-prescribed
5 reconciliations of those costs.
6  When the cost control efforts relate to capital projects,
7 customers are directly benefitted when those costs are
8 incorporated into the utility’s rate base.
9  When cost control measures relate to other O&M costs during a
10 test year, customers are directly benefitted in the rates set
11 based upon that test year’s costs.
12  Cost controls measures related to non-test-year O&M costs
13 directly benefit customers because savings achieved in a
14 particular year often carry over for several years, any one of
15 which may be a test year.
16 To exclude annual incentive costs based on cost control measures
17 because of a difference in the timing of when a portion of these efforts
18 may benefit shareholders versus customers is an extreme position that
19 should be rejected. To the contrary, creating an environment where cost
20 control by employees is encouraged every year is exactly what utilities
21 should be doing.
22 Further, the operational focus of cost control is directly linked to the
23 customer. This is one reason why the Company has a major focus on
9
Entergy Texas, Inc. Page 8 of 18
Rebuttal Testimony of Kevin G. Gardner
Docket No. 39896
1 continuous improvement. This continuous improvement model energizes
2 the workforce to continually look for better ways to run the business more
3 efficiently, which results in lower costs and customer bills. Our
4 employees’ focus is directed on the customer, not the shareholder, as the
5 beneficiary of their cost savings, improved efficiencies, and process
6 improvements.
7
8 Q. PLEASE DESCRIBE HOW THE CONTINOUS IMPROVEMENT MODEL
9 IS IMPLEMENTED AT ETI AND HOW IT TIES COST CONTROL TO
10 CUSTOMER INTEREST.
11 A. Entergy’s continuous improvement model encourages employees to look
12 at their daily activities and implement changes to streamline processes
13 and eliminate unnecessary processes. The intent is that these improved
14 activities will result in increased productivity and efficiencies that will
15 ultimately benefit our customers.
16
17 Q. ON PAGE 39, MR. GARRETT PURPORTS TO EXPLAIN THE
18 IMPORTANCE OF THE DISTINCTION BETWEEN FINANCIAL
19 PERFORMANCE MEASURES AND OPERATIONAL MEASURES. DO
20 YOU AGREE WITH HIS ANALYSIS?
21 A. No. In terms of their benefit to customers, I firmly disagree with the
22 position that there is a meaningful distinction between “financial”
23 performance incentive targets and “operational” incentive performance
10
Entergy Texas, Inc. Page 9 of 18
Rebuttal Testimony of Kevin G. Gardner
Docket No. 39896
1 targets. The earnings or net income encouraged by financial targets are
2 specifically and directly the product of employee efforts to control or
3 manage costs, operate efficiently and improve efficiency, and to provide
4 strong customer service. Improved earnings are achieved by better
5 margins — i.e., more efficient operations, by improved performance and
6 cost management. The critical goal of incentives is to obtain these
7 improved margins without sacrificing quality of service. That is what a
8 balanced incentive program achieves.
9
10 Q. WHAT DOES MR. GARRETT RECOMMEND IN HIS ANALYSIS OF THE
11 EAM AND THE ANNUAL INCENTIVE PLANS?
12 A. On his pages 50-51, Mr. Garrett’s relies on the use of the EAM as the
13 basis for the possible disallowance of all annual incentive payments.
14
15 Q. IS IT REASONABLE TO DISALLOW INCENTIVE COMPENSATION
16 COSTS BECAUSE THE OVERALL FUNDING MECHANISM (THE EAM)
17 IS FINANCIAL IN NATURE?
18 A. No. It only makes common sense, from the Company’s and customers’
19 perspective, to ensure that the Company is able to afford to pay out the
20 annual incentive payments before it does so. Funding mechanisms within
21 incentive plans such as the EAM simply support the Company’s financial
22 capacity to pay for operational performance-based programs. The
23 benefits that the ratepayers receive from the operational-based goals in
11
Entergy Texas, Inc. Page 10 of 18
Rebuttal Testimony of Kevin G. Gardner
Docket No. 39896
1 the incentive compensation plans are in no way diminished by the fact that
2 the Company requires a funding mechanism to ensure its capability to pay
3 out incentives.
4 Lack of prudent financial controls would not be in the best interest
5 of the Company’s customers, employees, or shareholders. All companies,
6 whether categorized as regulated utilities or general industries, must
7 employ sound financial management.
8
9 Q. DO YOU AGREE WITH MR. GARRETT’S STATEMENTS ON HIS
10 PAGES 49-50 AND 52 THAT AN EVEN LARGER DISALLOWANCE OF
11 INCENTIVE COMPENSATION COSTS MAY BE MERITED BY THE
12 COMPANY’S LEVELS OF CUSTOMER SATISFACTION?
13 A. No, as explained in the rebuttal testimony of Company witness
14 Vernon Pierce, the facts support the exact opposite result.
15
16 III. ALLEGATIONS REGARDING BASE PAY AND BENEFITS LEVELS
17 Q. PLEASE DESCRIBE THE TESTIMONY OF MR. GARRETT REGARDING
18 ABOVE-MARKET BASE PAY.
19 A. On his pages 25-27, Mr. Garrett alleges that the Company’s base pay
20 levels are 2% above market. He then asserts that ratepayers should only
21 be asked to pay the necessary market-based price for employee pay, and
22 he recommends a 2% downward adjustment to base pay costs to “bring
23 the Company’s base pay down to a market-based level.”
12
Entergy Texas, Inc. Page 11 of 18
Rebuttal Testimony of Kevin G. Gardner
Docket No. 39896
1 Q. DO YOU AGREE WITH HIS ALLEGATIONS AND RECOMMENDATION?
2 A. No. The Company’s base pay is not 2% above market. The Company’s
3 test year base pay was 2% above market median. For the reasons
4 explained below, being “at market” means being within a reasonable
5 range, such as +/-10%, of the market median; therefore, the Company’s
6 base pay levels are at market.1
7 As indicated in my direct testimony, the Entergy Companies have
8 established a pay philosophy that is competitive with the market. The
9 Entergy Companies focus wages on a reasonable range around the
10 50th percentile of the market. That is the point at which half the companies
11 in the surveys pay total annual compensation that exceeds the market's
12 total annual compensation midpoint and half the companies in the surveys
13 pay less than the market's total annual compensation midpoint. The
14 Entergy Companies consider this to be a competitive but reasonable pay
15 philosophy.
16 To obtain market data, the Entergy Companies participate in well-
17 established and highly-regarded surveys from providers such as Towers
18 Watson, Mercer and AON Hewitt (formerly, Hewitt Associates). However,
19 no two jobs, even within the same organization, are likely to be identical,
20 much less between organizations. There are many jobs that cannot be
21 matched at all and must be slotted internally. The details of the survey
1
Further, as I indicated on page 23 of my direct testimony, some compensation consultants
would even use a +/- 15 percent range for pay levels. At this point, the Entergy Companies
continue to target +/- 10 percent in establishing compensation levels.
13
Entergy Texas, Inc. Page 12 of 18
Rebuttal Testimony of Kevin G. Gardner
Docket No. 39896
1 data can vary among participating organizations. As a result,
2 benchmarking jobs to the market is an inexact science.
3 Although benchmarking has its place in compensation analyses,
4 and is commonly used by HR departments and professionals, there are
5 differences in how companies match job responsibilities with job titles and
6 in how companies complete the compensation survey information. These
7 limitations do not invalidate benchmark comparisons of compensation
8 levels, but they do add an element of imprecision to any comparison of
9 compensation by job title.
10 With this in mind, when using a benchmark analysis to compare
11 companies' levels of compensation, it is advisable to view the market level
12 of compensation as a range (e.g., +/- 10% of a mid-point) rather than a
13 precise, single point. Market data for numerous positions move from year
14 to year, so the Entergy Companies see annual compensation of +/-10% of
15 market median as both a reasonable and necessary expense to provide
16 service to the public. This approach is not just an Entergy Companies'
17 point of view, but one commonly used by compensation consultants.
14
Entergy Texas, Inc. Page 13 of 18
Rebuttal Testimony of Kevin G. Gardner
Docket No. 39896
1 Q. PLEASE DESCRIBE THE ALLEGATIONS OF MR. GARRETT
2 REGARDING ABOVE-MARKET BENEFITS.
3 A. On his pages 58-59, Mr. Garrett states that the value of the Company’s
4 employment benefit plans is 14% above market when compared to a peer
5 group of Fortune 500 companies. He then asserts that ratepayers should
6 only be asked to pay the market-based price for employee costs, and
7 recommends a 14% downward adjustment to the Company’s employee
8 benefits expense.
9
10 Q. DO YOU AGREE WITH MR. GARRETT’S ALLEGATIONS AND
11 RECOMMENDATION?
12 A. No. The value of the Company’s benefits plans is not 14% above market.
13 Table 6 on page 42 of my direct testimony shows that the value of the
14 Entergy Companies’ benefits plans is only 1% above the market median of
15 the peer group of utility companies. As noted with regard to base pay,
16 being “at market” means being within 10% of the market median; therefore
17 the Company’s benefits levels are at market with regard to its peer group
18 of utility companies.2 Even if one gives equal weight to the reported
19 benefits plan values of the Fortune 500 companies and the peer utilities,
20 the value of the Company’s benefit plans is at market. Moreover, the peer
21 group of utility companies provides a more appropriate comparison for the
22 Company’s benefits plans because utilities often need to attract more
2
Nowhere did I purport to identify a “peer group of Fortune 500 companies.”
15
Entergy Texas, Inc. Page 14 of 18
Rebuttal Testimony of Kevin G. Gardner
Docket No. 39896
1 long-term employees than Fortune 500 companies, such as the nation’s
2 large retail companies. Experienced, long-term employees are needed to
3 operate and manage the utility infrastructure. Employee retention is thus
4 a particularly important issue for utilities, and benefits plans play an
5 important role in achieving strong retention rates. Accordingly, the
6 Company’s benefit plan levels are well within a reasonable range, and no
7 disallowance should be required.
8
9 IV. SUPPLEMENTAL EXECUTIVE RETIREMENT BENEFITS PLANS
10 Q. PLEASE DESCRIBE THE ISSUE RAISED BY THE STAFF, CITIES AND
11 OPUC WITNESSES REGARDING SUPPLEMENTAL EXECUTIVE
12 RETIREMENT PLANS.
13 A. The Company provides three types of supplemental executive retirement
14 plans that are addressed by Staff witness Givens, Cities witness Garrett
15 and OPUC witness Szerszen. The plans include the Pension Equalization
16 Plan, the Supplemental Retirement Plan, and the System Executive
17 Retirement Plan. The plans are further described in Schedule G-2 to the
18 Company’s Rate Filing Package. Ms. Givens recommends, on her pages
19 22-23, and Mr. Garrett recommends, on his page 55, a disallowance of
20 both ETI and ESI-billed costs for these programs, quantifying the total
21 amount as $2,114,931.3 Dr. Szerszen recommends a disallowance of the
3
Company witness Tumminello identifies $112,531 of these ESI costs that should not have
been charged to ETI.
16
Entergy Texas, Inc. Page 15 of 18
Rebuttal Testimony of Kevin G. Gardner
Docket No. 39896
1 portion of these costs allocated from ESI to ETI, which she quantifies at
2 $1,391,861.4 Mr. Garrett argues that these costs are not necessary to
3 provide utility service but are instead discretionary payments that should
4 be funded by shareholders. Dr. Szerszen contends that ETI has not
5 shown that these costs are necessary to provide utility service, and that
6 the ESI allocation method is unjustified. Ms. Givens describes the
7 payments as excessive. I disagree with each of these contentions.
8
9 Q. WHY ARE THE COSTS OF THESE PLANS REASONABLE AND
10 NECESSARY?
11 A. Supplemental executive retirement plans are established for the purpose
12 of attracting, retaining, and motivating highly competent and qualified
13 leaders. In particular, the Pension Equalization Plan provides
14 supplemental retirement benefits to account for the fact that Internal
15 Revenue Code regulations limit the level of retirement benefits that qualify
16 for tax treatment favorable to ETI and Entergy Corporation. The existence
17 of this supplemental benefit program allows the Company to pay
18 retirement benefits to these employees that are proportionate to the
19 compensation they receive while active in their employment.
20 In addition, the Supplemental Retirement Plan and the System
21 Executive Retirement Plan provide supplemental benefits beyond the
4
Company witness Tumminello identifies $112,531 of these costs that should not have been
charged to ETI.
17
Entergy Texas, Inc. Page 16 of 18
Rebuttal Testimony of Kevin G. Gardner
Docket No. 39896
1 amounts restricted in the qualified plan to some participants to attract,
2 retain, and motivate employees.
3 These retirement benefits are widely provided by companies within
4 the utility business sector. Accordingly, ETI needs to offer them in order to
5 be competitive in the employment market with peer companies, and
6 thereby to retain and adequately compensate these employees in terms of
7 future retirement benefits. For these reasons, I conclude that the costs to
8 ETI of these plans are reasonable and necessary.
9
10 Q. OPUC WITNESS SZERSZEN SUGGESTS THAT AN ADDITIONAL
11 REASON TO DENY RECOVERY OF ESI AFFILIATE CHARGES FOR
12 SUPPLEMENTAL RETIREMENT BENEFITS IS THAT THERE IS NO
13 CAUSAL RELATIONSHIP BETWEEN THESE TYPES OF COSTS AND
14 THE ALLOCATION METHOD USED TO BILL ETI ITS SHARE. WHICH
15 COMPANY WITNESSES ADDRESSES THIS ISSUE?
16 A. Company witness Stephanie B. Tumminello addresses this issue.
18
Entergy Texas, Inc. Page 17 of 18
Rebuttal Testimony of Kevin G. Gardner
Docket No. 39896
1 V. RELOCATION COSTS
2 Q. WHAT IS MS. GIVENS’ POSITION ON EMPLOYEE RELOCATION
3 ASSISTANCE, AND DO YOU AGREE WITH HER
4 RECOMMENDATION?
5 A. On her page 24, Staff witness Givens recommends that this type of
6 expense be disallowed based on their removal from cost of service in
7 Lower Colorado River Authority Docket No. 28906 and the level of
8 ETI’s annual compensation. I disagree with her recommendation.
9 Finding of Fact No. 86 in the Commission’s final order in Docket
10 No. 28906 states that “LCRA’s wages are competitive, thus a bonus or
11 moving allowance is not necessary to attract quality personnel.” For
12 the employee market in which ETI operates, however, most peer
13 companies offer moving assistance. Such assistance is expected by
14 employees, and the Company would be placed at a competitive
15 disadvantage if it did not offer it.
16 Further, though Ms. Givens points to the Company’s level of
17 annual compensation as a basis for disallowing this benefit cost, she
18 sought to disallow no other benefits costs. Just as the Company’s level
19 of compensation does not merit disallowing medical and dental benefits
20 costs, it does not merit disallowing relocation cost benefits if the level of
21 such costs is reasonable. Ms. Givens does not dispute the
22 reasonableness of the amount. In fact, as I indicated by my direct
19
Entergy Texas, Inc. Page 18 of 18
Rebuttal Testimony of Kevin G. Gardner Revised – Errata No. 7
Docket No. 39896
1 testimony on page 46, the Entergy Companies’ average relocation
2 assistance amounts during the test year were reasonable when
3 compared to 2010 industry average relocation costs as reported by the
4 Employee Relocation Council. Recovery of this expense should be
5 authorized.1
6
7 Q. DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY?
8 A. Yes.
1
Staff witness Givens also recommends a disallowance related to certain executive
perquisites; the Company is not opposing that adjustment.
SOAH Docket No. XXX-XX-XXXX
PUC Docket No. 39896
ETI 2011 Rate Case
ETI EXHIBIT NO. 53
SOAH DOCKET NO. XXX-XX-XXXX
PUC DOCKET NO. 39896
APPLICATION OF ENTERGY §
TEXAS, INC. FOR AUTHORITY TO § BEFORE THE
CHANGE RATES, RECONCILE § STATE OFFICE OF
FUEL COSTS, AND OBTAIN § ADMINISTRATIVE HEARINGS
DEFERRED ACCOUNTING §
TREATMENT §
REBUTTAL TESTIMONY
OF
JAY C. HARTZELL, Ph.D.
ON BEHALF OF
ENTERGY TEXAS, INC.
APRIL 2012
1
ENTERGY TEXAS, INC.
REBUTTAL TESTIMONY OF JAY C. HARTZELL, Ph.D.
DOCKET NO. 39896
TABLE OF CONTENTS
Page
I.  Introduction and Qualifications 1
II.  Purpose of Rebuttal Testimony 1
III.  Response to Mr. Garrett’s Policy Arguments Opposing Inclusion of
“Financially” Related Incentive Compensation in Rates 2
IV.  Response to Mr. Pollock’s and Ms. Givens' Policy Arguments
Opposing Inclusion of “Financially” Related Incentive Compensation
in Rates 13
V.  Conclusion 15
2
Entergy Texas, Inc. Page 1 of 15
Rebuttal Testimony of Jay C. Hartzell, Ph.D.
Docket No. 39896
1 I. INTRODUCTION AND QUALIFICATIONS
2 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
3 A. My name is Jay C. Hartzell. I am the Chair of the Finance Department,
4 Professor of Finance, and the Allied Bancshares Centennial Fellow at the
5 McCombs School of Business at the University of Texas at Austin. My
6 business address is Department of Finance, The University of Texas at
7 Austin, 1 University Station B6600, Austin, Texas 78712.
8
9 Q. DID YOU PREVIOUSLY FILE DIRECT TESTIMONY ON BEHALF OF
10 ENTERGY TEXAS, INC. (“ETI” OR “THE COMPANY”) IN THIS
11 PROCEEDING?
12 A. Yes, I did.
13
14 II. PURPOSE OF REBUTTAL TESTIMONY
15 Q. WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY?
16 A. My Rebuttal Testimony addresses certain arguments raised by Cities
17 witness Garrett, by Staff witness Givens, and by TIEC witness Pollock in
18 opposition to inclusion in rates of what has been termed “financially”
19 related incentive compensation.
3
Entergy Texas, Inc. Page 2 of 15
Rebuttal Testimony of Jay C. Hartzell, Ph.D.
Docket No. 39896
1 III. RESPONSE TO MR. GARRETT’S POLICY ARGUMENTS
2 OPPOSING INCLUSION OF “FINANCIALLY” RELATED
3 INCENTIVE COMPENSATION IN RATES
4 Q. WHAT PORTIONS OF MR. GARRETT’S TESTIMONY ARE YOU
5 ADDRESSING?
6 A. Mr. Garrett makes several arguments as to why “financially” based
7 incentive compensation should be excluded from rates. Specifically, he
8 argues that:
9 1) Payment is uncertain.
10 2) Incentive plans tied to company earnings performance are held in
11 general disfavor because many factors that significantly impact
12 earnings are outside the control of most company employees and
13 have limited value to customers.
14 3) Earnings-based incentive plans can discourage conservation.
15 4) The utility and its stockholders assume none of the financial risks
16 associated with financially based incentive payments.
17 5) Incentive payments based on financial performance measures
18 should be made out of increased earnings.
19 6) Financially based incentive payments embedded in rates shelter
20 the utility against the risk of earnings erosion through attrition.
21 Mr. Garrett goes on to argue that financial incentives differ from
22 operational incentives because ratepayers have no stake in an incentive
23 plan design based on financial performance measures, while they do have
24 a stake in such a plan to the extent it is based on operational performance
4
Entergy Texas, Inc. Page 3 of 15
Rebuttal Testimony of Jay C. Hartzell, Ph.D.
Docket No. 39896
1 measures. There are logical and theoretical problems with these
2 arguments, as I discuss below. Company witness Kevin G. Gardner also
3 addresses the flaws in Mr. Garrett’s analysis.
4
5 Q. PLEASE ADDRESS MR. GARRETT’S ARGUMENT THAT FUTURE
6 PAYMENT OF FINANCIALLY BASED INCENTIVE COMPENSATION IS
7 UNCERTAIN.
8 A. It is true that payment of incentive compensation in the future is designed
9 to be uncertain. Indeed, this is a key aspect of the effectiveness of
10 incentive compensation, because the risk associated with the level of
11 future compensation provides incentives for positive employee
12 performance. However, this uncertainty does not imply that such incentive
13 compensation is an unreasonable, unnecessary, or non-recurring
14 business expense. If Mr. Garrett’s argument were valid, no incentive
15 compensation, whether it is financially or operationally based, would be a
16 candidate for inclusion in rates, which is a position already considered and
17 rejected by the Commission.1 At some level, many future costs of doing
18 business are uncertain at the time rates are set. I understand that by
19 using a “test year,” the Commission has a sample data point that, despite
1
See Application of Oncor Electric Delivery Company for Authority to Change Rates, Docket
No. 35717, Proposal for Decision at 100 (Jun 2, 2009) (stating that, despite the fact that
incentive compensation plans are conditional by nature, the Commission has allowed
recovery based on operational measures) and Order on Rehearing Findings of Fact 91-93
and Ordering Paragraph 1 (Nov. 30, 2009) (adopting the PFD to the degree consistent with
the order on rehearing).
5
Entergy Texas, Inc. Page 4 of 15
Rebuttal Testimony of Jay C. Hartzell, Ph.D.
Docket No. 39896
1 this inherent level of uncertainty, becomes the starting point for setting
2 rates. ETI’s incentive compensation plan design provides the potential for
3 payment of incentive compensation at varying levels dependent on the
4 degree of financial success. This potential variation is consistent with the
5 use of the test-year level of incentive compensation payments as the basis
6 for setting rates.
7
8 Q. WHAT IS YOUR RESPONSE TO MR. GARRETT’S POSITION THAT
9 INCENTIVE PLANS BASED ON COMPANY EARNINGS ARE HELD IN
10 GENERAL DISFAVOR BECAUSE MANY FACTORS THAT
11 SIGNIFICANTLY IMPACT EARNINGS ARE OUTSIDE THE CONTROL
12 OF MOST COMPANY EMPLOYEES AND HAVE LIMITED VALUE TO
13 CUSTOMERS?
14 A. Here, Mr. Garrett uses examples of “good luck” to argue that because
15 random chance can influence whether employees make targets or not,
16 this possibility somehow leads to the conclusion that such compensation
17 plans are held in disfavor. Mr. Garrett, however, conveniently ignores the
18 fact that the luck might be bad – e.g., an unseasonably mild summer might
19 weaken the firm’s financial performance and make it less likely that the
20 firm hits some financial targets. Moreover, the impact of such events can
21 also affect the level of performance on operational measures such as
22 reliability, such that Mr. Garrett’s argument raises no meaningful
6
Entergy Texas, Inc. Page 5 of 15
Rebuttal Testimony of Jay C. Hartzell, Ph.D.
Docket No. 39896
1 distinction from the types of incentive payments that the Commission
2 currently allows in rates.
3 The effect of random chance – both positive and negative
4 surprises – is why nearly every overall compensation package provides
5 some component of safe pay, such as salary, instead of consisting of only
6 incentive-based pay. An incentive-only pay package would be too risky
7 from the employee’s perspective and too expensive from the firm’s
8 perspective due to this greater risk. A balanced approach, however, that
9 includes some incentive compensation, adds the possibility of a reward to
10 the negative of risk. Moreover, that possibility of reward motivates
11 employees to take actions that are in the shareholders’ and ratepayers’
12 best interests.
13 The uncertainty of payment of a portion of their compensation
14 provides incentives for employees to take actions that are in the best
15 interest of shareholders and ratepayers alike. The nature of the workplace
16 is such that it is impossible to perfectly observe and verify the employees’
17 actions. Instead, one must rely on signals or indications. These signals or
18 indications will include some element of luck or chance. Ultimately, by
19 properly balancing such incentive compensation with fixed salaries, all
20 parties can be better off – employees, shareholders, and customers.
7
Entergy Texas, Inc. Page 6 of 15
Rebuttal Testimony of Jay C. Hartzell, Ph.D.
Docket No. 39896
1 Q. WHAT IS YOUR RESPONSE TO MR. GARRETT’S CONTENTION THAT
2 EARNINGS-BASED INCENTIVE PLANS CAN DISCOURAGE
3 CONSERVATION?
4 A. Mr. Garrett hypothesizes that an earnings-based performance target will
5 improperly motivate employees to disregard beneficial programs such as
6 demand side management, if they perceive that such programs may
7 depress earnings. Mr. Garrett offers no evidence that any such incentive
8 is created by ETI’s incentive plan. Moreover, to the extent that an
9 incentive plan encourages the attraction of incremental customers – such
10 as in connection with an economic development program – it may have
11 the positive result of spreading the Company’s fixed costs among a larger
12 customer base, to the benefit of all customers. More fundamentally, an
13 appropriate balance of performance incentives in the incentive plan design
14 will avoid the result hypothesized. For example, when an incentive plan
15 design balances both earnings targets and cost control performance
16 through budget and process efficiency targets, the design should lead
17 managers to reduce costs, which in the long run will directly benefit
18 customers. At the same time, including performance targets related to
19 reliable service and customer satisfaction helps ensure that cost-cutting
20 does not erode customer service.
8
Entergy Texas, Inc. Page 7 of 15
Rebuttal Testimony of Jay C. Hartzell, Ph.D.
Docket No. 39896
1 Q. IS MR. GARRETT CORRECT THAT THE UTILITY AND ITS
2 STOCKHOLDERS ASSUME NONE OF THE FINANCIAL RISKS
3 ASSOCIATED WITH INCENTIVE PAYMENTS?
4 A. Based on my understanding of the ratemaking process, this statement is
5 false. If the exact level of incentive compensation for every year was
6 included in rates in that year, then it might be true. However, by using a
7 test year and setting the appropriate incentive compensation level based
8 on that year’s data, an expected level of incentive compensation is
9 included in future rates. The utility and shareholders still face financial risk
10 or variation due to fluctuations around that expected level. If incentive
11 compensation is above the amount put in rates, shareholders of the firm
12 will pay that extra amount.
13 In addition, Mr. Garrett’s claim here misses the whole point of
14 incentive compensation. The reason incentive compensation is effective
15 is that it puts a portion of the employees’ pay at risk. The goal is not to put
16 more risk on the shareholders – they are already bearing the risk of the
17 employees’ actions that affect the firms’ profitability. By exposing
18 employees’ pay to risk or variation, employees have an increased
19 incentive to take actions that are in both shareholders’ and ratepayers’
20 best interests.
9
Entergy Texas, Inc. Page 8 of 15
Rebuttal Testimony of Jay C. Hartzell, Ph.D.
Docket No. 39896
1 Q. IS THERE ANY MERIT TO MR. GARRETT’S CLAIM THAT INCENTIVE
2 PAYMENTS BASED ON FINANCIAL PERFORMANCE MEASURES
3 SHOULD BE MADE OUT OF INCREASED EARNINGS?
4 A. I do not understand Mr. Garrett’s claim or objection here. The test year
5 provides a measure of “expected” or “normal” compensation, including
6 both salaries and reasonable or customary incentive compensation. It is
7 this expected level that is recovered through rates, and thus, shareholders
8 do indeed bear the cost of any additional – or, better than expected –
9 compensation. Thus, what Mr. Garrett claims should happen is exactly
10 what does happen; shareholders pay for compensation that is greater than
11 expectations out of increased earnings.
12
13 Q. IS MR. GARRETT’S VIEW CORRECT THAT INCENTIVE PAYMENTS
14 EMBEDDED IN RATES SHELTER THE UTILITY AGAINST THE RISK OF
15 EARNINGS EROSION THROUGH ATTRITION?
16 A. No. Including a representative level of incentive compensation in rates
17 does not act as a typical financial hedge, unlike the characterization put
18 forth by Mr. Garrett. Hedges act as insurance and pay off more if the
19 firm’s performance weakens. Recovering incentive compensation through
20 rates would provide a level cash flow to the utility, holding revenues
21 constant. If the firm’s performance weakens due to shocks to its cost
22 structure, then this level cash flow would indeed improve its financial
23 stability, but no more so than other cost components of the rates in place.
10
Entergy Texas, Inc. Page 9 of 15
Rebuttal Testimony of Jay C. Hartzell, Ph.D.
Docket No. 39896
1 However, if the performance weakens due to a drop in revenues (for
2 example, due to a drop in electricity consumption), then the cash flow
3 traced to the inclusion of incentive compensation in rates would drop as
4 well (because it is part of the costs that go into establishing the per-unit
5 price). Even if the additional cash flow improves the financial health of the
6 utility, however, a financially healthy utility is in the customers’ best
7 interest. As I pointed out in my Direct Testimony, a utility that is financially
8 unhealthy would likely incur greater costs in the future that would be borne
9 by customers.
10 This last point brings up another problem with Mr. Garrett’s
11 testimony. He states:
12 When incentive compensation payments are based on
13 financial performance measures, the compensation
14 agreement between shareholders and employees could be
15 loosely stated in this manner: “if you increase shareholder
16 earnings, we will pay you a bonus.” The intended
17 beneficiaries to this agreement are the shareholders and the
18 employees. Ratepayers have no stake in this agreement;
19 therefore, they should bear none of the costs that result from
20 such an agreement. If, instead, the agreement were stated
21 in this manner: “if you will help increase reliability and quality
22 of service to the customers, and reduce fuel and purchased
23 power costs, we will pay you a bonus,” then, ratepayers
24 would have a stake in the agreement, and could share in a
25 portion of the costs. (See page 39.)
26 Mr. Garrett’s statement that ratepayers have no stake in the first
27 agreement he references is false in my opinion. Ratepayers are likely to
28 benefit from a financially healthy utility for the many reasons discussed in
29 my Direct Testimony. In addition, a well-balanced incentive plan that
11
Entergy Texas, Inc. Page 10 of 15
Rebuttal Testimony of Jay C. Hartzell, Ph.D.
Docket No. 39896
1 rewards employees based on operational measures in addition to financial
2 measures will help ensure that improvements in shareholders’ welfare do
3 not come at the expense of ratepayers’ welfare.
4
5 Q. IS MR. GARRETT’S STATEMENT THAT RATEPAYERS HAVE NO
6 STAKE IN INCENTIVE COMPENSATION AGREEMENTS BASED ON
7 FINANCIAL PERFORMANCE MEASURES LOGICAL AND CONSISTENT
8 WITH HIS OTHER STATEMENTS?
9 A. No. In addition to the benefits that ratepayers experience from a
10 financially healthy utility (as discussed in my Direct Testimony), perhaps
11 the easiest way to see the error in Mr. Garrett’s argument that ratepayers
12 have no stake in such incentive compensation plans is to consider an
13 incentive plan that motivates employees to achieve increased efficiencies
14 or control costs. Because of the regulatory process, the benefits of any
15 cost controls would be passed along to ratepayers through lower rates in
16 the future. Thus, it seems obvious that it is in the ratepayers’ interests that
17 the utility implements a fair and reasonable incentive compensation plan
18 that motivates employees to control costs.
19 Mr. Garrett admits this point on page 31 of his testimony, where he
20 states: “To the contrary, incentive plans that motivate employees to
21 achieve increased efficiencies (i.e., cost control) should be encouraged.”
22 He goes on to argue that because the utility retains such cost savings
23 between rate cases, the utility should pay for the incentive compensation
12
Entergy Texas, Inc. Page 11 of 15
Rebuttal Testimony of Jay C. Hartzell, Ph.D.
Docket No. 39896
1 rather than the ratepayers. Based on this discussion, it is clear that
2 Mr. Garrett understands that ratepayers ultimately benefit from incentive
3 compensation plans that lead to greater cost control, via the regulatory
4 process. Thus, Mr. Garrett contradicts his later statement on page 39 that
5 ratepayers have no stake in these types of agreements.
6
7 Q. IN ADDITION TO THESE INTERNAL INCONSISTENCIES, DOES MR.
8 GARRETT’S POSITION ALSO CONTRADICT THOSE OF MR.
9 POLLOCK AND MS. GIVENS?
10 A. Yes. Mr. Pollock and Ms. Givens do not object to the inclusion of
11 compensation based on cost controls. In fact, Mr. Pollock acknowledges
12 in his deposition that compensation based on cost controls will tend to
13 benefit ratepayers.2 In contrast, Mr. Garrett includes compensation based
14 on cost controls as financially-based, and then argues that it should be
15 excluded, in spite of his admission that it benefits ratepayers and should
16 be encouraged.
2
See pages 39-40 of Mr. Pollock’s deposition, dated April 9, 2012.
13
Entergy Texas, Inc. Page 12 of 15
Rebuttal Testimony of Jay C. Hartzell, Ph.D.
Docket No. 39896
1 Q. CAN YOU GIVE A SIMPLE EXAMPLE TO ILLUSTRATE THE BENEFIT
2 TO RATEPAYERS OF COST CONTROLS AS PART OF THE
3 REGULATORY PROCESS?
4 A. Yes. Consider a simple example where, due to an incentive
5 compensation plan that rewards cost controls, an employee comes up
6 with an idea that reduces the cost of delivering service by $1 per year, in
7 perpetuity. In order to convert this stream of cost savings into a value
8 today, one needs to use an interest (or discount) rate that captures
9 ratepayers’ and shareholders’ preferences for cash today relative to cash
10 in the future. To use round but plausible numbers, consider the case
11 where ratepayers and shareholders are willing to accept a 10 percent
12 return on their investments. In this case, the $1 annual cost saving would
13 generate $10 of value or wealth (calculated as $10 = $1 / 0.10).3
14 Next, assume that the time between the cost savings and the next
15 rate case is three years. In this example, shareholders receive the benefit
16 of the first three years of cost savings, while ratepayers receive the
17 savings for year four and beyond. Using the 10 percent discount rate, the
18 value of the cost savings that is captured by the shareholders is about
19 $2.49, while the remaining $7.51 accrues to the ratepayers.4 Thus, about
20 25 percent of the value of cost savings is passed to the shareholders,
3
Intuitively, this is the value because one could invest $10 at a 10 percent rate of return and
generate the equivalent $1 per year, forever.
4
This is calculated as 1/1.1 + 1/(1.1^2) + 1/(1.1^3) = 2.49, and 10 – 2.49 = 7.51.
14
Entergy Texas, Inc. Page 13 of 15
Rebuttal Testimony of Jay C. Hartzell, Ph.D.
Docket No. 39896
1 while 75 percent goes to the ratepayers. Clearly, the ratepayers have a
2 stake in the agreement that provided the employee with the incentive to
3 control costs. In fact, in this scenario, the ratepayers’ stake is even more
4 significant than that of the shareholders.
5
6 IV. RESPONSE TO MR. POLLOCK’S AND MS. GIVENS’
7 POLICY ARGUMENTS OPPOSING INCLUSION OF
8 “FINANCIALLY” RELATED INCENTIVE
9 COMPENSATION IN RATES
10 Q. WHAT PORTIONS OF MR. POLLOCK’S AND MS. GIVENS’ TESTIMONY
11 ARE YOU ADDRESSING?
12 A. Mr. Pollock and Ms. Givens both discuss incentive compensation, and
13 assert that compensation expense related to achieving financial objectives
14 should be disallowed.
15
16 Q. DO YOU AGREE WITH MR. POLLOCK’S STATEMENT THAT
17 INCENTIVE COMPENSATION BASED ON ACHIEVING CERTAIN
18 FINANCIAL GOALS OF ENTERGY SHOULD BE DISALLOWED ON THE
19 BASIS THAT IT BENEFITS ONLY SHAREHOLDERS NOT
20 CUSTOMERS?
21 A. No. Mr. Pollock makes this statement on pages 41-42 of his testimony.
22 As discussed earlier in this Rebuttal Testimony and in my Direct
23 Testimony, there are several reasons why ratepayers benefit from a
24 financially healthy utility. Incentive compensation based on financial
15
Entergy Texas, Inc. Page 14 of 15
Rebuttal Testimony of Jay C. Hartzell, Ph.D.
Docket No. 39896
1 measures is an important tool used to promote financial health, which in
2 turn tends to benefit ratepayers.
3
4 Q. DOES MR. POLLOCK OFFER ANY ADDITIONAL SUPPORT FOR HIS
5 CLAIM THAT INCENTIVE COMPENSATION EXPENSE LINKED TO
6 FINANCIAL PERFORMANCE SHOULD BE EXCLUDED?
7 A. Beyond his assertion that ratepayers do not benefit from a financially
8 healthy utility or from cost controls, Mr. Pollock’s recommendation appears
9 to be based solely on past precedent. On page 44, in response to the
10 question, “What is the basis for your recommendation?” he states, “My
11 recommendation is consistent with past precedent,” and goes on to
12 discuss previous Commission findings. He does not present additional
13 analysis of his own in support of his recommendation.
14
15 Q. DOES MS. GIVENS OFFER ANY ADDITIONAL SUPPORT FOR HER
16 CLAIM THAT INCENTIVE COMPENSATION EXPENSE LINKED TO
17 FINANCIAL PERFORMANCE SHOULD BE EXCLUDED?
18 A. Like Mr. Pollock, Ms. Givens’ recommendation appears to be based solely
19 on past precedent. She discusses this history on pages 16-18 of her
20 testimony, but she does not present additional analysis of her own in
21 support of her recommendation.
16
Entergy Texas, Inc. Page 15 of 15
Rebuttal Testimony of Jay C. Hartzell, Ph.D.
Docket No. 39896
1 V. CONCLUSION
2 Q. DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY?
3 A. Yes.
17
12
Cathleen Parsley
Chief Administrative Law Judge
July 6, 2012
TO: Stephen Journeay, Director COURIER PICK-UP
Commission Advising and Docket Management
William B. Travis State Office Building
1701 N. Congress, 7th Floor
Austin, Texas 78701
RE: SOAH Docket No. XXX-XX-XXXX
PUC Docket No. 39896
Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel
Costs, and Obtain Deferred Accounting Treatment
Enclosed is the Proposal for Decision (PFD) in the above-referenced case. By copy of
this letter, the parties to this proceeding are being served with the PFD.
Please place this case on an open meeting agenda for the Commissioners' consideration.
The jurisdictional deadline for this case is July 30, 2012. Please notify me and the parties of the
open meeting date, as well as the deadlines for filing exceptions to the PFD, replies to the
exceptions, and requests for oral argument.
:Ji;;;:-J.
Steven D. Arnold
Administrative Law Judge
Enclosure
xc: All Parties of Record
300 W. 15th Street, Suite 502, Austin, Texas 78701/ P.O. Box 13025, Austin, Texas 78711-3025
512.475.4993 (Main) 512.475.3445 (Docketing) 512.322.2061 (Fax)
www.soah.state.tx.us
SOAH DOCKET NO. XXX-XX-XXXX
PUC DOCKET NO. 39896
APPLICATION OF ENTERGY TEXAS, § BEFORE THE STATE OFFICE
INC. FOR AUTHORITY TO CHANGE §
RATES, RECONCILE FUEL COSTS, § OF
AND OBTAIN DEFERRED §
ACCOUNTING TREAT:MENT § ADMINISTRATIVE HEARINGS
PROPOSAL FOR DECISION
I. INTRODUCTION [Germane to Preliminary Order Issue Nos. 1 and 4]
Entergy Texas, Inc. (ETI or the Company) is an investor-owned electric utility with a retail
service area located in southeastern Texas. ETI serves retail and wholesale electric customers in
Texas. As ofJune 30, 2011, ETI served approximateI y 412,000 Texas retail customers. The Federal
Energy Regulatory Commission (FERC) regulates ETI's wholesale electric operations.
On November 28, 2011, ETI filed an application requesting approval of: (1) a proposed
increase in annual base rate revenues of approximately $111.8 million over adjusted revenues for the
period beginning July 1, 2010, and ending June 30, 2011 (Test Year); (2) a set of proposed tariff
schedules presented in the Electric Utility Rate Filing Package for Generating Utilities accompanying
ETI' s application and including new riders for recovery of costs related to purchased power capacity
and renewable energy credit requirements; (3) a request for final reconciliation of ETI's fuel and
purchased power costs for the reconciliation period from July 1, 2009, to June 30, 2011
(Reconciliation Period); and (4) certain waivers to the instructions in Rate Filing Package
Schedule V accompanying ETI' s application. The rate year for ETI' s proposed changes is June 1,
2012, through May 31, 2013 (Rate Year). 1 On April 13, 2012, adjusted its request for a proposed
increase in annual base rate revenues to approximately $104.8 million over adjusted Test Year
revenues.
1
During the hearing the parties used the term "Rate Year" to refer to the period June 2012 through May
2013. This was intended to represent the first 12 months of the rates adopted in this case. However, the rates
in this case will not go into effect (as temporary rates) until at least June 30, 2012. Nevertheless, for purposes
of this PFD, Rate Year will refer to the period June 2012 through May 2013.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 166
PUC DOCKET NO. 39896
the corrections to Staffs adjustments that were suggested by ETI, and the AU s can find no basis for
challenging those corrections. Thus, the Al.Js recommend that the Commission: (1) accept the
payroll adjustments proposed in the ETI application; and (2) accept the further payroll adjustments
proposed by Staff, corrected by ETI.
2. Incentive Compensation
One of the hotly contested issues concerns the extent to which ETI should be allowed to
recover, through its rates, the incentive compensation it pays to its employees. All parties agree that
Commission precedent generally identifies two types of incentive compensation, only one of which
is recoverable. Specifically, pursuant to Commission precedent, incentive compensation that is tied
to operational goals is recoverable, while incentive compensation that is tied to financial goals is
not. 569 In its application, however, ETI requests that it be allowed to recover its Test Year costs of
all of its incentive compensation costs, regardless of whether those costs are tied to operational goals
or to financial goals.
(a) Financially Based Incentive Compensation Should Not Be Recoverable
ETI acknowledges that costs of incentive compensation tied to financial goals have typically
been disallowed by the Commission. However, ETI asks for the Commission to reconsider its
precedents on this issue. 570 ETI argues that the Commission precedent is not, and should not be, a
hard and fast rule. ETI contends that the reason why cost recovery has been denied for incentive
compensation in prior rates cases is that, in those prior cases, there was "a lack of evidence showing
sufficient customer benefits."571 ETI asserts that, in this case, it has assembled evidence not
previously considered by the Commission that shows the benefits to customers of using financial
569
See, e.g., TIEC Initial Brief at 51-52; see also AEP Application of AEP Texas Central Company for
Authority to Change Rates, See Docket No. 33309, Order on Rehearing at FoF 82 (Mar. 4, 2007); Application
of AEP Texas Central Company for Authority to Change Rates, Docket No. 28840, Order at FoF 164-170
(Aug. 15, 2005).
570
Tr. at 1726.
571
ETI Initial Brief at 129.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 167
PUC DOCKET NO. 39896
measures in incentive compensation programs. For example, ETI argues that incentive
compensation that encourages the financial health of a company also benefits customers because:
(1) if a company maintains a financially healthy position, it will tend to have a
lower cost of capital that will in turn benefit customers through lower rates;
(2) a financially healthy company will be more prepared for emergency events
such as storms (which is particularly important in the Gulf Coast areas served
by ETI, which are subject to experiencing hurricanes); and
(3) with financial health, the costs of doing business with suppliers (of both
goods and services, including labor) will remain lower because, for example,
if a company was not in a financially stable condition, suppliers would tend
to demand higher prices or more onerous credit terms, resulting in higher
costs that would lead to higher rates than would otherwise occur.
ETI witness Kevin Gardner, Vice President of Human Resources for ESI, testified that
customers receive benefits from those portions of the incentive compensation plans that are tied to
financial goals and measures. He explained that incentive compensation based on financial metrics
is a reasonable, necessary, and common component of compensation for companies like ETI. He
also opined that such incentives are a market necessity that ETI must include in its compensation
package so that it can hire and retain talented employees. He contended that customers benefit from
the incentives because they attract and keep qualified people. 572 Mr. Gardner further testified that
disallowing financially-based incentives would only encourage utilities to eliminate them, thus
weakening the alignment of employees' financial interests with the interest of the ratepayers in
having an efficiently run and financially healthy utility. He opined that having only operational
incentives could encourage utilities to overspend in some areas resulting in an incomplete,
unbalanced incentive program that would be atypical when compared with American industry in
general. 573
A second ETI witness, Dr. Jay Hartzell, also testified in favor of the concept of allowing ETI
to recover its costs associated with its financially-based incentive compensation. He is a professor of
572
ETI Ex. 36 (Gardner Direct) at 31.
573
Id. at 32.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 168
PUC DOCKET NO. 39896
finance in the business school at the University of Texas at Austin. Dr. Hartzell acknowledged the
historical distinction that has been made by the Commission between compensation tied to financial
measures and compensation tied to operational measures. However, he argues that this distinction is
based upon a "false dichotomy" and that the more appropriate focus should be on whether customers
benefit from the incentive in question, regardless of whether it is a financial or operational
incentive. 574 Dr. Hartzell summarized his key opinion as follows:
In my opm10n, a well-designed compensation plan that includes incentive
compensation tied to cost controls, profitability, and stock prices would tend to
provide greater benefits to customers than an otherwise similar compensation plan
that did not include any such incentive compensation. 575
Dr. Hartzell argues that compensation linked to stock prices (provided it is part of a
reasonable, well-designed compensation plan) has four advantages for customers, :
• helps ensure that managers will consider the financial health of the company when they make
decisions, and it is in customers' interests for the company be financially healthy;
• provides an incentive for managers and employees to ensure that the company operates
efficiently, resulting in lower rates than would otherwise occur;
• provides a monitoring mechanism for managerial decision-making and the overall quality of
management; and
• results in lower customer costs because capital markets will tend to reward efficient long-term
investments or capital expenditures. 576
Dr. Hartzell cited a number of studies which support the theory that the benefits of incentive
compensation linked to stock price and profitability measures extend to customers of the company,
such as by lowering the company's cost of capital, increasing the company's ability to respond to
574
ETI Ex. 15 (Hartzell Direct) at 3-4, 6, and 9-10.
575
Id. at 7.
576
Id. at 13-14.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 169
PUC DOCKET NO. 39896
external shocks, improving customer satisfaction, and increasing oversight on managerial
decisions. 577
Conversely, Dr. Hartzell opined that if the use of incentive compensation linked to
profitability and stock prices is discouraged, via Commission policy disallowing recovery of the
costs of such compensation, then utility customers would be adversely affected. For example, if
employees did not receive any incentive compensation, salaries would have to be higher to attract
and retain the same quality of talent. Dr. Hartzell also testified that a compensation plan solely
consisting of salary and incentives based on operational performance could likely lead to "horizon
problems," meaning that, absent incentives to focus on the long run health of the company, managers
might maximize their immediate compensation at the expense of longer-run benefits that the
customer could have enjoyed.578
All of the other parties oppose ETI' s efforts to recover the costs of its incentive compensation
tied to financial goals. The parties uniformly agree that the Commission has a well-established and
straightforward policy regarding the recoverability of incentive compensation through rates:
incentive compensation that is tied to operational goals is recoverable; incentive compensation tied
to financial goals is not. 579 They contend that ETI's position in this case flies directly in the face of
that policy. TIEC points out that ETI has offered no legal authority, such as a statute or rule, which
would justify its desire to have the Commission reverse its policy and allow the recovery of incentive
compensation tied to financial goals. State Agencies similarly argue that ETI failed to establish a
reason why the Commission should deviate from its long-standing policy. The parties also support
the reasoning behind the Commission's policy: that financially-based incentives are of more
immediate benefit to shareholders, not ratepayers, and therefore are not necessary and reasonable for
the provision of service.
577
ETI Ex. 15 (Hartzell Direct) at 15-21.
578
Id. at 22-25.
579
TIEC Reply Brief at 35; State Agencies Initial Brief at 14; OPC Reply Brief at 12; Staff Initial Brief at 56;
Cities Initial Brief at 67; see also, Application ofAEP Texas Central Company for Authority to Change Rates,
Docket No. 33309, Order on Rehearing at FoF 82 (Mar. 4, 2007);Application ofAEP Texas Central Company
for Authority to Change Rates, Docket No. 28840, Order at FoF 164-170 (Aug. 15, 2005).
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 170
PUC DOCKET NO. 39896
State Agencies point out that, in support of his theory that financially-based incentives
provide benefits to ratepayers, Dr. Hartzell relied upon studies of utilities in competitive markets.
Thus, State Agencies contend, the studies are of little to no benefit in evaluating the effects of
financially-based incentives upon ETI customers because ETI is a monopoly that is not subject to
competitive pressures. Moreover, State Agencies examine at length the underlying studies relied
upon by Dr. Hartzell and assert, essentially, that the studies do not fully support the findings that
Dr. Hartzell ascribes to them.
Staff refutes ETI's contention that the only reason why cost recovery has historically been
denied for financially-based incentive compensation is that there has been a lack of evidence
showing customer benefits. For example, Staff points out that, in one of the prior dockets cited by
ETI, the Commission disallowed recovery for financially-based incentive costs after stating,
"Incentive compensation based on financial measures or goals is of more immediate benefit to
shareholders." 580 This suggests that the question is not, as ETI contends, whether the incentives
provide any benefit to ratepayers. Rather, the question is whether the incentives are primarily
intended to provide benefits to shareholders.
Mark Garrett, an attorney and certified public accountant who works as a consultant in the
area of public utility regulation, testified on behalf of the Cities in opposition to cost recovery for
financially-based incentive compensation. He stated there are a number of reasons why it makes
sense to exclude financially based incentive costs from rates: (1) there is no certainty from year to
year what the level of incentive payments will be (because incentive payments are conditioned upon
future events and triggers that might not occur), thereby making it difficult to set rates and recover a
level of expense; (2) many of the types of factors that increase earnings per share-such as an
unusually hot summer or customer growth-are outside the control of employees and have no value
to customers; and (3) earnings-based incentives can discourage energy conservation. 581 Mr. Garrett
580
Staff Reply Brief at 44, quoting Application of Oncor Electric Delivery Company for Authority to Change
Rates, Docket No. 35717, Order on Rehearing at FoF 92 (Nov. 30, 2009).
581
Cities Ex. 2 (Garrett Direct) at 29-30
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 171
PUC DOCKET NO. 39896
also discussed the results of a survey of 24 other states, which revealed that 17 states closely follow
Texas' approach, and none allow full recovery of incentive compensation.582
Mr. Garrett testified that ETI will not be placed at a competitive disadvantage in its ability to
obtain and retain qualified employees if its financially-based incentives are disallowed. He stated
that the Company's total payroll costs for 2011 were 10 percent above the market price, and that
most of the above-market payroll costs derived from the incentive program. 583
The ALls conclude that ETI should not be entitled to recover its financially based incentive
compensation costs. Based upon prior Commission precedents, the AU s conclude that the issue is
not, as ETI contends, whether such incentives might provide any benefits to customers. The proper
question to be asked is whether they provide benefits most immediately or predominantly to
shareholders. Without a doubt, the primary purpose of financially based incentives, such as
incentives tied to earnings per share or stock price, is to benefit shareholders, not ratepayers. Even
construing Dr. Harzell' s testimony in the most generous light, any benefits that might accrue to
ratepayers would be merely tangential to that primary purpose.
Moreover, even if the ALls were to completely accept as true the opinions offered by
Dr. Hartzell, it would be of limited benefit to ETI because his opinions were almost completely
theoretical. The premise of his testimony was that "a well-designed compensation plan" that
includes incentive compensation tied to financial goals would "tend to provide greater benefits to
customers" than a plan that did not include such compensation. 584 He stressed that the customer
benefits of incentive compensation tied to financial goals can only exist if such compensation is part
of a larger, reasonable, and well-designed overall compensation plan. 585 However, he did not
meaningfully apply this abstract theory to ETI's compensation plan. For example, Dr. Harzell did
not offer an evaluation of ETI' s compensation plan and conclude that it is "well designed," nor did
582
Id. at 32-38.
583
Id. at 45-46.
584
ETI Ex. 15 (Hartzell Direct) at 7 (emphasis added).
585
See, e.g., ETI Ex. 15 (Hartzell Direct) at 13.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 172
PUC DOCKET NO. 39896
he testify that ETI' s incentives tied to financial goals actually provide benefits to its customers. He
admitted that he did not study the details ofETI's incentive plans, nor did he do any type of analysis
to see if the costs of ETI's incentive programs outweighed their benefits. 586 He did not know the
amounts of incentive compensation that was paid by ETI. 587 One of his major premises was that
financially-based incentives can benefit customers by lowering their costs, but he did not know how
ETI customer's costs compared with customer costs in the other Entergy operating companies. 588
Another of his major premises was that financially-based incentives can benefit customers by
ensuring the financial health of the Company, but he made no attempt to determine whether ETI was,
in fact, a financially healthy company. 589 By confining his testimony to the abstract, it is impossible
to know whether Dr. Hartzell believes that ETI' s incentive compensation tied to financial goals
achieves the customer benefits that he believes such compensation can theoretically achieve. It is
true that Mr. Gardner described some of the specifics of ETI' s incentive plans. However, because
Dr. Hartzell did not explain the metrics of what he would consider "a well-designed compensation
plan," it is impossible to know if ETI' s plan meets those metrics.
Simply put, the AU s conclude that ETI has failed to establish a sufficient justification for
overturning the well-established Commission policy that financially based incentive compensation is
not recoverable.
(b) The Adjustment for Financially-Based Incentive Compensation Costs
Having concluded that ETI is not entitled to recover the costs of its financially based
incentive programs, it is necessary to determine the amount of those costs so that they may be
removed from consideration in this rate case. The parties disagree on the correct amount. Staff
586
Tr. at 484.
587
Tr. at 478.
588
Tr. at 480.
589
Tr. at 481-82.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 173
PUC DOCKET NO. 39896
590
argues that $5.3 million ofETI's incentive compensation is financiallybased. TIEC contends the
592
correct number is $6.2 million. 591 Cities contend it is $8.4 million.
Broadly speaking, ETI has two categories of incentive compensation programs - annual
programs and long-term programs. ETI witness Gardner testified that 100 percent of ETI' s
long-term programs are financially based, whereas an average, representing a far lower percentage,
of the Company's annual programs are financially based. 593 Staff witness Givens applied those
percentages to determine her estimate of the amount spent by ETI in the Test Year on financially
based incentives. As to the Company's long-term programs, she recommended removing the entire
costs of those programs (i.e. 100 percent) from the cost of service. As to the Company's annual
programs, she recommended removing average percentage of the costs of those programs.
Ms. Givens then applied the FICA tax rate to the total amount she identified as financially based
costs to account for direct taxes that ETI would have paid as a result of those costs. By her estimate,
the FICA taxes associated with ETI's financially based incentives paid in the Test Year totaled
$429,096. In total, Ms. Givens recommended removing $5,609,093 (representing ETI's financially
based incen,tives paid in the Test Year, plus FICA taxes associated with those payments) fromETI's
requested O&M expenses. However, based upon subsequent additional information supplied by
ETI594 relative to the actual payroll taxes paid by the Company for its financially based incentive
compensation, Staff has agreed to lower its estimate of FICA taxes from $429,096 to $143,801.
Thus, Staff now recommends removing $5 ,3 23, 798 (representing ETI' s financially based incentives
paid in the Test Year, plus FICA taxes associated with those payments) fromETI's requested O&M
expenses. 595
590
Staff Initial Brief at 56. (As discussed more below, Staffs original estimate was roughly $5.6 million. The
estimate was reduced, however, in response to supplemental payroll tax information supplied to Staff by ETI.)
591
TIEC Initial Brief at 53-54.
592
Cities Initial Brief at 70.
593
ETI Ex. 36 (Gardner Direct) at 30.
594
ETI Ex. 46 (Considine Rebuttal).
595
Staff Ex. 1 (Givens Direct) at 15-22; Staff Initial Brief at 56-63.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 174
PUC DOCKET NO. 39896
Like Ms. Givens for Staff, TIEC witness Pollock relied on the numbers and percentages
concerning ETI's incentive programs that were provided by Mr. Gardner. However, Mr. Pollock
calculated those numbers and percentages in a slightly different manner, leading to a different
recommended reduction amount. Just as Ms. Givens did, as to the Company's long-term programs,
he recommended removing the entire costs of those programs from the cost of service. ETI witness
Gardner testified that actual percentages of each annual program were quite different than the
average percentages for all programs used by Ms. Givens. 596 Thus, as to the Company's annual
programs, while Ms. Givens applied the average percentage reduction to all of the annual programs,
Mr. Pollock applied the actual percentage reductions applicable to each of the annual programs.
Based on Mr. Pollock's calculations, TIEC recommends removing $6,196,037 (representing ETI's
financially based incentives paid in the Test Year) from ETI's requested O&M expenses. 597 TIEC
appears not to have taken into account any payroll taxes associated with ETI's financially based
incentives.
Cities witness Garrett took a substantially different approach when he calculated his estimate
of ETI's financially based incentive costs. He agreed with Ms. Givens and Mr. Pollock that
100 percent of the Company's long-term program costs should be removed from the cost of service.
As to the annual programs, however, Mr. Garrett defined what qualifies as "financially based" much
more broadly than ETI, Staff, and TIEC. ETI witness Gardner testified that, when the Company's
five annual programs were averaged together, specific percentages of those programs were
financially based, aimed at "cost control," and aimed at "cost control, operational, safety."598
Mr. Garrett added together the percentages representing the financially-based costs, the cost-control
costs, and roughly one-third of the cost-control, operational safety costs to arrive at the figure he
identified as the amount of ETI' s costs for its annual programs that is "related to financial
performance measures."599 Cities contend this approach is supported by the decision in a prior
596
ETI Ex. 36 (Gardner Direct) at 30 and KGG-4.
597
TIEC Ex. 1 (Pollock Direct) at 41-45 and JP-7; TIEC Initial Brief at 51-54.
598
ETI Ex. 36 (Gardner Direct) at 30 and KGG-4.
599
Cities Ex. 2 (Garrett Direct) at 39-40, 46-50, MG2.10.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE175
PUC DOCKET NO. 39896
docket. 600 Based on Mr. Garrett's calculations, Cities recommend removing $8,397,232
(representing ETI' s incentives "related to financial performance measures" paid in the Test Year)
from ETI' s requested O&M expenses. 601 Mr. Garrett also agreed with Ms. Givens that an additional
reduction should be made to account for the FICA taxes that ETI would have paid as a result of those
costs. 602
The AUs reject Cities' attempt to broadly expand the definition of what qualifies as a
financially based incentive to include items such as cost control measures. Cities' primary
justification for doing so is that the Commission has done so previously in the AEP Texas case. As
pointed out by ETI, however, the Commission did so in that case merely because AEP Texas lumped
its cost control measures in with its financially based incentive costs. The evidence in this case
demonstrates that ratepayers benefit when a utility incentivizes its employee to control costs. Even
TIEC witness Pollock testified that "incentives that encourage employees to minimize costs are
probably more or less in the best interest of ratepayers." 603 ETI further provided evidence
establishing that cost control incentives that result in lower costs for the Company likewise result in
lower rates for customers. 604
As to the approaches advocated by TIEC and Staff, the AU s conclude that TIEC' s approach
more accurately captures the true cost of ETI' s financially based incentive programs. Rather than
averaging across all of ETI's annual programs (as was done by Staff), TIEC used the percentage
applicable to the single annual program that included a component of financially based costs. Thus,
the AU s recommend removing $6, 196,03 7 (representing ETI' s financially based incentives paid in
the Test Year) from ETI's requested O&M expenses. Additionally, the AlJs agree with Staff and
60
° Cities Initial Brief at 68, Application of AEP Texas Central Company for Authority to Change Rages,
Docket No. 28840, Final Order (August 15, 2005).
601
Cities Ex. 1 (Garrett Direct) at 51-52 and MG2. l O; Cities Initial Brief at 70.
602
Cities Ex. 1 (Garrett Direct) at 53.
603
Tr. at 1528.
604
ETI Ex. 50 (Gardner Rebuttal) at 6-7, ETI Initial Brief at 137-38.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 176
PUC DOCKET NO. 39896
Cities that an additional reduction should be made to account for the FICA taxes that ETI would
have paid as a result of those costs. That amount is not specifically known at this time.
3. Compensation and Benefits Levels
In the application, ETI included, as part of its labor costs, $54,965,005 in base payroll paid by
ETI and ESI in the Test Year. It also included $20,428,817 in costs associated with various benefits
(such as medical/dental, and life insurance) that ETI and ESI provided to their employees. 605 Cities
contend that the amounts for base pay and the benefits package should be reduced by $989,370 and
$2,860,034, respectively, because the amounts paid were above the market price. 606 No other party
challenges the reasonableness of the base payroll and benefits package.
As to base payroll, Cities contends that the amount paid by ETI and ESI was 1.8 percent
above the prevailing market price (above market). 607 Cities witness Garrett acknowledges that ETI
and ESI are free to pay their employees at above market wages, but he contends that ratepayers
should only be asked to pay the market rate for wages, which he contends constitute the only
"necessary" costs of providing utility service. Thus, Mr. Garrett and Cities recommend a 1.8 percent
downward adjustment to base payroll expense (or $989,370) "to bring the company's base payroll
down to a market-based level."608
As to the Company's benefits package, Cities points out that the amount paid by ETI and ESI
was 14 percent above market when compared to a peer group of Fortune 500 companies. 609 Cities
witness Garrett again contends that ratepayers should only be asked to pay the market rate for
benefits, which he contends constitute the only "necessary" costs of providing utility service. Thus,
605
Cities Ex. 2 (Garrett Direct) at 25, MG2.8, and MG2.9.
606 Id.
607
Id. at 25 and MG2.8.
608
Id. at 26-27 and MG2.8.
609
Id. at 58 and MG2.9; ETI Ex. 36 (Gardner Direct) at 41-42.
PUC DOCKET NO. 39896
SOAH DOCKET NO. XXX-XX-XXXX
APPLICATION OF ENTERGY TEXAS, §
INC. FOR AUTHORITY TO CHANGE §
RATES, RECONCILE FUEL COSTS, §
AND OBTAIN DEFERRED §
ACCOUNTING TREATMENT §
ORDER
This Order addresses the application of Entergy Texas, Inc. for authority to change rates,
reconcile fuel costs,, and defer costs for the transition to the Midwest Independent System
Operator (MISO). In its application, Entergy requested approval of an increase in annual base-
rate revenues of approximately $111.8 million (later lowered to $104.8 million), proposed tariff
schedules, including new riders to recover costs related to purchased-power capacity and
renewable-energy credit requirements, requested final reconciliation of its fuel costs, and
requested waivers to the rate-filing package requirements.
On July 6, 2012, the State Office of Administrative Hearings (SOAH) administrative law
judges (AUs) issued a proposal for decision in which they recommended an overall rate increase
for Entergy of $28.3 million resulting in a total revenue requirement of approximately $781
million. The AUs also recommended approving total fuel costs of approximately $1.3 billion.
The AUs did not recommend approving the renewable-energy credit rider and the Commission
earlier removed the purchased-power capacity rider as an issue to be addressed in this docket. 1
On August 8, 2012, the AUs filed corrections to the proposal for decision based on the
exceptions and replies of the parties. 2 Except as discussed in this Order, the Commission adopts
the proposal for decision, as corrected, including findings of fact and conclusions of law.
1
Supplemental Preliminary Order at 2, 3 (Jan. 19, 2012).
2
Letter from SOAHjudges to PUC (Aug. 8, 2012).
000000001
PUC Docket No. 39896 Order Page 2 of 43
SOAH Docket No. XXX-XX-XXXX
I. Discussion
A. Prepaid Pension Asset Balance
Entergy included in rate base an approximately $56 million item named Unfunded
Pension. 3 This amount represents the accumulated difference between the annual pension costs
calculated in accordance with the Statement of Financial Accounting Standards (SPAS) No. 87
and the actual contributions made by Entergy to the pension fund-Entergy contributed nearly
$56 million more to its pension fund than the minimum required by SPAS No. 87. 4
In Docket No. 33309, the Commission allowed a pension prepayment asset, excluding
the portion of the asset that is capitalized to construction work in progress (CWIP), less accrued
deferred federal income taxes (ADFIT) to be included in rate base. 5 For the excluded portion,
the Commission allowed the accrual of an allowance for funds used during construction
(AFUDC). 6 The ALls concluded that this approach was sound and should be followed in this
case. 7 Thus, the AU s recommended that the CWIP-related portion of Entergy' s prepaid pension
asset ($25,311,236) should be excluded from the asset and should accrue AFUDC. 8 However,
the ALls did not address ADFIT.
The Commission agrees that the CWIP-related portion of Entergy' s pension asset should
be excluded from the asset and that this excluded portion should accrue AFUDC. However, the
Commission also finds that the impact of this exclusion on Entergy's ADFIT should be reflected.
When items are excluded from rate base, the related ADFIT should also be excluded. The
adjusted ADFIT for the prepaid pension asset remaining in Entergy's rate base should be reduced
by $8,858,933, the deferred taxes related to the excluded $25 million. The Commission adds
new finding of fact 28A to reflect this modification to Entergy's ADFIT.
3
Proposal for Decision at 23 (July 6, 2012) (PFD).
4
PFD at 23-24.
5
Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 33309, Order on
Rehearing (March 4, 2008).
6
Remand of Docket No. 33309 (Application of AEP Texas Central Company for Authority to Change
Rates), Docket No. 38772, Order on Remand (Jan. 20, 2011).
7
PFDat 26.
8
Id. at 24-26.
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8. FIN 48
The Financial Accounting Standards Board's Interpretation No. 48 (FIN 48) prescribes
the way in which a company must analyze, quantify, and disclose the potential consequences of
tax positions that the company has taken that are legally uncertain. Entergy reported that its
uncertain tax positions totaled $5,916,461. FIN 48 requires that this amount be recorded on
Entergy's balance sheet as a tax liability. Entergy also reported that it made a cash deposit with
the IRS in the amount of $1,294,683 associated with its FIN 48 liability. 9
The AUs concluded that Entergy's FIN 48 liability should be included in its ADFIT
balance, but the amount of the cash deposit made by Entergy to the IRS attributable to Entergy's
FIN 48 liability should not be included in Entergy's ADFIT balance. Accordingly, the AUs
recommended that $4,621,778 (Entergy's FIN 48 liability of $5,916,461 less the $1,294,683 cash
deposit Entergy has already made with the IRS) be added to Entergy's ADFIT balance and thus
be used to offset Entergy's rate base. 10 The AUs did not recommend the addition of a deferred-
tax-account rider because no party expressly advocated the addition of such a rider. 11
The Commission adopts the proposal for decision regarding the adjustment to Entergy's
ADFIT for the amount attributable to Entergy's FIN 48 liability. However, the Commission also
follows its precedent regarding the creation of a deferred-tax-account tracker and modifies the
proposal for decision on this point. In CenterPoint's Electric Delivery Company's last rate case,
Docket No. 38339, 12 the Commission found that tax schedule UTP-on which companies must
describe, list, and rank each uncertain tax position-would provide the IRS auditors sufficient
information to quickly determine which uncertain tax positions are of a magnitude worth
investigating and that an IRS audit would be more likely to occur on some uncertain tax
positions. If an IRS audit of a FIN 48 uncertain tax position results in an unfavorable outcome,
the utility would not be able to earn a return on the amount paid to the IRS until the next rate
case.
9
PFD at 26-27 (citing Rebuttal Testimony of Roberts, Entergy Ex. 64 at 6), 29 (citing Rebuttal Testimony
of Roberts, Entergy Ex. 64 at 8).
10
PFD at 29.
11
Id. at 29.
12
Application of CenterPoint Electric Delivery Company, LLC for Authority to Change Rates, Docket
No. 38339, Order on Rehearing at 3-4 (June 23, 2011 ).
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Accordingly, the Commission authorizes Entergy to establish a rider to track unfavorable
FIN-48 rulings by the IRS. The rider will also allow Entergy to recover on a prospective basis
an after-tax return of 8.27% on the amounts paid to the IRS that result from an unfavorable FIN-
48 unfavorable-tax-position audit. The return will be applied prospectively to FIN-48 amounts
disallowed by an IRS audit after such amounts are actually paid to the federal government. If
Entergy subsequently prevails in an appeal of an unfavorable FIN-48 unfavorable-tax-position
decision by the IRS, then any amounts collected under rider related to that overturned decision
shall be credited back to ratepayers.
The Commission adds new finding of fact 40A and deletes finding of fact 41 consistent
with its decision to authorize the deferred-tax-account tracker.
C. Capitalized Incentive Compensation
Entergy capitalized into plant-in-service accounts some of the incentive payments made
to employees and sought to include those amounts in rate base. The Al.Js determined that
Entergy should not be able to recover its financially based incentive-compensation costs. 13
Therefore, the portion of Entergy's incentive-compensation costs capitalized during the period
July l, 2009 through June 30, 2010 that were financially based was excluded from Entergy's rate
base. The AU s also determined that the actual percentages should be used to determine the
amount that is financially based. 14
In discussing Entergy's incentive compensation as a component of operating expenses,
the Al.Js adopted the method advocated by Texas Industrial Energy Consumers (TIEC) for
calculating the amount of the financially based incentive costs. This method uses the actual
percentage reductions applicable to each of the annual incentive programs that included a
component of financially-based costs. 15
In its exceptions regarding capitalized incentive compensation, Entergy advocated for the
use of TIEC' s methodology to also calculate the amount of capitalized incentive compensation
that is financially based. Entergy also noted that the amount of the disallowance reflected in the
13
PFD at 171.
14
Id. at 72.
15
Id. at 174; see also Entergy's Exceptions to the Proposal for Decision at 25-26 (July 23, 2012).
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schedules, $1,333,352, was calculated using a disallowance factor that included incentive
compensation tied to cost-control measures, which the AUs found to be recoverable in the
operating-cost incentive-compensation calculation. 16 When the TIEC methodology is applied to
the capitalized incentive-compensation costs in rate base, the net result under TIEC's
methodology is that only $335,752.96 should be disallowed from capital costs. 17
The Commission agrees that capitalized incentive compensation that is financially based
should be excluded from rate base and that the exclusion only applies to incentive costs that
Entergy capitalized during the period from July 1, 2009 through June 30, 2010. However, the
Commission finds that a consistent methodology should be used to calculate the amount to be
excluded and therefore that TIEC's methodology should also be used for calculating the amount
of capitalized financially based incentive-compensation costs that should be excluded from rate
base. Accordingly, the total amount of capitalized incentive-compensation costs that should be
disallowed from rate base is $335,752.96. Finding of fact 61 is modified to reflect this
determination.
As noted by Commission Staff, this disallowance to plant-in-service alters the expense
for ad valorem taxes. Accounting for this disallowance, the appropriate expense amount for ad
valorem taxes is $24,921,022, 18 an adjustment of $1,222,106 to Entergy's test year amount.
Finding of fact 151 is modified to reflect this adjustment to property taxes.
D. Rate of Return and Cost of Capital
The AUs found the proper range of an acceptable return on equity for Entergy would be
from 9.3 percent to 10.0 percent. 19 The mid-point of the range is 9.65 percent. The AUs found
that the effect of unsettled economic conditions facing utilities on the appropriate return on
equity should be taken into account and that the effect would be to move the ultimate return on
equity towards the upper limits of the range that was determined to be reasonable. 20 The AU s
16
Entergy's Exceptions to the Proposal for Decision at 25-26.
17
Id. at 25-26.
18
Commission Number-Run Memorandum at 2 (Aug. 28, 2012).
19
PFD at 94.
20
Id.
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found that the reasonable adjustment would be 15 basis points, moving the reasonable return on
equity to 9.80 percent. 21
The Commission must establish a reasonable return for a utility and must consider
applicable factors. 22 The Commission disagrees with the AU s that a utility's return on equity
should be determined using an adder to reflect unsettled economic conditions facing utilities.
The Commission agrees with the AUs, however, that a return on equity of 9.80 percent will
allow Entergy a reasonable opportunity to earn a reasonable return on its invested capital, but
finds this rate appropriate independent of the 15-point adder recommended by the AUs. A
return on equity of 9.80 percent is within the range of an acceptable return on equity found by
the AUs. Accordingly, the Commission adds new finding of fact 65A to reflect the
Commission's decision on this point.
E. Purchased-Power Capacity Expense
The AU s rejected Entergy' s request to recover $31 million more in purchased-power
capacity costs than its actual test-year expenses because Entergy had failed to prove that the
adjustment was known and measurable, 23 and because the request violated the matching
principle. 24 Consequently, the AUs recommended that Entergy's test-year expenses of
$245,432,884 be used to set rates in this docket. 25
Entergy pointed to an additional $533,002 of purchased-power capacity expenses that
were properly included in Entergy's rate-filing package, but not provided for in the proposal for
decision. 26 The Commission finds that an additional $533,002 ($6,132 for test-year expenses for
Southwest Power Pool fees, $654,082 for Toledo Bend hydro fixed-charges, and -$127,212 for
an Entergy intra-system billing adjustment that were all recorded in FERC account 555) of
purchased-power capacity costs were incurred during the test-year and should be added to the
purchased-power capacity costs in Entergy's revenue requirement. The Commission modifies
21
Id. at 94.
22
PURA§§ 36.051, .052.
23
PFD at 108-09.
24
Id. at 109.
is Id.
26
Entergy' s Exceptions to the Proposal for Decision at 51.
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findings of fact 72 and 86 to reflect the inclusion of the additional $533,002 of test-year
purchased-power capacity costs, increasing the total amount to $245,965,886.
F. Labor Costs - Incentive Compensation
The Al.Js found that $6,196,037, representing Entergy's financially-based incentives paid
in the test-year, should be removed from Entergy's O&M expenses. 27 The Al.Js agreed with
Commission Staff and Cities that an additional reduction should be made to account for the
FICA taxes that Entergy would have paid for those costs, 28 but did not include this reduction in a
finding of fact.
The Commission agrees with the Al.Js, but modifies finding of fact 133 to specifically
include the decision that an additional reduction should be made to account for the FICA taxes
Entergy would have paid on the disallowed financially-based incentive compensation. The
Commission notes that this reduction for FICA taxes is reflected in the schedules attached to this
Order. 29
G. Affiliate Transactions
OPUC argued that Entergy's sales and marketing expenses exclusively benefit the larger
commercial and industrial customers, but the majority of the sales, marketing, and customer
service expenses are allocated to the operating companies based on customer counts. Therefore,
the majority of these expenses are allocated to residential and small business customers. OPUC
argued that it is inappropriate for residential and small business customers to pay for these
expenses. 30 The Al.Js did not adopt OPUC's position on this issue.
The Commission agrees with OPUC and reverses the proposal for decision regarding
allocation of Entergy' s sales and marketing expense and finds that $2.086 million of sales and
marketing expense should be reallocated using direct assignment. The Commission has
27
PFD at l 75.
28
Id. at l 75-76.
29
See Commission Number Run-Memorandum at 3 (Aug. 28, 2012).
30
Direct Testimony of Carol Szerszen, OPUC Ex. I at 44-45.
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previously expressed its preference for direct assignment of affiliate expenses. 31 The
Commission finds that the following amounts should be allocated based on a total-number-of-
customers basis: (l) $46,490 for Project E10PCR56224 - Sales and Marketing - EGSI Texas;
(2) $17,013 for Project F3PCD10049 - Regulated Retail Systems O&M; and (3) $30,167 for
Project F3PPMMALI2 - Middle Market Mkt. Development. The remainder, $1,992,475, should
be assigned to (l) General Service, (2) Large General Service and (3) Large Industrial Power
Service. 32 The reallocation has the effect of increasing the revenue requirement allocated to the
large business class customers and reduces the revenue requirement for small business and
residential customers. New finding of fact 164A is added to reflect the proper allocation of these
affiliate transactions.
H. Fuel Reconciliation
Entergy proposed to allocate costs for the fuel reconciliation to customers using a line-
loss study performed in 1997. Entergy conducted a line-loss study for the year ending December
31, 2010, which falls in the middle of the two year fuel reconciliation period-July 2009 through
June 2011-and therefore reflects the actual line losses experienced by the customer classes
during the reconciliation period. Cities argued that the allocation of fuel costs incurred over the
reconciliation period should reflect the current line-loss study performed by Entergy for this case
and recommended approval on a going-forward basis. Fuel factors under P.U.C. SUBST.
R. 25.237(a)(3) are temporary rates subject to revision in a reconciliation proceeding described
in P.U.C. SUBST. R. 25.236. P.U.C. SUBST. R. 25.236(d)(2) defines the scope of a fuel
reconciliation proceeding to include any issue related to the reasonableness of a utility's fuel
expenses and whether the utility has over- or under-recovered its reasonable fuel expenses. 33
Cities calculated a $3,981,271 reduction to the Texas retail fuel expenses incurred over the
reconciliation period using the current line-losses. The AUs rejected Cities' proposed
adjustment finding that the P.U.C. SUBST. R. 25.237(c)(2)(B) requires the use of Commission-
31
Application of Central Power and Light Company for Authority to Change Rates, Docket No. 14965,
Second Order on Rehearing at 87, COL 29 (Oct. 16, 1997).
32
Direct Testimony of Carol Szerszen, OPUC Ex. l at Schedule CAS-7.
33
Cities' Exceptions to the Proposal for Decision at 20-21 (July 23, 2012).
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approved line losses that were in effect at the time fuel costs were billed to customers in a fuel
reconciliation. 34
The Commission agrees with Cities and reverses the proposal for decision regarding
which line-loss factors should be used in Entergy's fuel reconciliation. Entergy used the 2010
study line-loss calculations to calculate the demand- and energy-related allocations in its cost of
service analysis supporting its requested base rates. These same currently available line-loss
factors should have been utilized in Entergy's fuel reconciliation. The Commission finds that
Entergy's 2010 line-loss factors should be used to calculate Entergy's fuel reconciliation
over-recovery. As a result, Entergy's fuel reconciliation over-recovery should be reduced by
$3,981,271. Finding of fact 246A and conclusions of law 19A and 19B are added to reflect the
Commission's finding that the 2010 line-loss factors be used to reconcile Entergy's fuel costs.
I. MISO Transition Expenses
During the Commission's consideration of the proposal for decision, the parties that
contested the amount of Entergy's MISO transition expenses and how the transition expenses
should be accounted for reached announced on the record that they had reached an agreement on
these issues. 35 Those parties agreed that the MISO transition expenses would not be deferred and
that Entergy's base rates should include $1.6 million for MISO transition expense. 36 The
Commission adopts the agreement of the parties and accordingly modifies finding of fact 251
and deletes finding of fact 252.
J. Purchased-Power Capacity Cost Baseline
The Commission modified the amount of purchased-power capacity expense in the
test-year to be $245,965,886 (see section E above). Finding of fact 255 is modified to reflect the
change to the proper test-year purchased-power capacity expense.
34
PFD at 327-328.
35
Open Meeting Tr. at 138 (Aug. 17, 2012).
36 Id.
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K. Other Issues
New findings of fact 17 A, 17B, 17C, 17D, and 17 E are added to reflect procedural
aspects of the case after issuance of the proposal for decision.
In addition, to reflect corrections recommended by the AUs, findings of fact 116, 123,
192, 194, and 202 are modified; and new finding of fact 182A is added.
The Commission adopts the following findings of fact and conclusions of law:
II. Findings of Fact
Procedural History
1. Entergy Texas, Inc. (ETI or the company) is an investor-owned electric utility with a
retail service area located in southeastern Texas.
2. ETI serves retail and wholesale electric customers in Texas. As of June 30, 2011, ETI
served approximately 412,000 Texas retail customers. The Federal Energy Regulatory
Commission (FERC) regulates ETI's wholesale electric operations.
3. On November 28, 2011, ETI filed an application requesting approval of: (1) a proposed
increase in annual base rate revenues of approximately $111.8 million over adjusted test-
year revenues; (2) a set of proposed tariff schedules presented in the Electric Utility Rate
Filing Package for Generating Utilities (RFP) accompanying ETI's application and
including new riders for recovery of costs related to purchased-power capacity and
renewable energy credit requirements; (3) a request for final reconciliation of ETI's fuel
and purchased-power costs for the reconciliation period from July 1, 2009 to
June 30, 2011; and (4) certain waivers to the instructions in RFP Schedule V
accompanying ETI' s application.
4. The 12-month test-year employed in ETI's filing ended on June 30, 2011 (test-year).
5. ETI provided notice by publication for four consecutive weeks before the effective date
of the proposed rate change in newspapers having general circulation in each county of
ETI's Texas service territory. ETI also mailed notice of its proposed rate change to all of
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SOAH Docket No. XXX-XX-XXXX
its customers. Additionally, ETI timely served notice of its statement of intent to change
rates on all municipalities retaining original jurisdiction over its rates and services.
6. The following parties were granted intervenor status in this docket: Office of Public
Utility Counsel; the cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe,
Dayton, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge
North, Orange, Pine Forest, Rose City, Pinehurst, Port Arthur, Port Neches, Shenandoah,
Silsbee, Sour Lake, Splendora, Vidor, and West Orange (Cities), the Kroger Co.
(Kroger); State Agencies; Texas Industrial Energy Consumers; East Texas Electric
Cooperative, Inc.; the United States Department of Energy (DOE); and Wal-Mart Stores
Texas, LLC, and Sam's East, Inc. (Wal-Mart). The Staff (Staff) of the Public Utility
Commission of Texas (Commission or PUC) was also a participant in this docket.
7. On November 29, 2011, the Commission referred this case to the State Office of
Administrative Hearings (SOAH).
8. On December 7, 2011, the Commission issued its order requesting briefing on threshold
legal/policy issues.
9. On December 19, 2011, the Commission issued its Preliminary Order, identifying 31
issues to be addressed in this proceeding.
10. On December 20, 2011, the Administrative Law Judges (ALls) issued SOAH Order
No. 2, which approved an agreement among the parties to establish a June 30, 2012
effective date for the company's new rates resulting from this case pursuant to certain
agreed language and consolidate Application of Entergy Texas, Inc. for Authority to Defer
Expenses Related to its Proposed Transition to Membership in the Midwest Independent
System Operator, Docket No. 39741 (pending) into this proceeding. Although it did not
agree, Staff did not oppose the consolidation.
11. On January 13, 2012, the AUs issued SOAH Order No. 4 granting the motions for
admission pro hac vice filed by Kurt J. Boehm and Jody M. Kyler to appear and
participate as counsel for Kroger and the motion for admission pro hac vice filed by Rick
D. Chamberlain to appear and participate as counsel for Wal-Mart.
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PUC Docket No. 39896 Order Page 12 of43
SOAH Docket No. XXX-XX-XXXX
12. On January 19, 2012, the Commission issued a supplemental preliminary order
identifying two additional issues to be addressed in this case and concluding that the
company's proposed purchased-power capacity rider should not be addressed in this case
and that such costs should be recovered through base rates.
13. ETI timely filed with the Commission petitions for review of the rate ordinances of the
municipalities exercising original jurisdiction within its service territory. All such
appeals were consolidated for determination in this proceeding.
14. On April 4, 2012, the ALls issued SOAH Order No. 13 severing rate case expense issues
into Application of Entergy Texas, Inc. for Rate Case Expenses Severed from PUC
Docket No. 39896, Docket No. 40295 (pending).
15. On April 13, 2012, ETI adjusted its request for a proposed increase in annual base rate
revenues to approximately $104.8 million over adjusted test-year revenues.
16. The hearing on the merits commenced on April 24 and concluded on May 4, 2012.
17. Initial post-hearing briefs were filed on May 18 and reply briefs were filed on May 30,
2012.
17A. On August 7, 2012, the SOAH ALls filed a letter with the Commission recommending
changes to the PFD.
17B At the July 27, 2012 open meeting, ETI agreed to extend the effective date of rates to
August 31, 2012 to provide the Commission sufficient time to consider the issues in this
proceeding.
l 7C. The Commission considered the proposal for decision at the August 17, 2012 and August
30, 2012 open meetings.
170. At the August 30, 2012 open meeting, ETI agreed to extend the effective date of rates to
September 14, 2012.
17E. At the August 17, 2012 open meeting, parties announced on the record a settlement of the
amount of costs for the transition to MISO.
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Rate Base
18. Capital additions that were closed to ETI's plant-in-service between July 1, 2009 and
June 30, 2011, are used and useful in providing service to the public and were prudently
incurred.
19. ETI's proposed Hurricane Rita regulatory asset was an issue resolved by the black-box
settlement in Application of Entergy Texas, Inc. for Authority to Change Rates and
Reconcile Fuel Costs, Docket No. 37744 (Dec. 13, 2010).
20. Accrual of carrying charges on the Hurricane Rita regulatory asset should have ceased
when Docket No. 37744 concluded because the asset would have then begun earning a
rate of return as part of rate base.
21. The appropriate calculation of the Hurricane Rita regulatory asset should begin with the
amount claimed by ETI in Docket No. 37744, less amortization accruals to the end of the
test-year in the present case, and less the amount of additional insurance proceeds
received by ETI after the conclusion of Docket No. 37744.
22. A Test-Year-end balance of $15,175,563 for the Hurricane Rita regulatory asset should
remain in rate base, applying a five-year amortization rate beginning August 15, 2010.
23. The Hurricane Rita regulatory asset should not be moved to the storm damage insurance
reserve.
24. The company requested in rate base its prepaid pension assets balance of $55,973,545,
which represents the accumulated difference between the Statement of Financial
Accounting Standards (SFAS) No. 87 calculated pension costs each year and the actual
contributions made by the company to the pension fund.
25. The prepaid pension assets balance includes $25,311,236 capitalized to construction work
in progress (CWIP).
26. It is not necessary to the financial integrity of ETI to include CWIP in rate base, and there
was insufficient evidence showing that major projects under construction were efficiently
and prudently managed.
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27. The portion of the prepaid pension assets balance that is capitalized to CWIP should not
be included in ETI' s rate base.
28. The remainder of the prepaid pension assets balance should be included in ETI' s rate
base.
28A. When items are excluded from rate base, the related ADFIT should also be excluded.
The amount of ADFIT associated with the $25 million capitalized to CWIP and excluded
from rate base is $8,858,933. The adjusted ADFIT for the prepaid pension asset
remaining in Entergy's rate base should be reduced by $8,858,933.
29. ETI should be permitted to accrue an allowance for funds used during construction on the
portion of ETI's Prepaid Pension Assets Balance capitalized to CWIP.
30. The Financial Accounting Standard Board (FASB) Financial Interpretation No. 48
(FIN 48), "Accounting for Uncertainty in Income Taxes," requires ETI to identify each of
its uncertain tax positions by evaluating the tax position on its technical merits to
determine whether the position, and the corresponding deduction, is more-likely-than-not
to be sustained by the Internal Revenue Service (IRS) if audited.
31. FIN 48 requires ETI to remove the amount of its uncertain tax positions from its
Accumulated Deferred Federal Income Tax (ADFIT) balance for financial reporting
purposes and record it as a potential liability with interest to better reflect the company's
financial condition.
32. At test-year-end, ETI had $5,916,461 in FIN 48 liabilities, meaning ETI has, thus far,
avoided paying to the IRS $5,916,461 in tax dollars (the FIN 48 liability) in reliance upon
tax positions that the company believes will not prevail in the event the positions are
challenged, via an audit, by the IRS.
33. ETI has deposited $1,294,683 with the IRS in connection with the FIN 48 liability.
34. The IRS may never audit ETI as to its uncertain tax positions creating the FIN 48
liability.
35. Even if ETI is audited, ETI might prevail on its uncertain tax positions.
36. ETI may never have to pay the IRS the FIN 48 liability.
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37. Other than the amount of its deposit with the IRS, ETI has current use of the FIN 48
liability funds.
38. Until actually paid to the IRS, the FIN 48 liability represents cost-free capital and should
be deducted from rate base.
39. The amount of $4,621,778 (representing ETI's full FIN 48 liability of $5,916,461 less the
$1,294,683 cash deposit ETI has made with the IRS for the FIN 48 liability) should be
added to ETI's ADFIT and thus be used to reduce ETI's rate base.
40. ETI's application and proposed tariffs do not include a request for a tracking mechanism
or rider to collect a return on the FIN 48 liability.
40A. It is appropriate for ETI to create a deferred-tax-account tracker in the form of a rider to
recover on a prospective basis an after-tax return of 8.27% on the amounts paid to the
IRS that result from an unfavorable FIN 48 audit. The rider will track unfavorable FIN
48 rulings and the return will be applied prospectively to FIN 48 amounts disallowed by
an IRS audit after such amounts are actually paid to the federal government. If ETI
prevails in an appeal of a FIN 48 decision, then any amounts collected under the rider
related to that decision should be credited back to ratepayers.
41. Deleted.
42. Investor-owned electric utilities may include a reasonable allowance for cash working
capital in rate base as determined by a lead-lag study conducted in accordance with the
Commission's rules.
43. Cash working capital represents the amount of working capital, not specifically addressed
in other rate base items, that is necessary to fund the gap between the time expenditures
are made and the time corresponding revenues are received.
44. The lead-lag study conducted by ETI considered the actual operations of ETI, adjusted
for known and measurable changes, and is consistent with P.U.C. SUBST.
R. 25.231(c)(2)(B)(iii).
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45. It is reasonable to establish ETI's cash working capital requirement based on ETI's lead-
lag study as updated in Jay Joyce's rebuttal testimony and on the cost of service approved
for ETI in this case.
46. As a result of the black-box settlements in Application of Entergy Gulf States, Inc. for
Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800 (Nov. 7,
2008) and Docket No. 37744, the Commission did not approve ETI's storm damage
expenses since 1996 and its storm damage reserve balance.
47. ETI established a prima facie case concerning the prudence of its storm damage expenses
incurred since 1996.
48. Adjustments to the storm damage reserve balance proposed by intervenors should be
denied.
49. The Hurricane Rita regulatory asset should not be moved to the storm damage insurance
reserve.
50. ETI's appropriate Test-Year-end storm reserve balance was negative $59,799,744.
51. The amount of $9,846,037, representing the value of the average coal inventory
maintained at ETI's coal-burning facilities, is reasonable, necessary, and should be
included in rate base.
52. The Spindletop gas storage facility (Spindletop facility) is used and useful in providing
reliable and flexible natural gas supplies to ETI's Sabine Station and Lewis Creek
generating plants.
53. The Spindletop facility is critical to the economic, reliable operation of the Sabine Station
and Lewis Creek generating plants due to their geographic location in the far western
region of the Entergy system.
54. It is reasonable and appropriate to include ETI' s share of the costs to operate the
Spindletop facility in rate base.
55. Staff recommended updating ETI's balance amounts for short-term assets to the 13-
month period ending December 2011, which was the most recent information available.
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Staffs proposed adjustments should be incorporated into the calculation of ETI' s rate
base.
56. The following short-term asset amounts should be included in rate base: prepayments at
$8,134,351; materials and supplies at $29,285,421; and fuel inventory at $52,693,485.
57. The amount of $1,127,778, representing costs incurred by ETI when it acquired the
Spindletop facility, represent actual costs incurred to process and close the acquisition,
not mere mark-up costs.
58. ETI's $1,127,778 in capitalized acquisition costs should be included in rate base because
ETI incurred these costs in conjunction with the purchase of a viable asset that benefits
its retail customers.
59. In its application, ETI capitalized into plant in service accounts some of the incentive
payments ETI made to its employees. ETI seeks to include those amounts in rate base.
60. A portion of those capitalized incentive accounts represent payments made by ETI for
incentive compensation tied to financial goals.
61. The portion of ETI's incentive payments that are capitalized and that are financially-
based should be excluded from ETI's rate base because the benefits of such payments
inure most immediately and predominantly to ETI's shareholders, rather than its electric
customers. ETI's capitalized incentive compensation that is financially based is
$335,752.96 and should be removed for rate base.
62. The test-year for ETI's prior ratemaking proceeding ended on June 30, 2009, and the
reasonableness of ETI's capital costs (including capitalized incentive compensation) for
that prior period was dealt with by the Commission in that proceeding and is not at issue
in this proceeding.
63. In this proceeding, ETI's capitalized incentive compensation that is financially-based
should be excluded from rate base, but only for incentive costs that ETI capitalized
during the period from July l, 2009 (the end of the prior test-year) through June 30, 2010
(the commencement of the current test-year).
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Rate o(Return and Cost of Capital
64. A return on common equity (ROE) of 9.80 percent will allow ETI a reasonable
opportunity to earn a reasonable return on its invested capital.
65. The results of the discounted cash flow model and risk premium approach support a ROE
of 9.80 percent.
65A. It is not appropriate to add 15 points to the ROE due to unsettled economic conditions
facing utilities.
66. A 9.80 percent ROE is consistent with ETI's business and regulatory risk.
67. ETI's proposed 6.74 percent embedded cost of debt is reasonable.
68. The appropriate capital structure for ETI is 50.08 percent long-term debt and
49.92 percent common equity.
69. A capital structure composed of 50.08 percent debt and 49.92 percent equity is
reasonable in light of ETI' s business and regulatory risks.
70. A capital structure composed of 50.08 percent debt and 49.92 percent equity will help
ETI attract capital from investors.
71. ETI's overall rate of return should be set as follows:
CAPITAL WEIGHTED A VG
COMPONENT STRUCTURE COST OF CAPITAL COST OF CAPITAL
LONG· TERM DEBT 50.08% 6.74% 3.38%
COMMON EQUITY 49.92% 9.80% 4.89%
TOTAL 100.00% 8.27%
Operating Expenses
72. ETI's test-year purchased capacity expenses were $245,965,886.
73. ETI requested an upward adjustment of $30,809,355 as a post-test-year adjustment to its
purchased capacity costs. This request was based on ETI' s projections of its purchased
capacity expenses during a period beginning June 1, 2012 and ending May 31, 2013 (the
rate-year).
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74. ETI's purchased capacity expense projections were based on estimates of rate-year
expenses for: (a) reserve equalization payments under Schedule MSS-1; (b) payments
under third-party capacity contracts; and (c) payments under affiliate contracts.
75. ETI's projection of its rate-year reserve equalization payments under Schedule MSS-1 is
based on numerous assumptions, including load growths for ETI and its affiliates, future
capacity contracts for ETI and its affiliates, and future values of the generation assets of
ETI and its affiliates.
76. There is substantial uncertainty with regard to ETI's projection of its rate-year reserve
equalization payments under Schedule MSS-1.
77. ETI's projection of its rate-year third-party capacity contract payments includes
numerous assumptions, one of which is that every single third-party supplier will perform
at the maximum level under the contract, even though that assumption is inconsistent
with ETI' s historical experience.
78. There is substantial uncertainty with regard to ETI's projection of its rate-year third-party
capacity-contract payments.
79. ETI's estimates of its rate-year purchases under affiliate contracts are based on a
mathematical formula set out in Schedule MSS-4.
80. The MSS-4 formula for rate-year affiliate capacity payments reflects that these payments
will be based on ratios and costs that cannot be determined until the month that the
payments are to be made.
81. Over $11 million of ETI' s affiliate transactions were based on a 2013 contract (the EAi
WBL Contract) that was not signed until April 11, 2012.
82. There is uncertainty about whether the EAi WBL Contract will ever go into effect.
83. ETI projects purchasing over 300 megawatts (MW) more in purchased capacity in the
rate-year than it purchased in the test-year.
84. ETI experienced substantial load growth in the two years before the test-year, and it
continues to project similar load growth in the future.
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85. ETI did not meet its burden of proof to demonstrate that a known and measurable
adjustment of $30,809,355 should be made to its test-year purchased capacity expenses.
86. ETI's purchased capacity expense in this case should be based on the test-year level of
$245,965,886.
87. ETI incurred $1,753,797 of transmission equalization expense during the test-year.
88. ETI proposed an upward adjustment of $8,942,785 for its transmission equalization
expense. This request was based on ETI's projections of its transmission equalization
expenses during the rate-year.
89. The transmission equalization expense that ETI will pay in the rate-year will depend on
future costs and loads for each of the Entergy operating companies.
90. ETI's projection of its rate-year transmission equalization expenses is uncertain and
speculative because it depends on a number of variables, including future transmission
investments, deferred taxes, depreciation reserves, costs of capital, tax rates, operating
expenses, and loads of each of the Entergy operating companies.
91. ETI seeks increased transmission equalization expenses for transmission projects that are
not currently used and useful in providing electric service. ETI's post-test-year
adjustment is based on the assumption that certain planned transmission projects will go
into service after the test-year. At the close of the hearing, none of the planned
transmission projects had been fully completed and some were still in the planning phase.
92. It is not reasonable for ETI to charge its retail ratepayers for transmission equalization
expenses related to projects that are not yet in-service.
93. ETI's request for a post-test-year adjustment of $8,942,785 for rate-year transmission
equalization expenses should be denied because those expenses are not known and
measurable. ETI's post-test-year adjustment does not with reasonable certainty reflect
what ETI' s transmission equalization expense will be when rates are in effect.
94. ETI's transmission equalization expense in this case should be based on the test-year
level of $1,753,797.
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95. P.U.C. SUBST. R. 25.23 l(c)(2)(ii) states that the reserve for depreciation is the
accumulation of recognized allocations of original cost, representing the recovery of
initial investment over the estimated useful life of the asset.
96. Except in the case of the amortization of the general plant deficiency, the use of the
remaining life depreciation method to recover differences between theoretical and actual
depreciation reserves is the most appropriate method and should be continued.
97. It is reasonable for ETI to calculate depreciation reserve allocations on a straight-line
basis over the remaining, expected useful life of the item or facility.
98. Except as described below, the service lives and net salvage rates proposed by the
company are reasonable, and these service lives and net salvage rates should be used in
calculating depreciation rates for the company's production, transmission, distribution,
and general plant assets.
99. A 60-year life for Sabine Units 4 and 5 is reasonable for purposes of establishing
production plant depreciation rates.
100. The retirement (actuarial) rate method, rather than the interim retirement method, should
be used in the development of production plant depreciation rates.
101. Production plant net salvage is reasonably based on the negative five percent net salvage
in existing rates.
102. The net salvage rate of negative 10 percent for ETI's transmission structures and
improvements (FERC Account 352) is the most reasonable of those proposed and should
be adopted.
103. The net salvage rate of negative 20 percent for ETI's transmission station equipment
(FERC Account 353) is the most reasonable of those proposed and should be adopted.
104. The net salvage rate of negative five percent for ETI's transmission towers and fixtures
(FERC Account 354) is the most reasonable of those proposed and should be adopted.
105. The net salvage rate of negative 30 percent for ETI's transmission poles and fixtures
(FERC Account 355) is the most reasonable of those proposed and should be adopted.
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106. The net salvage rate of negative 30 percent for ETI's transmission overhead conductors
and devices (FERC Account 356) is the most reasonable of those proposed and should be
adopted.
107. A service life of 65 years and a dispersion curve of R3 for ETI' s distribution structures
and improvements (FERC Account 361) are the most reasonable of those proposed and
should be approved.
108. A service life of 40 years and a dispersion curve of Rl for ETI's distribution poles,
towers, and fixtures (FERC Account 364) are the most reasonable of those proposed and
should be approved.
109. A service life of 39 years and a dispersion curve of R0.5 for ETI's distribution overhead
conductors and devices (FERC Account 365) are the most reasonable of those proposed
and should be approved.
110. A service life of 35 years and a dispersion curve of Rl.5 for ETI's distribution
underground conductors and devices (FERC Account 367) are the most reasonable of
those proposed and should be approved.
111. A service life of 33 years and a dispersion curve of L0.5 for ETI' s distribution line
transformers (FERC Account 368) are the most reasonable of those proposed and should
be approved.
112. A service life of 26 years and a dispersion curve of L4 for ETI's distribution overhead
service (FERC Account 369.1) are the most reasonable of those proposed and should be
approved.
113. The net salvage rate of negative five percent for ETI's distribution structures and
improvements (FERC Account 361) is the most reasonable of those proposed and should
be adopted.
114. The net salvage rate of negative 10 percent for ETI' s distribution station equipment
(FERC Account 362) is the most reasonable of those proposed and should be adopted.
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115. The net salvage rate of negative seven percent for ETI's distribution overhead conductors
and devices (FERC Account 365) is the most reasonable of those proposed and should be
adopted.
116. The net salvage rate of positive five percent for ETI's distribution line transformers
(FERC Account 368) is the most reasonable of those proposed and should be adopted.
117. The net salvage rate of negative 10 percent for ETI's distribution overhead services
(FERC Account 369.1) is the most reasonable of those proposed and should be adopted.
118. The net salvage rate of negative 10 percent for ETI's distribution underground services
(FERC Account 369.2) is the most reasonable of those proposed and should be adopted.
119. A service life of 45 years and a dispersion curve of R2 for ETI's general structures and
improvements (FERC Account 390) are the most reasonable of those proposed and
should be approved.
120. The net salvage rate of negative 10 percent for ETI's general structures and
improvements (FERC Account 390) is the most reasonable of those proposed and should
be adopted.
121. It is reasonable to convert the $21.3 million deficit that has developed over time in the
reserve for general plant accounts to General Plant Amortization.
122. A ten-year amortization of the deficit in the reserve for general plant accounts is
reasonable and should be adopted.
123. FERC pronouncement AR-15 requires amortization over the same life as recommended
based on standard life analysis. A standard life analysis determined that a five-year life
was appropriate for general plant computer equipment (FERC Account 391.2).
Therefore, a five year amortization for this account is reasonable and should be adopted.
124. ETI proposed adjustments to its test-year payroll costs to reflect: (a) changes to employee
headcount levels at ETI and Entergy Services, Inc. (ESI); and (b) approved wage
increases set to go into effect after the end of the test-year.
125. The proposed payroll adjustments are reasonable but should be updated to reflect the
most recent available information on headcount levels as proposed by Commission Staff.
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In addition to adjusting payroll expense levels, the more recent headcount numbers
should be used to adjust the level of payroll tax expense, benefits expense, and savings
plan expense.
126. Staff has appropriately updated headcount levels to the most recent available data but
errors made by Staff should be corrected. The corrections related to: (a) a double
counting of three ETI and one ESI employee; (b) inadvertent use of the ETI benefits cost
percentage in the calculation of ESI benefits costs; (c) an inappropriate reduction of
savings plan costs when such costs were already included in the benefits percentage
adjustments; and (d) corrections for full-time equivalents calculations. Staffs ETI
headcount adjustment (AG-7) overstated operation and maintenance (O&M) payroll
reduction by $224,217, and ESI headcount adjustment (AG-7) understated O&M payroll
increase by $37,531.
127. ETI included $14,187,744 for incentive compensation expenses in its cost of service.
128. The compensation packages that ETI offers its employees include a base payroll amount,
annual incentive programs, and long-term incentive programs. The majority of the
compensation is for operational measures, but some is for financial measures.
129. Incentive compensation that is based on financial measures is of more immediate and
predominant benefit to shareholders, whereas incentive compensation based on
operational measures is of more immediate and predominant benefit to ratepayers.
130. Incentives to achieve operational measures are necessary and reasonable to provide utility
services but those to achieve financial measures are not.
131. The $5,376,975 that was paid for long term incentive programs was tied to financial
measures and, therefore, should not be included in ETI' s cost of service.
132. Of the amounts that were paid pursuant to the Executive Annual Incentive Plan, $819,062
was tied to financial measures and, therefore, should be disallowed.
133. In total, the amount of incentive compensation that should be disallowed is $6,196,037
because it was related to financial measures that are not reasonable and necessary for the
provision of electric service. An additional reduction should be made to account for the
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PUC Docket No. 39896 Order Page 25 of43
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FICA taxes ETI would have paid on the disallowed financially based incentive
compensation.
134. The amount of incentive compensation that should be included in the cost of service is
$7,991,707.
135. To attract and retain highly qualified employees, the Entergy companies provide a total
package of compensation and benefits that is equivalent in scope and cost with what other
comparable companies within the utility business and other industries provide for their
employees.
136. When using a benchmark analysis to compare companies' levels of compensation, it is
reasonable to view the market level of compensation as a range rather than a precise,
single point.
137. ETI's base pay levels are at market.
138. ETI's benefits plan levels are within a reasonable range of market levels.
139. ETI's level of compensation and benefits expense is reasonable and necessary.
140. ETI provides non-qualified supplemental executive retirement plans for highly
compensated individuals such as key managerial employees and executives that, because
of limitations imposed under the Internal Revenue Code, would otherwise not receive
retirement benefits on their annual compensation over $245,000 per year.
141. ETI' s non-qualified supplemental executive retirement plans are discretionary costs
designed to attract, retain, and reward highly compensated employees whose interests are
more closely aligned with those of the shareholders than the customers.
142. ETI' s non-qualified executive retirement benefits in the amount of $2, 114,931 are not
reasopable or necessary to provide utility service to the public, not in the public interest,
and should not be included in ETI' s cost of service.
143. For the employee market in which ETI operates, most peer companies offer moving
assistance. Such assistance is expected by employees, and ETI would be placed at a
competitive disadvantage if it did not offer relocation expenses.
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144. ETI's relocation expenses were reasonable and necessary.
145. The company's requested operating expenses should be reduced by $40,620 to reflect the
removal of certain executive prerequisites proposed by Staff.
146. Staff properly adjusted the company's requested interest expense of $68,985 by removing
$25,938 from FERC account 431 (using the interest rate of 0.12 percent for calendar year
2012), leaving a recommended interest expense of $43,047.
147. During the test-year, ETI's property tax expense equaled $23,708,829.
148. ETI requested an upward pro Jonna adjustment of $2,592,420, to account for the property
tax expenses ETI estimates it will pay in the rate-year.
149. ETI's requested pro Jonna adjustment is not reasonable because it is based, in part, upon
the prediction that ETI' s property tax rate will be increased in 2012, a change that is
speculative is not known and measurable.
150. Staffs recommendation to increase ETI's test-year property tax expenses by $1,214,688
is based on the historical effective tax rate applied to the known test-year-end plant in
service value, consistent with Commission precedent, and based upon known and
measurable changes.
151. ETI's test-year property tax burden should be adjusted upward by $1,222,106 for a total
expense of $24,921,022.
152. Staff recommended reducing ETI's advertising, dues, and contributions expenses by
$12,800. The recommendation, which no party contested, should be adopted.
153. The final cost of service should reflect changes to cost of service that affect other
components of the revenue requirement such as the calculation of the Texas state gross
receipts tax, the local gross receipts tax, the PUC Assessment Tax and the Uncollectible
Expenses.
154. The company's requested Federal income tax expense is reasonable and necessary.
155. ETI's request for $2,019,000 to be included in its cost of service to account for the
company's annual decommissioning expenses associated with River Bend is not
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PUC Docket No. 39896 Order Page 27 of43
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reasonable because it is not based upon "the most current information reasonably
available regarding the cost of decommissioning" as required by P.U.C. SUBST.
R. 25.23 l(b)(l)(F)(i).
156. Based on the most current information reasonably available, the appropriate level of
decommissioning costs to be included in ETI's cost of service is $1,126,000.
157. ETI' s appropriate total annual self-insurance storm damage reserve expense is
$8,270,000, comprised of an annual accrual of $4,400,000 to provide for average annual
expected storm losses, plus an annual accrual of $3,870,000 for 20 years to restore the
reserve from its current deficit.
158. ETI' s appropriate target self-insurance storm damage reserve is $17 ,595,000.
159. ETI should continue recording its annual storm damage reserve accrual until modified by
a Commission order.
160. The operating costs of the Spindletop facili.ty are reasonable and necessary.
161. The operating costs of the Spindletop facility paid to PB Energy Storage Services are
eligible fuel expenses.
Affiliate Transactions
162. ETI affiliates charged ETI $78,998,777 for services during the test-year. The majority of
these O&M expenses-$69,098,041-were charged to ETI by ESL The remaining
affiliate services were charged (or credited) to ETI by: Entergy Gulf States Louisiana,
L.L.C.; Entergy Arkansas, Inc.; Entergy Louisiana, LLC; Entergy Mississippi, Inc.;
Entergy Operations, Inc.; and non-regulated affiliates.
163. ESI follows a number of processes to ensure that affiliate charges are reasonable and
necessary and that ETI and its affiliates are charged the same rate for similar services.
These processes include: (a) the use of service agreements to define the level of service
required and the cost of those services; (b) direct billing of affiliate expenses where
possible; (c) reasonable allocation methodologies for costs that cannot be directly billed;
(d) budgeting processes and controls to provide budgeted costs that are reasonable and
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PUC Docket No. 39896 Order Page 28 of43
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necessary to ensure appropriate levels of service to its customers; and (e) oversight
controls by ETI' s Affiliate Accounting and Allocations Department.
164. Affiliates charged expenses to ETI through 1292 project codes during the test-year.
164A. The $2,086,145 in affiliate transactions related to sales and marketing expenses should be
reallocated using direct assignment. The following amounts should be allocated to all
retail classes in proportion to number of customers: (1) $46,490 for Project
ElOPCR56224 - Sales and Marketing - EGSI Texas; (2) $17,013 for Project
F3PCD10049 - Regulated Retail Systems O&M; and (3) $30,167 for Project
F3PPMMALI2 - Middle Market Mkt. Development. The remainder, $1,992,475, should
be assigned to (1) General Service, (2) Large General Service and (3) Large Industrial
Power Service.
165. ETI agreed to remove the following affiliate transactions from its application:
(1) Project F3PPCASHCT (Contractual Altemative/Cashpo) in the amount of $2,553;
(2) Project F3PCSPETEI (Entergy-Tulane Energy Institute) in the amount of $14,288;
and (3) Project F5PPKATRPT (Storm Cost Processing & Review) in the amount of $929.
166. The $356,151 (which figure includes the $112,531 agreed to by ETI) of costs associated
with Projects F5PCZUBENQ (Non-Qualified Post Retirement) and F5PPZNQBDU (Non
Qual Pension/Senf Dom Utl) are costs that are not reasonable and necessary for the
provision of electric utility service and are not in the public interest.
167. The $10,279 of costs associated with Project F3PPFXERSP (Evaluated Receipts
Settlement) are not normally-recurring costs and should not be recoverable.
168. The $19,714 of costs associated with Project F3PPEASTIN (Willard Eastin et al) are
related to ESI' s operations, it is more immediately related to Entergy Louisiana, Inc. and
Entergy New Orleans, Inc. As such, they are not recoverable from Texas ratepayers.
169. The $171,032 of costs associated with Project F3PPE9981S (Integrated Energy
Management for ESI) are research and development costs related to energy efficiency
programs. As such, they should be recovered through the energy efficiency cost recovery
factor rather than base rates.
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170. Except as noted in the above findings of fact Nos. 162-169, all remaining affiliate
transactions were reasonable and necessary, were allowable, were charged to ETI at a
price no higher than was charged by the supplying affiliate to other affiliates, and the rate
charged is a reasonable approximation of the cost of providing service.
Jurisdictional Cost Allocation
171. ETI has one full or partial requirements wholesale customer - East Texas Electric
Cooperative, Inc.
172. ETI proposes that 150 MW be set as the wholesale load for developing retail rates in this
docket. Using 150 MW to set the wholesale load is reasonable. The 150 MW used to set
the wholesale load results in a retail production demand allocation factor of
95.3838 percent.
173. The 12 Coincident Peak (12 CP) allocation method is consistent with the approach used
by the FERC to allocate between jurisdictions.
174. Using 12CP methodology to allocate production costs between the wholesale and retail
jurisdictions is the best method to reflect cost responsibility and is appropriate based on
ETI' s reliance on capacity purchases.
Class Cost Allocation and Rate Design
175. There is no express statutory authorization for ETI's proposed Renewable Energy Credits
rider (REC rider).
176. REC rider constitutes improper piecemeal ratemaking and should be rejected.
177. ETI's test-year expense for renewable energy credits, $623,303, is reasonable and
necessary and should be included in base rates.
178. Municipal Franchise Fees (MFF) is a rental expense paid by utilities for the right to use
public rights-of-way to locate its facilities within municipal limits.
179. ETI is an integrated utility system. ETI' s facilities located within municipal limits
benefit all customers, whether the customers are located inside or outside of the
municipal limits.
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180. Because all customers benefit from ETI's rental of municipal right-of-way, municipal
franchise fees should be charged to all customers in ETI' s service area, regardless of
geographic location.
181. It is reasonable and consistent with the Public Utility Regulatory Act (PURA)
§ 33.008(b) that MFF be allocated to each customer class on the basis of in-city kilowatt
hour (kWh) sales, without an adjustment for the MFF rate in the municipality in which a
given kWh sale occurred.
182. The same reasons for allocating and collecting MFF as set out in Finding of Fact
Nos. 178-181 also apply to the allocation and collection of Miscellaneous Gross Receipts
Taxes. The company's proposed allocation of these costs to all retail customer classes
based on customer class revenues relative to total revenues is appropriate.
l 82A. ETI' s proposed gross plant-based allocator is an appropriate method for allocating the
Texas franchise tax.
183. The Average and Excess (A&E) 4CP method for allocating capacity-related production
costs, including reserve equalization payments, to the retail classes is a standard
methodology and the most reasonable methodology.
184. The A&E 4CP method for allocating transmission costs to the retail classes is standard
and the most reasonable methodology.
185. ETI appropriately followed the rate class revenue requirements from its cost of service
study to allocate costs among customer classes. ETI's revenue allocation properly sets
rates at each class's cost of service.
186. It is reasonable for ETI to eliminate the service condition for Rate Groups A and C in
Schedule SHL [Street and Highway Lighting Service] that charges a $50 fee for any
replacement of a functioning light with a lower-wattage bulb.
187. It is appropriate to require ETI to prepare and file, as part of its next base rate case, a
study regarding the feasibility of instituting LED-based rates and, if the study shows that
such rates are feasible, ETI should file proposals for LED-based lighting and traffic
signal rates in its next rate case.
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188. An agreement was reached by the parties and approved by the Commission in Docket
No. 37744 that directed ETI to exclude, in its next rate case, the life-of-contract demand
ratchet for existing customers in the Large Industrial Power Service (LIPS), Large
Industrial Power Service-Time of Day, General Service, General Service-Time of Day,
Large General Service, and Large General Service-Time of Day rate schedules.
189. ETI's proposed tariffs in this case did not remove the life-of-contract demand ratchet
from these rate schedules consistent with the parties' agreement in Docket No. 37744.
190. A perpetual billing obligation based on a life-of-contract demand ratchet, as ETI
proposed, is not reasonable.
191. ETI's proposed LIPS and LIPS Time of Day tariffs should be modified to reflect the
agreement that was adopted by the Commission as just and reasonable in Docket
No. 37744. Accordingly, these tariffs should be modified as set out in Findings of Fact
No. 192-194.
192. ETI' s Schedule LIPS and LIPS Time of Day § VI should be changed to read:
DETERMINATION OF BILLING LOAD
The kW of Billing Load will be the greatest of the following:
(A) The Customer's maximum measured 30-minute
demand during any 30-minute interval of the current billing
month, subject to§§ III, IV and V above; or
(B) 75% of Contract Power as defined in§ VII; or
(C) 2,500 kW.
193. ETI's Schedule LIPS and LIPS Time of Day§ VII should be changed to read:
DETERMINATION OF CONTRACT POWER
Unless Company gives customer written notice to the contrary,
Contract Power will be defined as below:
Contract Power - the highest load established under§ VI(A) above
during the 12 months ending with the current month. For the
initial 12 months of Customer's service under the currently
effective contract, the Contract Power shall be the kW specified in
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PUC Docket No. 39896 Order Page 32 of43
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the currently effective contract unless exceeded in any month
during the initial 12-month period.
194. The Large General Service, Large General Service-Time of Day, General Service, and
General Service-Time of Day schedules should be similarly revised to eliminate ETI' s
life-of-contract demand ratchet.
195. In its proposed rate design for the LIPS class, the company took a conservative approach
and increased the current rates by an equal percentage. This minimized customer bill
impacts while maintaining cost causation principles on a rate class basis.
196. It is a reasonable move towards cost of service to add a customer charge of $630 to the
LIPS rate schedule with subsequent increases to be considered in subsequent base rate
cases.
197. It is a reasonable move towards cost of service to slightly decrease the LIPS energy
charges and increase the demand charges as proposed by Staff witness
William B. Abbott.
198. DOE proposed a new Schedule LIPS rider-Schedule "Schedulable Intermittent
Pumping Service" (SIPS) for load schedulable at least four weeks in advance, that occurs
in the off-season (November through April), that can be cancelled at any time, and for
load not lasting more than 80 hours in a year. For customers whose loads match these
SIPS characteristics (for example, DOE's Strategic Petroleum Reserve), the 12-month
demand ratchet provision of Schedule LIPS does not apply to demands set under the
provisions of the SIPS rider. The monthly demand set under the SIPS provisions would
be applicable for billing purposes only in the month in which it occurred. In short, if a
customer set a 12-month ratchet demand in that month, it would be forgiven and not
applicable in the succeeding 12 months.
199. DOE's proposed Schedule SIPS is not restricted solely to the DOE and should be
adopted. It more closely addresses specific customer characteristics and provides for
cost-based rates, as does another ETI rider applicable to Pipeline Pumping Service.
200. Standby Maintenance Service (SMS) is available to customers who have their own
generation equipment and who contract for this service from ETI.
000000032
PUC Docket No. 39896 Order Page 33 of43
SOAH Docket No. XXX-XX-XXXX
201. P.U.C. SUBST. R. 25.242(k)(l) provides that rates for sales of standby and maintenance
power to qualifying facilities should recognize system wide costing principles and should
not be discriminatory.
202. It is reasonable to move Schedule SMS toward cost of service by: (a) adding a customer
charge equivalent to that of the LIPS rate schedule only for SMS customers not
purchasing supplementary power under another applicable rate; and (b) revising the tariff
as follows:
Distribution Transmission
Charge
(less than 69KV) (69KV and greater)
Billing Load Charge ($/kW):
Standby $2.46 $0.79
Maintenance $2.27 $0.60
Non-Fuel Enenzv Charge (¢/kWh)
On-Peak 4.245¢ 4.074¢
Off-Peak 0.575¢ 0.552¢
203. ETI's Additional Facilities Charge rider (Schedule AFC) prescribes the monthly rental
charge paid by a customer when ETI installs facilities for that customer that would not
normally be supplied, such as line extensions, transformers, or dual feeds.
204. ETI existing Schedule AFC provides two pricing options. Option A is a monthly charge.
Option B, which applies when a customer elects to amortize the directly-assigned
facilities over a shorter term ranging from one to ten years, has a variable monthly
charge. There is also a term charge that applies after the facility has been fully
depreciated.
205. It is reasonable and cost-based to reduce the Schedule AFC Option A rate to 1.20 percent
per month of the installed cost of all facilities included in the agreement for additional
facilities.
000000033
PUC Docket No. 39896 Order Page 34 of43
SOAH Docket No. XXX-XX-XXXX
206. It is reasonable and cost-based to reduce the Schedule AFC Option B monthly rate and
the Post Term Recovery Charge as follows:
Selected Recovery Term Recovery Term Charge Post Recovery Term Charge
1 10.88% 0.35%
2 5.39% 0.35%
3 3.92% 0.35%
4 3.20% 0.35%
5 2.76% 0.35%
6 2.48% 0.35%
7 2.28% 0.35%
8 2.14% 0.35%
9 1.97% 0.35%
10 1.94% 0.35%
207. The revisions in the above findings of fact to Schedule AFC rates reasonably reflect the
costs of running, operating, and maintaining the directly-assigned facilities.
208. It is reasonable to modify the Large General Service rate schedule by increasing the
demand charge from $10.25 to $12.81; decreasing the energy charge from $.01023 to
$.00513; and maintaining the customer charge at $425.05.
209. Staffs proposed change to the General Service (GS) rate schedule to gradually move GS
customers towards their cost of service by recommending a decrease in the customer
charge from the current rate of $41.09 to $39.91, and a decrease in the energy charges is
reasonable and should be adopted.
210. ETI's Residential Service (RS) rate schedule is composed of two elements: a customer
charge of $5 per month and a consumption-based energy charge. The Energy charge is a
fixed rate of 5.802¢ per kWh from May through October (summer). In the months
November through April (winter), the rates are structured as a declining block, in which
the price of each unit is reduced after a defined level of usage.
211. ETI's Schedule RS declining block rate structure is contrary to energy-efficiency efforts
and the Legislature's goal of reducing both energy demand and energy consumption in
Texas, as stated in PURA § 39.905.
000000034
PUC Docket No. 39896 Order Page 35 of43
SOAH Docket No. XXX-XX-XXXX
212. Schedule RS winter block rates should be modified consistent with the goal set out in
PU,RA § 39.905, with the initial phase-in of a 20 percent reduction in the block
differential proposed by ETI and subsequent reductions should be reviewed for
consideration at the occurrence of each rate case filing.
213. Other elements of Schedule RS are just and reasonable.
Fuel Reconciliation
214. ETI incurred $616,248,686 in natural-gas expenses during the reconciliation period,
which is from July 2009 through June 2011.
215. ETI purchased natural gas in the monthly and daily markets and pursuant to a long-term
contract with Enbridge Inc. pipeline. ETI also transported gas on its own account and
negotiated operational balancing agreements with various pipeline companies.
216. ETI employed a diversified portfolio of gas supply and transportation agreements to meet
its natural-gas requirements, and ETI prudently managed its gas-supply contracts.
217. ETI' s natural gas expenses were reasonable and necessary expenses incurred to provide
reliable electric service to retail customers.
218. ETI incurred $90,821,317 in coal expenses during the reconciliation period.
219. ETI prudently managed its coal and coal-related contracts during the reconciliation
period.
220. ETI monitored and audited coal invoices from Louisiana Generating, LLC for coal
burned at the Big Cajun II, Unit 3 facility.
221. ETI's coal expenses were reasonable and necessary expenses incurred to provide reliable
electric service to retail customers.
222. ETI incurred $990,041,434 in purchased-energy expenses during the reconciliation
period.
223. The Entergy System's planning and procurement processes for purchased-power
produced a reasonable mix of purchased resources at a reasonable price.
000000035
PUC Docket No. 39896 Order Page36 of43
SOAH Docket No. XXX-XX-XXXX
224. During the reconciliation period, ETI took advantage of opportunities in the fuel and
purchased-power markets to reduce costs and to mitigate against price volatility.
225. ETI's purchased-energy expenses were reasonable and necessary expenses incurred to
provide reliable electric service to retail customers.
226. ETI provided sufficient contemporaneous documentation to support the reasonableness of
its purchased-power planning and procurement processes and its actual power purchases
during the reconciliation period.
227. The Entergy system sold power off system when the revenues were expected to be more
than the incremental cost of supplying generation for the sale, subject to maintaining
adequate reserves.
228. The System Agreement is the tariff approved by the FERC that provides the basis for the
operation and planning of the Entergy system, including the six operating companies.
The System Agreement governs the wholesale-power transactions among the operating
companies by providing for joint operation and establishing the bases for equalization
among the operating companies, including the costs associated with the construction,
ownership, and operation of the Entergy system facilities.
229. Under the terms of the Entergy System Agreement, ETI was allocated its share of
revenues and expenses from off-system sales.
230. During the reconciliation period, ETI recorded off-system sales revenue in the amount of
$376,671,969 in FERC Account 447 and credited 100 percent of off-system sales
revenues and margins from off-system sales to eligible fuel expenses.
231. ETI properly recorded revenues from off-system sales and credited those revenues to
eligible fuel costs.
232. The Entergy system consists of six operating companies, including ETI, which are
planned and operated as a single, integrated electric system under the terms of the System
Agreement.
233. Service schedule MSS-1 of the System Agreement determines how the capability and
ownership costs of reserves for the Entergy system are equalized among the operating
000000036
PUC Docket No. 39896 Order Page37 of43
SOAH Docket No. XXX-XX-XXXX
companies. These inter-system "reserve equalization" payments are the result of a
formula rate related to the Entergy system's reserve capability that is applied on a
monthly basis.
234. Reserve capability under service schedule MSS-1 is capability in excess of the Entergy
system's actual or planned load built or acquired to ensure the reliable, efficient operation
of the electric system.
235. By approving service schedule MSS-1, the FERC has approved the method by which the
operating companies share the cost of maintaining sufficient reserves to provide
reliability for the Entergy system as a whole.
236. Service schedule MSS-3 of the System Agreement determines the pricing and exchange
of energy among the operating companies. By approving service schedule MSS-3, the
FERC has approved the method by which the operating companies are reimbursed for
energy sold to the exchange energy pool and how that energy is purchased.
237. Service schedule MSS-4 of the System Agreement sets forth the method for determining
the payment for unit power purchases between operating companies. By approving
service schedule MSS-4, the FERC has approved the methodology for pricing
inter-operating company unit power purchases.
238. The Entergy system is planned using multi-year, annual, seasonal, monthly, and next-day
horizons. Once the planning process has identified the most economical resources that
can be used to reliably meet the aggregate Entergy system demand, the next step is to
procure the fuel necessary to operate the generating units as planned and acquire
wholesale power from the market.
239. Once resources are procured to meet forecasted load, the Entergy system is operated
during the current day using all the resources available to meet the total Entergy system
demand.
240. After current-day operation, the System Agreement prescribes an accounting protocol to
bill the costs of operating the system to the individual operating companies. This
protocol is implemented via the intra-system bill to each operating company on a
monthly basis.
000000037
PUC Docket No. 39896 Order Page 38 of43
SOAH Docket No. XXX-XX-XXXX
241. ETI purchased power from affiliated operating companies per the terms of service
schedule MSS-3 of the System Agreement. The payments made under Schedule MSS-3
to affiliated operating companies are reasonable and necessary, and the FERC has
approved the pricing formula and the obligation to purchase the energy. ETI pays the
same price per megawatt hour for energy under service schedule MSS-3 as does any
other operating company purchasing energy under service schedule MSS-3 during the
same hour.
242. The Spindletop facility is used primarily to ensure gas-supply reliability and guard
against gas-supply curtailments that can occur as a result of extreme weather or other
unusual events.
243. The Spindletop facility provides a secondary benefit of flexibility in gas supply. ETI can
back down gas-fired generation to take advantage of more economical wholesale power,
or use gas from storage to supplement gas-fired generation when load increases during
the day and thereby avoid more expensive intra-day gas purchases.
244. ETI's customers received benefits from the Spindletop facility during the reconciliation
period through reliable gas supplies and ETI's monthly and daily storage activity.
245. ETI prudently managed the Spindletop facility to provide reliability and flexibility of gas
supply for the benefit of customers.
246. ETI proposed new loss factors, based on a December 2010 line-loss study, to be applied
for the purpose of allocating its costs to its wholesale customers and retail customer
classes.
246A. ETI's 2010 line-loss factors should be used to reconcile ETI's fuel costs. Therefore,
ETI's fuel reconciliation over-recovery should be reduced by $3,981,271.
247. ETI's proposed loss factors are reasonable and shall be implemented on a prospective
basis as a result of this final order.
248. ETI seeks a special-circumstances exception to recover $99,715 resulting from the
FERC's reallocation of rough production equalization costs in FERC Order No. 720-A,
and to treat such costs as eligible fuel expense.
000000038
PUC Docket No. 39896 Order Page 39of43
SOAH Docket No. XXX-XX-XXXX
249. Special circumstances exist and it is appropriate for ETI to_recover the rough production
cost equalization costs reallocated to ETI as a result of the FERC' s decision in Order
No. 720-A.
Other Issues
250. A deferred accounting of ETI's Midwest Independent Transmission System Operator
(MISO) transition expenses is not necessary to carry out any requirement of PURA.
251. ETI should include $1.6 million in base rates for MISO transition expense.
252. Deleted.
253. Transmission Cost Recovery Factor baseline values should be set during the compliance
phase of this docket, after the Commission makes final rulings on the various contested
issues that may affect this calculation.
254. Distribution Cost Recovery Factor baseline values should be set during the compliance
phase of this docket, after the Commission makes final rulings on the various contested
issues that may affect this calculation.
255. The appropriate amount for ETI's purchased-power capacity expense to be included in
base rates is $245,965,886.
256. The amount of ETI's purchased-power capacity expense includes third-party contracts,
legacy affiliate contracts, other affiliate contracts, and reserve equalization. Whether the
amounts for all contracts should be included in the baseline for a purchased-capacity rider
that may be approved in Project No. 39246 is an issue that should be decided in that
project.
III. Conclusions of Law
1. ETI is a "public utility" as that term is defined in PURA § 11.004(1) and an "electric
utility" as that term is defined in PURA § 31.002( 6).
2. The Commission exercises regulatory authority over ETI and jurisdiction over the subject
matter of this application pursuant to PURA§§ 14.001, 32.001, 32.101, 33.002, 33.051,
36.101-.111, and 36.203.
000000039
PUC Docket No. 39896 Order Page40 of43
SOAH Docket No. XXX-XX-XXXX
3. SOAH has jurisdiction over matters related to the conduct of the hearing and the
preparation of a proposal for decision in this docket, pursuant to PURA § 14.053 and
TEX. GoV'T CODE ANN. § 2003.049.
4. This docket was processed in accordance with the requirements of PURA and the Texas
Administrative Procedure Act, Tex. Gov't Code Ann. Chapter 2001.
5. ETI provided notice of its application in compliance with PURA§ 36.103, P.U.C. PROC.
R. 22.51(a), and P.U.C. SUBST. R. 25.235(b)(l)-(3).
6. Pursuant to PURA § 33.001, each municipality in ETI's service area that has not ceded
jurisdiction to the Commission has jurisdiction over the company's application, which
seeks to change rates for distribution services within each municipality.
7. Pursuant to PURA § 33.051, the Commission has jurisdiction over an appeal from a
municipality's rate proceeding.
8. ETI has the burden of proving that the rate change it is requesting is just and reasonable
pursuant to PURA § 36.006.
9. In compliance with PURA§ 36.051, ETI's overall revenues approved in this proceeding
permit ETI a reasonable opportunity to earn a reasonable return on its invested capital
used and useful in providing service to the public in excess of its reasonable and
necessary operating expenses.
10. Consistent with PURA § 36.053, the rates approved in this proceeding are based on
original cost, less depreciation, of property used and useful to ETI in providing service.
11. The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059
and P.U.C. SUBST. R. 25.231(c)(2)(C)(i).
12. Including the cash working capital approved in this proceeding in ETI's rate base is
consistent with P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV), which allows a reasonable
allowance for cash working capital to be included in rate base.
13. The ROE and overall rate of return authorized in this proceeding are consistent with the
requirements of PURA§§ 36.051and36.052.
000000040
PUC Docket No. 39896 Order Page 41of43
SOAH Docket No. XXX-XX-XXXX
14. The affiliate expenses approved in this proceeding and included in ETI' s rates meet the
affiliate payment standards articulated in PURA §§ 36.051, 36.058, and Railroad
Commission of Texas v. Rio Grande Valley Gas Co., 683 S.W.2d 783 (Tex. App.-
Austin 1984, no writ).
15. The ADFIT adjustments approved in this proceeding are consistent with PURA§ 36.059
and P.U.C. SUBST. R. 25.231(c)(2)(C)(i).
16. Pursuant to P.U.C. SUBST. R. 25.23 l(b)(l)(F), the decommissioning expense approved in
this case is based on the most current information reasonably available regarding the cost
of decommissioning, the balance of funds in the decommissioning trust, anticipated
escalation rates, the anticipated return on the funds in the decommissioning trust, and
other relevant factors.
17. ETI has demonstrated that its eligible fuel expenses during the reconciliation period were
reasonable and necessary expenses incurred to provide reliable electric service to retail
customers as required by P.U.C. SUBST. R. 25.236(d)(l)(A). ETI has properly accounted
for the amount of fuel-related revenues collected pursuant to the fuel factor during the
reconciliation period as required by P.U.C. SUBST. R. 25.236(d)(l)(C).
18. ETI prudently managed the dispatch, operations, and maintenance of its fossil plants
during the reconciliation period.
19. The reconciliation period level operating and maintenance expenses for the Spindletop
facility are eligible fuel expenses pursuant to P.U.C. SUBST. R. 25.236(a).
19A. Fuel factors under P.U.C. SUBST. R. 25.237(a)(3) are temporary rates subject to revision
in a reconciliation proceeding.
19B. P.U.C. SUBST. R. 25.236(d)(2) defines the scope of a fuel reconciliation proceeding to
include any issue related to the reasonableness of a utility's fuel expenses and whether
the utility has over- or under-recovered its reasonable fuel expenses. It is proper to use
the new line-loss study to calculate Entergy's fuel reconciliation and over-recovery.
20. Special circumstances are warranted pursuant to P.U.C. SUBST. R. 25.236(a)(6) to
recover rough production equalization payments reallocated to ETI by the FERC.
000000041
PUC Docket No. 39896 Order Page 42 of 43
SOAH Docket No. XXX-XX-XXXX
21. ETI' s rates, as approved in this proceeding, are just and reasonable in accordance with
PURA § 36.003.
IV. Ordering Paragraphs
In accordance with these findings of fact and conclusions of law, the Commission issues
the following orders:
1. The proposal for decision prepared by the SOAH AL.Js is adopted to the extent consistent
with this Order.
2. ETI' s application is granted to the extent consistent with this Order.
3. ETI shall file in Tariff Control No. 40742 Compliance Tariff Pursuant to Final Order in
Docket No. 39896 (Application of Entergy Texas, Inc. for Authority to Change Rates,
Reconcile Fuel Costs, and Obtain Deferred Accounting Treatment) tariffs consistent with
this Order within 20 days of the date of this Order. No later than ten days after the date
of the tariff filings, Staff shall file its comments recommending approval, modification,
or rejection of the individual sheets of the tariff proposal. Responses to the Staff's
recommendation shall be filed no later than 15 days after the filing of the tariff. The
Commission shall by letter approve, modify, or reject each tariff sheet, effective the date
of the letter.
4. The tariff sheets shall be deemed approved and shall become effective on the expiration
of 20 days from the date of filing, in the absence of written notification of modification or
rejection by the Commission. If any sheets are modified or rejected, ETI shall file
proposed revisions of those sheets in accordance with the Commission's letter within ten
days of the date of that letter, and the review procedure set out above shall apply to the
revised sheets.
5. Copies of all tariff-related filings shall be served on all parties of record.
6. ETI shall prepare and file as part of its next base rate case a study regarding the
feasibility of instituting LED-based rates and, if the study shows that such rates are
feasible, ETI should file proposals for LED-based lighting and traffic signal rates in that
case. If ETI has LED lighting customers taking service, the study shall include detailed
000000042
PUC Docket No. 39896 Order Page 43 of 43
SOAH Docket No. XXX-XX-XXXX
information regarding differences in the cost of serving LED and non-LED lighting
customers. ETI shall provide the results of this study to Cities and interested parties as
soon as practicable, but no later than the filing of its next rate case.
7. All other motions, requests for entry of specific findings of fact and conclusions of law,
and any other requests for general or specific relief, if not expressly granted, are denied.
SIGNED AT AUSTIN, TEXAS the ~day of September 2012.
PUBLIC UTILITY COMMISSION OF TEXAS
2~~IRMAN
I respectfully dissent regarding the utility- and executive-management-class affiliate
transactions. To be consistent with Commission precedent in Docket No. 14965,37 the indirect
costs of the management of Entergy's ultimate parent should not be borne by Texas ratepayers.
Therefore, I would disallow the following: $173,867 for Project No. F3PCCPM001 (Corporate
Performance Management); $372,919 for Project No. F3PCC31255 (Operations-Office of the
CEO); and $74,485 for Project No. F3PPC00001 (Chief Operating Officer). I join the
Commission in all other respects for this Order.
q:\cadm\orders\final\39000\39896fo2.docx
37
Application of Central Power and Light Company for Authority to Change Rates, Docket No. 14965,
Second Order on Rehearing (Oct. 16, 1997).
000000043
SOAH Docket No. XXX-XX-XXXX
PUC Docket No. 40295
ETI Exhibit No. 4
SOAH DOCKET NO. XXX-XX-XXXX
DOCKET NO. 39896
APPLICATION OF ENTERGY § BEFORE THE STATE OFFICE
TEXAS, INC. FOR AUTHORITY §
TO CHANGE RATES, RECONCILE § OF
FUEL COSTS, AND OBTAIN §
DEFERRED ACCOUNTING § ADMINISTRATIVE HEARINGS
TREATMENT §
SUPPLEMENTAL DIRECT TESTIMONY
OF
MICHAEL P. CONSIDINE
ON BEHALF OF
ENTERGY TEXAS, INC.
MARCH 2012
1 ~q
~ 36
ENTERGY TEXAS, INC.
SUPPLEMENTAL DIRECT TESTIMONY OF MICHAEL P. CONSIDINE
DOCKET NO. 39896
TABLE OF CONTENTS
I. WITNESS INTRODUCTION 1
II. PURPOSE OF SUPPLEMENTAL TESTIMONY 1
Ill. UPDATE REGARDING INTERNAL RATE CASE EXPENSES 2
IV. RECOVERY OF RATE CASE EXPENSES 5
EXHIBIT
Exhibit MPC-SD-1 Requested Rate Case Expenses
Exhibit MPC-SD-2 ESI Payroll, Benefits, and Taxes Charged to ETI by Affiliate
Class
2
37
Entergy Texas, Inc. Page 1of5
Supplemental Direct Testimony of Michael P. Considine
Docket No. 39896
1 I. WITNESS INTRODUCTION
2 a. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
3 A. My name is Michael P. Considine. My business address is 425 West
4 Capitol Avenue, Little Rock, Arkansas 72201. I am employed by Entergy
5 Services, Inc. ("ESr), the service company affiliate of Entergy Texas, Inc.
6 ("ETI" or the "Company") as a Senior Staff Accountant in the Rate Design
7 and Administration Department.
8
9 a. DID YOU PREVIOUSLY FILE TESTIMONY IN THIS PROCEEDING?
10 A. Yes. I filed direct testimony as part of the Company's rate filing package.
11
12 II. PURPOSE OF SUPPLEMENTAL DIRECT TESTIMONY
13 a. WHAT IS THE PURPOSE OF YOUR SUPPLEMENTAL DIRECT
14 TESTIMONY?
15 A. My supplemental direct testimony supports and updates the Company's
16 request to recover rate case expenses associated with this proceeding.
17 Specifically, I provide the levels of rate case expenses incurred (that is,
18 recorded on the Company's books) as of January 31, 2012, related to: (1)
19 outside accounting services, outside legal counsel, and consultants
20 ("external rate case expenses"); and (2) ETI direct expenses and ESI
21 payroll, benefits, and taxes ("internal rate case expenses"). In addition, I
22 address the reasonableness and necessity of the internal rate case
23 expenses. Company witness Mr. Stephen Morris has filed direct, and now
3
38
Entergy Texas, Inc. Page2of5
Supplemental Direct Testimony of Michael P. Considine
Docket No. 39896
1 supplemental direct, testimony addressing the reasonableness and
2 necessity of external rate case expenses.
3
4 Ill. UPDATE REGARDING INTERNAL RATE CASE EXPENSES
5 Q. SINCE FILING ITS RATE FILING PACKAGE, HAS THE COMPANY
6 PROVIDED ITS INCURRED RATE CASE EXPENSES?
7 A. Yes. On February 21, 2012, in response to Staff Request for Information
8 ("RFI") 9-1, the Company filed schedules of: (1) external rate case
9 expenses as of December 31, 2011; and 2) internal rate case expenses
10 as of December 31, 2011.
11
12 Q. DO YOU PROVIDE AN UPDATE REGARDING THE LEVELS OF
13 INCURRED RATE CASE EXPENSES IN YOUR SUPPLEMENTAL
14 DIRECT TESTIMONY?
15 A. Yes. The Company's Addendum to its response to Staff RFI 9-1 is
16 attached as Exhibit MPC-SD-1, which presents external rate case
17 expenses by vendor and internal rate case expenses by ETI direct
18 expense category and ESI department. As shown in Exhibit MPC-SD-1,
19 as of January 31, 2012, the Company had incurred $1,963, 113 in external
20 rate case expenses and $2,173,124 in internal rate case expenses. The
21 Company requests recovery of these external and internal rate case
22 expenses.
4
39
Entergy Texas, Inc. Page 3of5
Supplemental Direct Testimony of Michael P. Considine
Docket No. 39896
1 Q. HAVE YOU REVIEWED THE INCURRED INTERNAL RATE CASE
2 EXPENSES PRESENTED IN EXHIBIT MPC-SD-1 TO DETERMINE
3 WHETHER SUCH EXPENSES ARE REASONABLE AND NECESSARY?
4 A. Yes.
5
6 Q. HOW DID YOU DETERMINE WHETHER THE INCURRED INTERNAL
7 RATE CASE EXPENSES PRESENTED IN EXHIBIT MPC-SD-1 WERE
8 REASONABLE AND NECESSARY?
9 A. Internal rate case expenses are all captured in Project Code
10 F5PPETX011. The project code is used only for time and expense
11 related to this rate case, and all costs incurred by ESI in this project code
12 are directly billed to ETI. The process through which costs are billed to
13 project codes is described in Company witness Stephanie B. Tuminello's
14 direct testimony. In addition, the Company's affiliate class witnesses,
15 including those who address the ETI direct charges, explain how the
16 budgeting and cost control processes work within their business units.
17 For example, timesheet and expense reports are reviewed by supervisors
18 to ensure accuracy. Also, Company witness Kevin G. Gardner supports
19 the reasonableness and necessity of the compensation and benefits paid
20 to ESI employees.
21 Company witnesses have presented direct testimony regarding the
22 various classes of affiliate costs that ETI receives from ESI, and my
23 Exhibit MPC-SD-2 shows the ESI rate case charges to ETI by affiliate
5
40
Entergy Texas, Inc. Page4 of5
Supplemental Direct Testimony of Michael P. Considine
Docket No. 39896
1 class. The processes and practices described in the Company's direct
2 testimony regarding billing, budgeting, cost control, compensation, and
3 benefits remain in effect today. These processes and practices help to
4 ensure that the requested internal rate case expenses are necessary and
5 reasonable, represent the actual costs of the services, do not include
6 prohibited expenses, do not include charges for duplicative services or
7 expenses, and are no higher than the prices charged to other affiliates, or
8 to non-affiliates, for the same or similar classes of item.
9 Further, a review of the Company's requested rate case expenses
10 is undertaken to determine that only appropriate charges are included in
11 the rate case expense request, and inappropriate charges, such as
12 charges for luxury items or excessive meals charges, are excluded.
13
14 Q. WHAT DID YOU CONCLUDE WITH RESPECT TO THE
15 REASONABLENESS AND NECESSITY OF THE COMPANY'S
16 INCURRED INTERNAL RATE CASE EXPENSES?
17 A Based on my review and analysis, as described above, the Company's
18 incurred internal rate case expenses are reasonable and necessary.
6
41
Entergy Texas, Inc. Page5of5
Supplemental Direct Testimony of Michael P. Considine
Docket No. 39896
1 IV. RECOVERY OF RATE CASE EXPENSES
2 Q. HOW DOES THE COMPANY PROPOSE TO RECOVER RATE CASE
3 EXPENSES?
4 A. As explained in my direct testimony, the Company proposes that it be
5 permitted to recover all incurred rate case expenses over a three-year
6 period, with a return on the unamortized balance.
7
8 Q. WILL THE COMPANY PROVIDE ADDITIONAL UPDATES REGARDING
9 THE LEVEL OF INCURRED RATE CASE EXPENSES?
10 A. Yes. Staff RFI 9-1 requests that ETI provide monthly updates regarding
11 the level of incurred rate case expenses. ETI will provide the next update
12 to Staff RFI 9-1 on or around March 21, 2012.
13
14 Q. WILL YOU PROVIDE ADDITIONAL SUPPLEMENTAL TESTIMONY
15 REGARDING THE REASONABLENESS AND NECESSITY OF
16 INCURRED INTERNAL RATE CASE EXPENSES?
17 A. It is likely that I will file additional supplemental direct testimony regarding
18 the reasonableness and necessity of internal rate case expenses incurred
19 after those addressed herein.
20
21 Q. DOES THIS CONCLUDE YOUR SUPPLEMENTAL DIRECT
22 TESTIMONY?
23 A. Yes.
7
42
Exhibit MPC-SD-1
Docket No. 39898
Page 1 of2
ENTERGY TEXAS, INC.
RATE CASE EXPENSES RECORDED THROUGH THE MONTH ENDED JANUARY 31, 2012
ETI 6/30/11 COS DOCKET 39896
AMOUNT
ACCQUNDNG
DELOITTE & TOUCHE LLP Total 915,970
LESS: NON-CONFORMING D&T EXPENSES (2,373)
PRICEWATERHOUSE COOPERS LlP Total 122,168
LESS: NON-CONFORMING PWC EXPENSES (7)
ACCOUNTING TOTAL 1,035,758 •
CON8lJLTAND
EXPERT POWERHOUSE LLC OBA EXPERGY 104,689
FINANCOINC 15,051
GERALD WTUCKER CPA 56,575
JAY HARTZELL 8,100
CONSULTANTS TOTAL 184,415 *
DUGGINS VIJREN MANN & ROMERO LlP 742,975
LESS: NON-CONFORMING D\Mv'IR EXPENSES (35)
LEGAL BILLS RECEIVED BUT NOT PAID
LEGAL TOTAL 742,940 *
COMPANX DIRECT EX'.PENSE§
Business Meals/Entertainment 1,627
CHle8 BIBS-Lawton Law Firm 22,220
Computer & Office Supplies 189
Court Transatpts
Depreciation Expense-General 97,103
Employee Mtgs/Functlons 2,686
Equipment And Other Rentals
Legal Notices 98,ns
Lodging 3,679
Long Distance Charges
Other Employee Expenses 879
Other Office & General 5,401
Personal Car MHeage • Local 595
Ponting, MalUng & Shipping 3,49S
Safety Training Loader 1,291
Se!Vlce Company Recipient 206.740
Temporary SelVlces 10,494
Travel Transportation 5,114
UtlUty BIDa 2,518
COMPANY DIRECT EXPENSES TOTAL 462,806
ES! PAYROLL BENEflD & TA)(ES 1,710,318 SEE DETAIL ON PAGE 2
ACDJAL RAD CAU EX'.PENSU IltROUQH 1131(1f 4,136,237
* Please refer to the Company's response and addend urns to Staff RFI 9-1 for detail
supporting ti'le Accounting, Consultant, and Legal expenses addressed above. Amounts for
Duggins Wren Mann & Romero, LLP Include fees and expenses from the following
consultants: Commonwealth Consulting; Alllance Consulting; LeWla & Ellla; and Naman,
Howell, Smith & Lee.
8
43
ENTERGY TEXAS, INC.
RATE CASE PAYROLL FOR ESI EMPLOYEES THROUGH THE MONTH ENDED JANUARY 31, 2012 Extibll MPC-SD-1
ETI 8130111 COS DOCKET 39898 Docket No. 39896
Page 2 of2
DEPARTIEfr WAGES HOURS ACTIVITIES
Dir, CrpAvtn, Secll' &R.E. Op 1,423 17 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Colledlont, Eel Detail 498 14 ASSIST IN RATE CASE PREPARATION &RFI RESPONSES
Remillance PIOCllllklg-Esl 120 e ASSIST IN RATE CASE PREPARATION &RFI RESPONSES
Csc Cullarler Contact Solutna 14,064 137 ASSIST IN RATE CASE PREPARATION &RFI RESPONSES
Cua1crn9r Load lntlm'llllon Adm 8,488 136 ASSIST IN RATE CASE PREPARATION &RFI RESPONSES
Bod Feea,Crp Dues ·Eli 36,705 • ASSIST IN RATE CASE PREPARATION &RFI RESPONSES
Revenue Requirement &~ 1s1.m 2,489 ASSIST IN RATE CASE PREPARATION &RFI RESPONSES
Rate Oellgn & Admlnlltnltlon 107,871 1,737 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Regulaloly Lltfglllon Support 87,808 2,537 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Director· Regutmory Proj9cts 10,258 136 ASSIST IN RATE CASE PREPARATION &RFI RESPONSES
Forecatil111 &Alllllyala 981 21 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Fuel & Special Ridenl 9,885 154 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Planning Anllylla 220 2 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Vp Regulalory Seivlca 2.170 13 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
~Optimization 517 9 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Regula1Dry Accounting 280,150 3,937 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Mldg R....at & Forecutrng 780 11 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Whollllle Bllllnese 1,977 19 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Diltrlbutlon Enginlel1ng Delli 22,838 288 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Prof Collif9Fi.d AIMta Opna 2,950 49 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Acc:ounll Payable 9,582 378 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Afliftal8 Al::c:l'g & Allocations 78,804 1,359 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Corporate Plarri1g & Pedorm 3,238 59 ASSIST IN RATE CASE PREPARATION &RFI RESPONSES
E>demal Reporting 18,784 380 ASSIST IN RATE CASE PREPARATION &RFI RESPONSES
Con1RJller Utllty Opel1lllona 4,520 87 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
CFO: ~ Openltlon1 7,549 82 ASSIST IN RATE CASE PREPARATION &RFI RESPONSES
Sllte And Local T - 20,132 241 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Regutab'y TIX SUpport 25,978 178 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
0111ce C!1 Corp Risk C>veralght 103 1 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Aa:ountlng Pollc:y And R-.dl 998 15 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
COfPOl819 Finance 14,323 201 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Buslneee ServicH 13,370 159 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Income TIX Accounting 14,804 249 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Dir, Tax Accounting & Complian 1.942 18 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Anet Managrnent Support 19,682 341 ASSIST JN RATE CASE PREPARATION & RFI RESPONSES
Compenaallon & Benefits Design 80,857 723 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
HR~ 2,942 43 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
VP HR Netwolk Operations 1,393 25 ASSIST JN RATE CASE PREPARATION & RFI RESPONSES
HR• Project Management 13,614 118 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
HR· Tolal RNalda Prgma 2,978 28 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
HR· Total R-m Ope 357 7 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
HR • Bulineaa Melrk;s 230 3 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Chief Legal Otllcer 58,949 589 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
l.8Qll • l.lllgatlon • TX 4,817 52 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Legal· Generlll Counsel 2,028 25 ASSIST IN RATE CASE PREPARATION & RA RESPONSES
Legal • Reg • Corp 1,040 4 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Legal • Reg ·TX 10,684 72 ASSIST IN RATE CASE PREPARATION & RA RESPONSES
Utllty Convn 0119ctor 509 4 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
VP· Advocaq Communleallona 338 9 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Fed11111I Regulaby Alfalnl 758 8 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
WEB COMMUNICATIONS 1,048 15 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Syatem Regulllory Affalre(Dlr) 4,360 88 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Rilk Management 12,122 157 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
lntemal Audit 1,938 29 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
SUPPLY CHAIN BUSINESS SUPPORT 7,311 97 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
DIRECTOR SUPPLY CHAIN SUPPORT 2,158 19 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Regllltly Mrs/Energy Settlmt 74,029 1,157 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
SPO CoqJPance&Contract Adrrin. 549 15 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
SPO Compllanc:e&Buaineaa Supprt 2.435 20 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Generation Planning & Models 2,858 30 ASSIST JN RATE CASE PREPARATION & RFI RESPONSES
Supply Pllnnlng andAnalyala 742 18 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
VP Energy Management 487 4 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Gen Supvn • Srp&S 7,014 es ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Reguia1Dly Slrallgy 19,915 211 ASSIST IN RATE CASE PREPARATION& RFI RESPONSES
Infra & EnterprlH Strvlces 4,688 47 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Security and Compliance 6,591 62 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Trana Regulatory Support 20,991 260 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
TOTAL ESI WAGES 1,303,158 19,406
ESI EMPLOYEE BENEFITS & TAXES 407,159 9
TOTAL ESI PAYROLL. BENEFITS & TAXES 1,710,318
44
Exhibit MPC-SD-2
Docket No. 39896
Page 1 of1
ESI PAYROLL, BENEFITS, AND TAXES CHARGED TO ETI BY AFFILIATE CLASS
14,803 0.87%
ENERGY AND FUEL MANAGEMENT 108401 6.34%
DISTRIBUTION OPERATIONS 29,971 1.75%
FINANCIAL SERVICES 183,291 10.72%
FEDERAL PRG AFFAIRS 6,718 0.39%
TAX SERVICES 82,495 4.82%
HUMAN RESOURCES 108,108 6.32%
FOSSIL PLANT OPERATIONS 25,831 1.51%
INTERNAL & EXTERNAL COMMUNICATIONS 2,483 0.15%
SUPPLY CHAIN 12,428 0.73%
REGULATORY SERVICES 887,801 51.91%
TRANSMISSION OPERATIONS 27,549 1.61%
TREASURY OPERATIONS 34,842 2.04%
ADMINISTRATION 1,867 0.11%
LEGAL SERVICES 101,713 5.95%
CUSTOMER SERVICE OPERATIONS 30,225 1.77%
RETAIL OPERATIONS 3,619 0.21%
OTHER EXPENSES 48,174 2.82%
1,710,318 100.00%
10
45
SOAH Docket No. XXX-XX-XXXX
PUC Docket No. 40295
ETI Exhibit No. 5
SOAH DOCKET NO. XXX-XX-XXXX
DOCKET NO. 40295
APPLICATION OF ENTERGY § BEFORE THE STATE OFFICE
TEXAS, INC. FOR RATE CASE §
EXPENSES PERTAINING TO § OF
PUC DOCKET NO. 39896 §
§ ADMINISTRATIVE HEARINGS
SUPPLEMENTAL DIRECT TESTIMONY
OF
MICHAEL P. CONSIDINE
ON BEHALF OF
ENTERGY TEXAS, INC.
OCTOBER 2012
ENTERGY TEXAS, INC.
SUPPLEMENTAL DIRECT TESTIMONY OF
MICHAEL P. CONSIDINE
DOCKET NO. 40295
TABLE OF CONTENTS
I. Witness Introduction 1
II. Purpose of Supplemental Testimony 1
Ill. Update Regarding Internal Rate Case Expenses 2
IV. Recovery of Rate Case Expenses 5
EXHIBITS
Exhibit MPC-SD-3 Requested Rate Case Expenses
Exhibit MPC-SD-4 ES! Payroll, Benefits, and Taxes Charged to ETI by
Affiliate Class
2
Entergy Texas, Inc. Page 1of6
Supplemental Direct Testimony of Michael P. Considine
Docket No. 40295
1 I. WITNESS INTRODUCTION
2 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
3 A. My name is Michael P. Considine. My business address is 425 West
4 Capitol Avenue, Little Rock, Arkansas 72201. I am employed by Entergy
5 Services, Inc. ("ESI"), the service company affiliate of Entergy Texas, Inc.
6 ("ETI" or the "Company'') as a Manager in the Regulatory Accounting
7 Department.
8
9 Q. DID YOU PREVIOUSLY FILE TESTIMONY RELATED TO THIS
10 PROCEEDING?
11 A. Yes. In Docket No. 39896, I filed direct testimony as part of the
12 Company's rate filing package, supplemental direct testimony on March
13 13, 2012, and rebuttal testimony on April 13, 2012.
14
15 II. PURPOSE OF SUPPLEMENTAL DIRECT TESTIMONY
16 Q. WHAT IS THE PURPOSE OF THIS ADDITIONAL SUPPLEMENTAL
17 DIRECT TESTIMONY?
18 A. This supplemental direct testimony supports and updates the Company's
19 request to recover rate case expenses associated with this proceeding.
20 Specifically, I provide the levels of rate case expenses incurred and paid
21 as of August 31, 2012, related to outside accounting services, outside
22 legal counsel, and outside consultants ("external rate case expenses"). I
23 also provide the levels of rate case expenses incurred and paid as of
Entergy Texas, Inc. Page 2 of6
Supplemental Direct Testimony of Michael P. Considine
Docket No. 40295
1 August 31, 2012, related to ETI direct expenses and ESI payroll, benefits,
2 and taxes ("internal rate case expenses"). In addition, I address the
3 reasonableness and necessity of the internal rate case expenses.
4 Company witness Stephen Morris has filed direct testimony as part of
5 ETl's filing package, supplemental direct testimony on March 13, 2012,
6 and additional supplemental direct testimony contemporaneous with the
7 filing of this testimony addressing the reasonableness and necessity of
8 external rate case expenses.
9
10 Ill. UPDATE REGARDING INTERNAL RATE CASE EXPENSES
11 Q. SINCE FILING ITS RATE FILING PACKAGE, HAS THE COMPANY
12 PROVIDED ITS INCURRED RATE CASE EXPENSES?
13 A. Yes. On February 21, 2012, in response to Staff Request for Information
14 ("RF!") 9-1, the Company filed schedules of: (1) external rate case
15 expenses as of December 31, 2011; and (2) internal rate case expenses
16 as of December 31, 2011. On March 13, 2012, an update to Staff RFI 9-1
17 was provided. The Company filed schedules of (1) external rate case
18 expenses as of January 31, 2012; and (2) internal rate case expenses as
19 of January 31, 2012.
Entergy Texas, Inc. Page 3 of6
Supplemental Direct Testimony of Michael P. Considine
Docket No. 40295
1 Q. DO YOU PROVIDE AN UPDATE REGARDING THE LEVELS OF
2 INCURRED RATE CASE EXPENSES IN THIS PIECE OF
3 SUPPLEMENTAL DIRECT TESTIMONY?
4 A. Yes. The summary rate case expense spreadsheet included as part of
5 the Company's Second Addendum to its response to Staff RFI 9-1 is
6 attached as Exhibit MPC-SD-3, which presents external rate case
7 expenses by vendor and internal rate case expenses by ETI direct
8 expense category and ESI department. As shown in Exhibit MPC-SD-3,
9 as of August 31, 2012, the Company had incurred $3,846,734 in external
10 rate case expenses and $4,791,370 in internal rate case expenses. The
11 Company requests recovery of these external and internal rate case
12 expenses.
13
14 Q. HAVE YOU REVIEWED THE INTERNAL RATE CASE EXPENSES
15 PRESENTED IN EXHIBIT MPC-SD-3 TO DETERMINE WHETHER SUCH
16 EXPENSES ARE REASONABLE AND NECESSARY?
17 A. Yes.
18
19 Q. HOW DID YOU DETERMINE WHETHER THE INCURRED INTERNAL
20 RATE CASE EXPENSES PRESENTED IN EXHIBIT MPC-SD-3 WERE
21 REASONABLE AND NECESSARY?
22 A. Internal rate case expenses are all captured in Project Code
23 F5PPETX011. The project code is used only for time and expense related
Entergy Texas, Inc. Page4 of6
Supplemental Direct Testimony of Michael P. Considine
Docket No. 40295
1 to the Docket No. 39896 rate case, and all costs incurred by ESI in this
2 project code are directly billed to ETI. The process through which costs
3 are billed to project codes were described in Company witness Stephanie
4 8. Tumminello's direct testimony from Docket No. 39896. In addition, the
5 Company's affiliate class witnesses from Docket No. 39896, including
6 those who address the ETI direct charges, explained how the budgeting
7 and cost control processes work within their business units. For example,
8 timesheet and expense reports are reviewed by supervisors to ensure
9 accuracy. Also, in Docket No. 39896, Company witness Kevin G. Gardner
1O supported the reasonableness and necessity of the compensation and
11 benefits paid to ESI employees.
12 In Docket No. 39896, Company witnesses presented direct
13 testimony regarding the various classes of affiliate costs that ETI received
14 from ES!, and my Exhibit MPC-SD-4 shows the ESI rate case charges to
15 ETI by affiliate class. The processes and practices described in the
16 Company's Docket No. 39896 direct testimony regarding billing,
17 budgeting, cost control, compensation, and benefits remain in effect today.
18 These processes and practices help to ensure that the requested internal
19 rate case expenses are necessary and reasonable, represent the actual
20 costs of the services, do not include prohibited expenses, do not include
21 charges for duplicative services or expenses, and are no higher than the
22 prices charged to other affiliates, or to non-affiliates, for the same or
23 similar classes of item.
Entergy Texas, Inc. Page 5 of6
Supplemental Direct Testimony of Michael P. Considine
Docket No. 40295
1 Further, a review of the Company's requested rate case expenses
2 is undertaken to determine that only appropriate charges are included in
3 the rate case expense request, and inappropriate charges, such as
4 charges for luxury items or excessive meals charges, are excluded.
5
6 Q. WHAT DID YOU CONCLUDE WITH RESPECT TO THE
7 REASONABLENESS AND NECESSITY OF THE COMPANY'S
8 INCURRED INTERNAL RATE CASE EXPENSES?
9 A. Based on my review and analysis, as described above, the Company's
10 incurred internal rate case expenses are reasonable and necessary.
11
12 IV. RECOVERY OF RATE CASE EXPENSES
13 Q. HOW DOES THE COMPANY PROPOSE TO RECOVER RATE CASE
14 EXPENSES?
15 A. As explained in my direct testimony, the Company proposes that it be
16 permitted to recover all incurred rate case expenses over a three-year
17 period, with a return on the unamortized balance.
18
19 Q. WILL THE COMPANY PROVIDE ADDITIONAL UPDATES REGARDING
20 THE LEVEL OF INCURRED RATE CASE EXPENSES?
21 A. Yes. ET! will provide the next update through September 30, 2012 to Staff
22 RFI 9-1 on or around October 25, 2012.
... ---· ------------
Entergy Texas, Inc. Page 6of6
Supplemental Direct Testimony of Michael P. Considine
Docket No. 40295
1 Q. DOES THIS CONCLUDE YOUR SUPPLEMENTAL DIRECT
2 TESTIMONY?
3 A. Yes.
8
ENTERGY TEXAS, INC. Exhibit MPC..S0-3
RATE CASE EXPENSES PAID AND ACCRUED THROUGH THE MONTH ENDED AUGUST 31, 2012 Docket No. 40295
ETI 6/30/1 i COS DOCKET 39896 RATE CASE EXPENSES Page 1 of 2
AMOUNT
ACCOUNTING
DELO!TTE & TOUCHE LLP Total 915,970
LESS: NON-CONFORMING D&T EXPENSES (2,373)
PRICEWATERHOUSE COOPERS LLP Total 122,168
LESS: NON-CONFORMING PWC EXPENSES (7)
ACCOUNTING TOTAL 1,035,758 •
CONSULTANTS
DOLORES S STOKES DBA D STOKES CONSULTING 17,290
EXPERT POWERHOUSE LLC DBA EXPERGY 172,752
FINANCOINC 125,220
GERALD W TUCKER CPA 116,119
JAY HARTZELL 12,825
MILLER & CHEVALIER CHARTERED 19,443
TOWERS WATSON PENNSYLVANIA INC 2,288
LESS: NON-CONFORMING TWP EXPENSES (22)
CONSULTANTS TOTAL 465,915 *
DUGGINS WREN MANN & ROMERO LLP 2,345,127
LESS: NON-CONFORMING DWMR EXPENSES (66)
LEGAL TOTAL 2,345,061 •
INTERNAL RATE CASES EXPENSES (NON-PAYROLL)
Business Meals/Entertainment 3,852
Cities Bills-Lawton Law Finn 1,117,309
Computer & Office Supplies 758
Court Transcripts 38,466
Depreciation & Amort Expenses 204,136
Employee Mtgs/Functions 7,762
Legal Notices 100,799
Lodging 18,959
Other Employee Expenses 3,423
Other Office & General 5,829
Pagers/Cellular Phones 10
Personal Car Mileage • Local 2,764
Postage and Overnight Delivery 8,699
Printing, Mailing & Shipping 12,601
Safely Training Loader i,843
Service Company Recipient 342,078
Temporary Services 66,943
Travel Transportation 24,126
Utility Bills 2,518
LESS: NON-CONFORMING COMPANY EXPENSES (560)
INTERNAL RATE CASES EXPENSES (NON-PAYROLL) TOTAL i,962,315
ESI PAYRQLL. BENEFITS & TAXES 2,829,056 See next tab and Ex. MPL-SD-4 for Detail
RATE CASE EXPENSES THROUGH S/31112 8,638,105
*Please refer to the Company's response and addenda to Staff 9-1
for detail supporting the Accounting, Consultant, and Legal expenses
addressed above. Amounts for Duggins Wren Mann & Romero, lLP
include fees and expenses from the following consultants:
Commonwealth Consulting; Alliance Consulting; Lewis & Ellis;
Naman, Howell, Smith & Lee; and Vector Advisors.
ENTERGY TEXAS, INC.
RATE CASE PAYROLL FOR ESI EMPLOYES THROUGH AUGUST 31, 2012
ETI 6130111 COS DOCKET 39a96
Exhibit MPC·S0-3
Docket No. 40295
DEPARTMENT WAGES HOURS ACTIVITIES Page 2 of 2
frnr, crp-·AVin, secui- & R.E. op-·· ..... "14'
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
icoueciions. E"siDetai1 •· ....... 14 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
f ... -· .. ------ "''" .. . ....... ·--·-
r.Remittance
...... _ ......-.Processing-Esi
- __ .. ... ... B ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
1Csc Customer Contact Solutns 232 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
[<_;iisto~~J~~dlnyoiffi~1on li"d!i"1: - ... 135 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
!Gsu President & Ceo -·-- - -ff' ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
!!l<>e1_F~s!c;:p?~~i:E~1-...:::--.. :·_·- _ - - ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
·Revenue Requirement & Analyses ·~ __"--· 205,883t -·~ ~ -~~~3~ ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Raie-i:feSign- & 'Acimin}~raiion - - - .• f ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
·-······~~- ·L~ ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
' ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
.......21 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
- .._fa ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
1 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
100 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
.....-.... w211 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
- --'i;:i'Js1 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
a~~~g • . , ........ 11. ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
Wholesale Business ·- 1;4001· . . _ ···-191 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
!Distribution Engiileeriri(iDatal ···- =---.·31;12,.1,..' .· ......·.=.-.. ._424Jl ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
1~~~-~u-~ss~iigp"'af~xbedl:e~!Sis&ts :~-----··----':'.'-"'..... _ ...!!' ___ .. , __ -~ ~60,85~1~·- ~~~- ~717
ASSIST IN RATE CASE PREPARATION& RFI RESPONSES
jHR Compliance 6,81~
122 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
[Y.P_!-iR o~~!i?~s·-~:_
'.HR .. Project Management
~-=:
'
...__
1_:.~~~t-:__ -~-~--~2 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
-- 36,6~~r·- .... j_27... ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
1~_f:!F(Pr~~m_s - =~ --~~ ~--
JHR - Total Rewards Prgms
- "' . . .
...........D.26.Si ..
__
_!..0,3961""'" ..... --~~] ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
.~j ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
lHR :Totai"ReY.rards Ops-- 7941 19r ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
lHR-Busines"ii"Meiilii --·---- ---+- 1,901?1 ·:::-.:- 33J
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
fc'°hiafLegai officer 58,949!. 562j ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
!Legai:-t:iiigation"-T£ - ... "~:-. .e~{ ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
?.c.1_4..4.]. ·=
flega1:F"eR"c"' ......... 2,!56t' - - 17~ ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
:regal ~-GeneraTcounsel ·--+ - 2,744 421
ASSIST IN RATE CASE PREPARATION & Rf! RESPONSES
!Legat- Reg -Corp . . . "ii,024 - ..... 46 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
fCegal - Reg .:-TX-""'"" - ' 139,(issr .. 2;·!60 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
!"uuiify sYStem·Mcommun1CauOOs •A·!"' 452 3 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
fVp -Advocacy"communications ""'""'8~ ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
[Feaera'iRegulaiory Affairs .. - -- .... 6 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
WEB COMMUNICATio"Ns·- ... ... •. - - - -· ""14 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
S°Ystern RegulatoryAffairs(D~) -- -- t--- . 15,663 .....- - "fo9. ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
·'···--- '"' - - ..... ........... - ... •......... ' .... ............ ... ... -···-- j
\~i=!:_.Ma~ageme~~ _ .•.. ... ... _... J. ___1_~!.E_8 _ 164! ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
llntemalAudil 1 2,8921 41! ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
'
r~:::i~::t6~~~$~~:~l~:r~'!f ~--~
lReguiiiT,:Y71ffrSiEnergy Seillmt - - ... - ·- -......
. .,- i~ 2."" -==-~~:i ~~~:~; :~ ~~~ g~~~ :~~:~:~:~~: ::: :~~:g~~~~
05
i57,592 ----""2,47ii) ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
'sPo comlian"Ce&coiilract Admiii~ -- 1·.~~~J-~----=~;~1, ~~~:~~ :~ :~~ :;~~~ ::~:~~~~:g~ ! ~;: ~~;:g~;~~
··- .....
=:J~_,2_?9, -- - _fcj_i ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
3,016 29 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
!§1?..~rati~~:>,£'.'~'.li°ii~~- _: ~--.. . -· -l,000 - "'121
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
1Supply Planning andAnalysis 742 ....... ---- "' 15 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
!'Power SuPply -.... .. ... ··········· ...
j" -- .,\1 'f•?..8~ .. ::=~ Ji,:i_~)l ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
~i ASSIST IN RATE CASE PREPARATION & RFI
.
lVPEnorgy"ivlSiiai;iemanf : 487 RESPONSES
r~:J;~~;t~~~~--=-= = .. . - ---t !~:;~~- ~-- -~ . 1~~1 ~~~:~~ :~ ~~~ ~~~~ :~~:~~;:~~: ::: :~~:g~~~~
...
tt~!r~ ~~'.eipii_i;~-~~r.'!i;:~s .... _ .. + 4- -~- ... =-=-~1
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
lSecurity and Compliance . ... 61l ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
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SOAH Docket No. XXX-XX-XXXX
PUC Docket No. 40295
SOAH DOCKET NO. XXX-XX-XXXX
DOCKET NO. 40295
APPLICATION OF ENTERGY §
TEXAS, INC. FOR RATE CASE §
EXPENSES PERTAINING TO § OF
PUC DOCKET NO. 39896 §
§ ADMINISTRATIVE HEARINGS
SUPPLEMENTAL DIRECT TESTIMONY
OF
MICHAEL P. CONSIDINE
ON BEHALF OF
ENTERGY TEXAS, INC.
OCTOBER 25, 2012
ENTERGY TEXAS, INC.
SUPPLEMENTAL DIRECT TESTIMONY OF
MICHAEL P. CONSIDINE
DOCKET NO. 40295
TABLE OF CONTENTS
I. Witness Introduction 1
II. Purpose of Supplemental Direct Testimony 1
Ill. Update Regarding Internal Rate Case Expenses 2
IV. Recovery of Rate Case Expenses 5
EXHIBITS
Exhibit MPC-SD-5 Summary Rate Case Expense Spreadsheet
Exhibit MPC-SD-6 ES! Rate Case Charges to ETI by Affiliate Class
2
Entergy Texas, Inc. Page 1of5
Supplemental Direct Testimony of Michael P. Considine
Docket No. 40295
1 I. WITNESS INTRODUCTION
2 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
3 A. My name is Michael P. Considine. My business address is 425 West
4 Capitol Avenue, little Rock, Arkansas 72201. I am employed by Entergy
5 Services, Inc. ("ESI"), the service company affiliate of Entergy Texas, Inc.
6 ("ETI" or the "Company") as a Manager in the Regulatory Accounting
7 Department.
8
g Q. ARE YOU THE SAME MICHAEL P. CONSIDINE THAT PREVIOUSLY
10 FILED TESTIMONY IN BOTH DOCKET NO. 39896 AND THIS DOCKET?
11 A. Yes.
12
13 II. PURPOSE OF SUPPLEMENTAL DIRECT TESTIMONY
14 Q. WHAT IS THE PURPOSE OF THIS ADDITIONAL SUPPLEMENTAL
15 DIRECT TESTIMONY?
16 A. This supplemental direct testimony supports and updates the Company's
17 request to recover rate case expenses associated with this proceeding.
18 Specifically, I provide the levels of rate case expenses incurred and paid
19 as of September 30, 2012, related to outside accounting services, outside
20 legal counsel, and outside consultants ("external rate case expenses"). I
21 also provide the levels of rate case expenses incurred and paid as of
22 September 30, 2012, related to ETI direct expenses and ESI payroll,
23 benefits, and taxes ("internal rate case expenses"). in addition, I address
Entergy Texas, Inc. Page 2 of 5
Supplemental Direct Testimony of Michael P. Considine
Docket No. 40295
1 the reasonableness and necessity of the internal rate case expenses paid
2 in September 2012. Company witness Stephen Morris has filed direct and
3 supplemental direct testimony in Docket No. 39896 and supplemental
4 direct testimony in this docket on October 5, 2012 and contemporaneous
5 with the filing of this testimony addressing the reasonableness and
6 necessity of external rate case expenses.
7
8 Ill. UPDATE REGARDING INTERNAL RATE CASE EXPENSES
g Q. SINCE FILING ITS RATE FILING PACKAGE, HAS THE COMPANY
10 PROVIDED ITS INCURRED RATE CASE EXPENSES?
11 A Yes. On February 21, 2012, in Docket No. 39896, the Company filed its
12 initial responses to Staff's 9th Requests for Information ("RFls"), including
13 schedules of internal and external rate case expenses as of December 31,
14 2011. On March 13, 2012, in Docket No. 39896, the Company filed my
15 first supplemental direct testimony with attached exhibits containing
16 schedules of internal and external rate case expenses as of January 31,
17 2012. On March 16, in Docket No. 39896, the Company provided updates
18 to its responses to Staff's 9th RFls. On October 5, in this docket, the
19 Company filed my second supplemental direct testimony with attached
20 exhibits containing schedules of internal and external rate case expenses
21 as of August 31, 2012, as well as further updates to its responses to
22 Staff's 9th RFls.
------- -------------
Entergy Texas, Inc. Page 3 of 5
Supplemental Direct Testimony of Michael P. Considine
Docket No. 40295
1 Q. DO YOU PROVIDE AN UPDATE REGARDING THE LEVELS OF
2 INCURRED RATE CASE EXPENSES IN THIS PIECE OF
3 SUPPLEMENTAL DIRECT TESTIMONY?
4 A Yes. The summary rate case expense spreadsheet, included as part of
5 the Company's third addendum to its response to Staff RF! 9-1 and filed
6 contemporaneously herewith, is attached as Exhibit MPC-SD-5. This
7 exhibit presents external rate case expenses by vendor and internal rate
8 case expenses by ETI direct expense category and ES! department. As
9 shown in Exhibit MPC-SD-5, as of September 30, 2012, the Company had
10 incurred $3,908,214 in external rate case expenses and $4,844,362 in
11 internal rate case expenses. The Company requests recovery of these
12 rate case expenses.
13
14 Q. HAVE YOU REVIEWED THE INTERNAL RATE CASE EXPENSES
15 PRESENTED IN EXHIBIT MPC-SD-5 TO DETERMINE WHETHER SUCH
16 EXPENSES ARE REASONABLE AND NECESSARY?
17 A Yes.
18
19 Q. HOW DID YOU DETERMINE WHETHER THE INCURRED INTERNAL
20 RATE CASE EXPENSES PRESENTED IN EXHIBIT MPC-S0-5 WERE
21 REASONABLE AND NECESSARY?
22 A Internal rate case expenses are all captured in Project Code
23 F5PPETX011. The project code is used only for time and expense related
Entergy Texas, Inc. Page4 of 5
Supplemental Direct Testimony of Michael P. Considine
Docket No. 40295
1 to the Docket No. 39896 rate case, and all costs incurred by ESI in this
2 project code are directly billed to ET!. The process through which costs
3 are billed to project codes were described in Company witness Stephanie
4 B. Tumminello's direct testimony from Docket No. 39896. In addition, the
5 Company's affiliate class witnesses from Docket No. 39896, including
6 those who address the ETI direct charges, explained how the budgeting
7 and cost control processes work within their business units. For example,
8 timesheet and expense reports are reviewed by supervisors to ensure
9 accuracy. Also, in Docket No. 39896, Company witness Kevin G. Gardner
10 supported the reasonableness and necessity of the compensation and
11 benefits paid to ESI employees.
12 In Docket No. 39896, Company witnesses presented direct
13 testimony regarding the various classes of affiliate costs that ETI received
14 from ES!, and my Exhibit MPC-SD-6, attached hereto, shows the ESI rate
15 case charges to ETI by affiliate class. The processes and practices
16 described in the Company's Docket No. 39896 direct testimony regarding
17 billing, budgeting, cost control, compensation, and benefits remain in
18 effect today. These processes and practices help to ensure that the
19 requested internal rate case expenses are necessary and reasonable,
20 represent the actual costs of the services, do not include prohibited
21 expenses, do not include charges for duplicative services or expenses,
22 and are no higher than the prices charged to other affiliates, or to non-
23 affiliates, for the same or similar classes of item.
Entergy Texas, Inc. Page 5 of 5
Supplemental Direct Testimony of Michael P. Considine
Docket No. 40295
1 Further, a review of the Company's requested rate case expenses
2 is undertaken to determine that only appropriate charges are included in
3 the rate case expense request, and inappropriate charges, such as
4 charges for luxury items or excessive meals charges, are excluded.
5
6 Q. WHAT DID YOU CONCLUDE WITH RESPECT TO THE
7 REASONABLENESS AND NECESSITY OF THE COMPANY'S
8 INCURRED INTERNAL RATE CASE EXPENSES?
9 A Based on my review and analysis, as described above, the Company's
10 incurred internal rate case expenses are reasonable and necessary.
11
12 IV. RECOVERY OF RATE CASE EXPENSES
13 Q. HOW DOES THE COMPANY PROPOSE TO RECOVER RATE CASE
14 EXPENSES?
15 A As explained in my direct testimony, the Company proposes that it be
16 permitted to recover all incurred rate case expenses over a three-year
17 period, with a return on the unamortized balance.
18
19 Q. DOES THIS CONCLUDE YOUR SUPPLEMENTAL DIRECT
20 TESTIMONY?
21 A Yes.
ENTERGY TEXAS, !NC. exhibit MPC-S0-5
Docket No. 40295
RATE CASE EXPENSES PAID AND ACCRUED THROUGH THE MONTH ENDED SEPTEMBER 30, 2012
Page 1 of2
ETI 6/30/11 COS DOCKET 39896 RATE CASE EXPENSES
AMOUNT
ACCOUNTING
DELOITTE & TOUCHE LLP Total 915,970
LESS NON-CONFORMING D&T EXPENSES (2,373)
PRICEWATERHOUSE COOPERS LLP Total 122,168
LESS NON-CONFORMING PWC EXPENSES (7}
ACCOUNTING TOTAL 1,035,756 •
!,';ONSULTft,NI~
DOLORES S STOKES DBA D STOKES CONSULTING 17,290
EXPERT POWERHOUSE LLC DBA EXPERGY 172,752
FINANCO INC 125,220
GERALD W TUCKER CPA 116,119
JAY HARTZELL 12,625
MILLER & CHEVALIER CHARTERED 19,443
TOWERS WATSON PENNSYLVANIA INC 2,288
LESS· NON-CONFORMING TWP EXPENSES (22)
CONSULTANTS TOTAL 465,915 •
DUGGINS WREN MANN & ROMERO LLP 2,406,607
LESS NON-CONFORMING DWMR EXPENSES (66}
LEGAL TOTAL 2,406,541 •
INTERNAL BATE CASES EXPENSES (NQN-PAYRQU,}
Business Meals/Entertainment 3,852
Cities Bills-Lawton Law Firm 1, 117,309
Computer & Office Supplies 758
Court Transcripts 38,466
Depreciation & Amort Expenses 207,683
Employee Mtgs/Functions 7,762
Legal Notices 100,799
Lodging 18,959
Other Employee Expenses 3,423
Other Office & General 5,829
Pagers/Cellular Phones 10
Personal Car Mileage • Local 2,764
Postage and Overnight Delivery 8,699
Pnnting, Mailing & Shipping 12,601
SerY1ce Company Recipient 346,MO
Temporary Services 66,943
Travel Transportation 24, 126
Utility Bills 2,518
LESS NON-CONFORMING COMPANY EXPENSES (560)
INTERNAL RATE CASES EXPENSES (NON-PAYROLL) TOTAL 1,968,581
ES! PAYROLL. BENEFITS & TAXES 2,875,781 See next tab and Ex. MPL-SD-6 for Detail
BATE CASE !iXPEN§ES THRO!,IGH 9130112 8,752,576
•Please refer to the Company's response and addenda to Staff 9-1
· for detail supporting the Accounting, Consultant, and Legal expenses
addressed above. Amounts for Duggins Wren Mann & Romero, LLP
include fees and expenses from the following consultants:
Commonwealth Consulting; Alliance Consulting; Lewis & Ellis;
Naman, Howell, Smith & Lee; and Vector Advisors.
ENTERGY TEXAS, INC.
RATE CASE PAYROLL FOR ES! EMPLOYES THROUGH SEPTEMBER 30, 2012
ET! 6/30/11 COS DOCKET 39896
Exhibit MPC-S0-5
Docket No. 40295
DEPARTMENT WAGES HOURS ACTIVIHES Page 2 of 2
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFl RESPONSES
ASSIST IN RATE CASE PREPARATION & RFl RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
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ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
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ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
ASSIST JN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATJON & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST !N RATE CASE PREPARATION & Rfl RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
ASSIST lN RATE CASE PREPARATION & RF! RESPONSES
ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & Rf! RESPONSES
ASSIST IN RATE CASE PREPARATION & Rf! RESPONSES
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ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
(133) ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
·-==~~~
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···-···--,,.3..~.8-J q
TOTAL ES! WAGES 2,102,309 32,592
Affiliate Rate Case Expenses Exhibit MPC-SD-6
Payroll, Benefits, Payroll Taxes, and Incentive Costs by Class Docket No. 40295
Through Sept 30, 2012 Page 1of1
-+-------·-·-· · · - - - - - - ·..··
* ET! em lo ees with affiliate costs
\0
SOAH Docket No. XXX-XX-XXXX
PUC Docket No. 40295
ETI Exhibit No. 7
SOAH DOCKET NO. XXX-XX-XXXX
PUCT DOCKET NO. 40295
APPLICATION OF ENTERGY § BEFORE THE STATE OFFICE
TEXAS, INC. FOR RATE CASE § OF
EXPENSES PERTAINING TO § ADMINISTRATIVE HEARINGS
PUC DOCKET NO. 39896 §
RE BUTTAL TESTIMONY
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MICHAEL P. CONSIDINE
ON BEHALF OF
ENTERGY TEXAS, INC.
NOVEMBER 15, 2012
ENTERGY TEXAS, INC.
REBUTTAL TESTIMONY OF MICHAEL P. CONSIDINE
PUCT DOCKET NO. 40295
TABLE OF CONTENTS
Page
I. WITNESS INTRODUCTION 1
II. PURPOSE OF REBUTTAL TESTIMONY 1
m. REBUTTAL ISSUES 2
A. Allocation of Rate Case Expenses 2
B. Return 011 the Unamortized Balance 3
C. Frequency of Rate Cases 4
D. Calpine-Carville PPA 5
E. Costs Billed by Company Consultant Gerald Tucker 7
F. Depreciation 9
EXHIBITS
MPC-R-1: Excerpts from ETl's Response to Staff 9-1, Addendum 3
Entergy Texas, Inc. Page 1of11
Rebuttal Testimony of Michael P. Considine
PUCT Docket No. 40295
1 I. WITNESS INTRODUCTION
2 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
3 A. My name is Michael P. Considine. My business address is 425 West
4 Capitol Avenue, little Rock, Arkansas 72201. I am employed by Entergy
5 Services, Inc. ("ESI"), the service company affiliate of Entergy Texas, Inc.
6 ("ETI" or the "Company") as a Manager in the Regulatory Accounting
7 Department I was formerly a Senior Staff Accountant in the Regulatory
8 Accounting Department during Docket No. 39896. As a Manager in
9 Regulatory Accounting, I am responsible for managing the work of those
1O gathering, preparing, and analyzing accounting data for the Operating
11 Companies for use in preparing rate filings. This includes coordination of
12 accounting-related schedules and testimony filed with the various
13 regulatory commissions that have jurisdiction over the Operating
14 Companies.
15
16 Q. ARE YOU THE SAME MICHAEL P. CONSIDINE THAT PREVIOUSLY
17 FILED TESTIMONY IN BOTH DOCKET NO. 39896 AND THIS DOCKET?
18 A. Yes.
19
20 II. PURPOSE OF REBUTTAL TESTIMONY
21 Q. WHAT IS THE PURPOSE OF THIS REBUTTAL TESTIMONY?
22 A. The purpose of my rebuttal testimony is to respond to various issues
23 raised in Staff and Intervenor Direct Testimonies and Recommendations
Entergy Texas, Inc. Page 2ofi1
Rebuttal Testimony of Michael P. Considine
PUCT Docket No. 40295
1 related to the Company's request to recover Docket No. 39896 rate case
2 expenses associated with various aspects including issues related to the
3 Company's request to recover internal rate case expenses. The rebuttal
4 testimony of witness Stephen F. Morris addresses certain aspects of those
5 same filings including issues related to outside legal counsel and outside
6 accounting and consulting firms ("external rate case expenses").
7
8 !IL REBUTTAL ISSUES
9 A. Allocation of Rate Case Exgenses
10
11 Q. PLEASE ADDRESS STAFF'S APPROACH TO THE ALLOCATION OF
12 RATE CASE EXPENSES.
13 A. Staff Witness Brian Murphy recommends a class revenue requirement
14 allocator based upon each class' Commission-approved revenue
1
15 requirement. Mr. Murphy recommends that ETl's Schedule RCE-2 rates
16 be set in the compliance phase of this proceeding by multiplying the
17 approved total amount by Staffs recommended class allocator and
18 dividing the resulting class share both by ETl's proposed three-year
19 amortization period and also by ETl's proposed class billing determim.mts. 2
20 Mr. Murphy also recommends that the Company be required to track
21 collection on Rider RCE and terminate billing in the billing month in which
22 the approved amount has been billed.
1
Murphy Direct at 4.
2
Id. at 5.
 Entergy Texas, Inc. Page 3of11
Rebuttal Testimony of Michael P. Considine
PUCT Docket No. 40295
1 Q. DOES ETI OBJECT TO STAFF'S ALLOCATION BASIS?
2 A. No, ETI does not object to Staff's approach on allocation.
3
4 Q. DOES THE COMPANY OBJECT TO TRACKING AND TERMINATING
5 THE RIDER ONCE THE APPROVED AMOUNT HAS BEEN BILLED?
6 A. The Company agrees with this approach so long as the final order
7 includes language following Commission precedent allowing the Company
8 to seek recovery of any additional rate case expenses accrued after
9 September 30, 2012 in its subsequent rate case. 3
10
11 B. Retum on the Unamortized Balance
12 Q. PLEASE DESCRIBE STAFF'S RECOMMENDATION FOR THE RETURN
13 ON THE UNAMORTIZED BALANCE.
14 A. Staff's Recommendations suggest that ET! not be allowed to recover any
15 return on the unamortized balance as the Company had requested for the
16 three-year period over which ETI would be recovering the approved rate
17 case expenses.
18
19 Q. WHAT IS YOUR VIEW ON THE RETURN ON THE UNAMORTIZED
20 BALANCE?
3
Requests for Rate Case Expenses Severed From Docket No. 38339 (Application of CenterPoint
Energy Houston Electric, LLC for Authority to Change Rates), Docket No. 39127, Order, Finding
of Fact 26 (Jun. 6, 2011).
Entergy Texas, Inc. Page 4of11
Rebuttal Testimony of Michael P. Considine
PUCT Docket No. 40295
1 A The return is a necessary component of a cost that is amortized over a
2 period of time. It represents the time value of money and the cost of the
3 Company's lost opportunity to deploy those funds elsewhere. The
4 Company's proposal reflects a reasonable balancing of interests on this
5 issue as the Company is only proposing a return over the three-year
6 recovery period and does not propose to recover the lost opportunity costs
7 on the rate case expenses from the time they were incurred. If the
8 Company is not permitted to recover a return on the unamortized portion
9 of its approved rate case expenses, it will, in effect, incur a disal!owance
10 relative to the amount of rate case expenses approved by the
11 Commission. Therefore, I disagree with Staff's recommendation on this
12 point; the Company should be allowed to recover its return on the
13 unamortized balance.
14
15 C. Frequency of Rate Cases
16 Q. PLEASE SUMMARIZE THE POLICY ISSUES RAISED BY PARTIES
17 REGARDING THE FREQUENCY OF RATE CASES.
18 A. Both the State Agencies in their Recommendations, and OPUC witness
19 Nathan Benedict point to the frequency of rate cases as a reason the
20 Commission should disallow otherwise reasonable rate case expenses.
21 Mr. Benedict asserts that the Company has filed three base rate cases in
22 a little more than four years and that this frequency places a burden on
23 ratepayers. The State Agencies claim that frequent requests for rate relief
Entergy Texas, Inc. Page 5of11
Rebuttal Testimony of Michael P. Considine
PUCT Docket No. 40295
1 for electric utilities are shareholder-driven and because of that, half of rate
2 case expenses should be paid for by the shareholders.
3
4 Q. DO YOU AGREE WITH THE ARGUMENTS MADE REGARDING THE
5 FREQUENCY OF BASE RATE CASES?
6 A. No. Rate cases are cost-driven. The Company is permitted to recover its
7 reasonable and necessary costs and to have the opportunity to earn a
8 reasonable retum cm invested capita!. Each of ETl's recent base rate
g cases has resulted in a rate increase for the Company. Ironically, the
10 Company has proposed on multiple occasions to establish rate riders to
11 address the Company's rising costs that would substantially reduce the
12 likelihood of the Company filing rate cases as frequently as it has in the
13 last few years. These proposals have been opposed by the same parties
14 who here complain about the frequency of rate cases. Without the ability
15 to recover the increasing level of reasonable expenses through such
16 riders, a utility is left with no recourse but to file a rate case.
17
18 D. Calpine-Carville PPA
19 Q. PLEASE DESCRIBE OPUC'S RECOMMENDATIONS REGARDING THE
20 CALPINE-CARVILLE PURCHASED POWER AGREEMENT.
21 A. In its Recommendation and Request for Hearing, OPUC proposes that the
22 Commission disallow the recovery of rate case expenses relating to the
23 regulatory approval of this purchased power agreement ("PPA"). OPUC
Entergy Texas, Inc. Page6of11
Rebuttal Testimony of Michael P. Considine
PUCT Docket No. 40295
1 states that the Company has already been granted recovery of costs
2 associated with the regulatory approval process for the Calpine-Carville
3 PPA and the Company sought and obtained that regulatory approval in
4 Docket No. 39896. Thus, it claims that if the Company were to also
5 recover those costs as part of its rate case expenses in this docket, it
6 would constitute double recovery. Specifically, OPUC mentioned a
7 disallowance of the portion of the expenses related to the testimonies of
8 Company witness Robert Cooper and the billable time of Company
9 attorney Dick Westerburg.
10
11 Q. WHAT IS YOUR RESPONSE TO THE DISALLOWANCES SUGGESTED
12 BY OPUC REGARDING THE CALPINE~CARVILLE PPA?
13 A. OPUC fails to recognize an important distinction between the amounts at
14 issue. An individual may have charged time to Project Code
15 F3PPWET308 (that is, the internal project code for the Calpine PPA
16 development costs) as the Calpine PPA was being developed, including
17 time spent determining how regulatory approval of the PPA might
18 generally be obtained and designing the PPA in a manner that would
19 facilitate such approval. These costs would have occurred during the test
20 year and were included for recovery in Docket No. 39896. However, an
21 individual may have also charged time to Project Code F5PPETX011 (that
22 is, the internal project code for the rate case filed by ETI in Docket No.
23 39896) as they developed testimony specifically for Docket No. 39896 or
Entergy Texas, Inc. Page 7of11
Rebuttal Testimony of Michael P. Considine
PUCT Docket No. 40295
1 responded to RFls related to the Calpine PPA during the course of the
2 rate case. These costs would have occurred after the test year. Recovery
3 of these latter costs was severed from Docket No. 39896 and is now being
4 requested in this docket Costs recorded to Project Code F5PPETX011
5 are the only costs the Company is proposing to recover in this instant
6 docket. Therefore, no double recovery exists. 4
7
8 E. Costs Billed by Company Consultant Gerald Tucker
9 Q. PLEASE BRIEFLY SUMMARIZE STATE AGENCIES' RECOMMENDED
10 DISALLOWANCE FOR COSTS BILLED BY COMPANY CONSULTANT
11 GERALD TUCKER.
12 A State Agencies' recommended $116, 119 disallowance is based upon
13 claims that services performed by Mr. Tucker are duplicative and go
14 beyond reviewing affiliate costs.
15
16 Q. DO YOU AGREE WITH STATE AGENCIES' CHARACTERIZATION OF
17 COSTS BILLED BY MR. TUCKER?
18 A No. Over the past two decades, the PUCT has at times disallowed large
19 percentages of utilities' affiliate expenses, including those of Entergy Gulf
20 States, Inc. ("EGSI"). One of the concerns raised in the past by the ALJs
21 and the Commission has been an inability to understand the information
4
Moreover, on pages 43-44 of her direct testimony in Docket No. 39896, Company witness
Tumminello provided a detailed description of the controls and review process in affiliate billing
that ensure actual costs are reflected, and the Commission disallowed no costs due to duplicative
charges.
Entergy Texas, Inc. Page 8of11
Rebuttal Testimony of Michael P. Considine
PUCT Docket No. 40295
1 presented by the utilities. As a result, the Company needs to ensure that
2 it has experienced personnel to assist in the effective preparation and
3 presentation of its rate cases. Mr. Tucker brings a level of expertise and
4 perspective to ensure this effective preparation and presentation. He is an
5 accountant and thus brings a perspective that the Company's outside
6 counsel do not bring to a rate case.
7 Mr. Tucker has been involved in all ET! (formerly EGSI) rate cases
8 since Docket No. 16705 in 1997 as well as numerous rate cases filed by
9 other utilities in Texas. This extensive experience with ETI and its
10 previous dockets is exactly the reason Mr. Tucker was asked to assist with
11 the review of discovery as well. This review included completeness of the
12 response, consistency with responses in the current and previous cases,
13 and clarity of the response. Mr. Tucker also assisted with preparation for
14 depositions of both Company and intervenor witnesses along with the
15 preparation of Company testimony and rate filing package schedules.
16 With Mr. Tucker's assistance, the Company is better able to provide the
17 information in a clear and accurate manner that allows customer
18 representatives to analyze the Company's costs and requested rates.
19 Likewise, Mr. Tucker's assistance has been necessary to ensure, to the
20 extent possible, that ETl's affiliate charges, in particular, are not
21 susceptible to the substantial affiliate cost disallowance that was ordered
/0
Entergy Texas, Inc. Page 9of11
Rebuttal Testimony of Michae! P. Considine
PUCT Docket No. 40295
1 in Docket No. 16705.5 There are very few individuals who have as much
2 rate case experience with the Company as does Mr. Tucker, and there are
3 no employees at the Company or ESI who have Mr. Tucker's experience
4 with and knowledge of how other Texas utilities present their affiliate costs
5 and other rate case matters. 6
6
7 F. Depreciation
8 Q. PLEASE DESCRIBE THE STATE AGENCIES' RECOMMENDED
9 DISALLOWANCES FOR DEPRECIATION.
10 A. The State Agencies' reason for disallowing $207 ,683 is that there is no
11 evidence to prove the reasonableness and necessity of this charge as a
12 cost of participation in the base rate case. The State Agencies claim that
13 the "attached detail" referenced in the summary spreadsheet was not
14 attached.
15
16 a. HOW DO YOU RESPOND TO THE STATE AGENCIES' CLAIMS?
17 A. The State Agencies are wrong. The detail State Agencies claims is
18 lacking was in fact provided in the very RFI response State Agencies cites
19 as deficient, ETl's response to Staff 9-1, Addendum 3. Accordingly, I have
20 attached as Exhibit MPC-R-1 those portions of the Company's voluminous
5
In Docket No. 16705, all of Entergy Services, lnc.'s affiliate charges to EGSI were disallowed.
6
A copy of Mr. Tucker's resume is attached to the rebuttal testimony of Stephen F. Morris as
Exhibit SFM-R-2.
{{
Entergy Texas, Inc. Page 10of11
Rebuttal Testimony of Michael P. Considine
PUCT Docket No. 40295
1 response to Staff 9-1, Addendum 3 that contain the detail relevant to State
2 Agencies' allegation.
3 Page 1 of Exhibit MPC-R-1 is the summary spreadsheet referenced
4 by State Agencies containing the total of $207,683 for "Depreciation and
5 Amort Expense." Page 2, the second tab of the same spreadsheet,
6 provides additional information regarding the labor costs that drive the
7 depreciation and amortization expense at issue, including the segregation
8 of such labor costs by department The remaining pages of Exhibit MPC-
9 R-1 are a spreadsheet entitled "Roadmap to Internal Rate Case
10 Expenses," which breaks down each of the totals comprising the "Internal
11 Rate Case Expenses (Non-Payroll)" category addressed on the summary
12 spreadsheet on Page 1, including the depreciation and amortization
13 expense about which State Agencies complains. 7 Specifically, on Page 8
14 of Exhibit MPC-R-1, this roadmap spreadsheet breaks down the
15 depreciation and amortization total by project code, year, month, resource
16 code, resource description, monthly amount, and journal ID number.
17 Thus, contrary to State Agencies' claim, the Company provided a
18 "roadmap" of detail in support of the expense at issue.
7
ETl's Response to Staff RFI 9-1. Addendum 3 is cumulative and includes the original response
to Staff RFI 9-1, Addendum 1, Addendum 2, and Addendum 3. The roadmap spreadsheet was
first included in Addendum 1 and was then entitled "Guide to Internal Rate Case Expense
Invoices." The same spreadsheet was updated in Addendum 2 and retitled "Roadmap to lntemc:d
Rate Case Expenses" to more accurately reflect its purpose and contents. Again, every
document and piece of detail provided by the Company in response to Staff RFi 9-1 was
cumulatively included in Addendum 3, which State Agencies cites as lacking sufficient detail,
including the original and updated version of the roadmap spreadsheet
Entergy Texas, Inc. Page 11of11
Rebuttal Testimony of Michael P. Considine
PUCT Docket No. 40295
1 Moreover, these costs are a reasonable and necessary part of
2 providing services. The use of assets required to support employee
3 service functions necessarily results in depreciation and amortization cost.
4 ESl's depreciation expense is thus loaded to all project codes which incur
5 ESI labor charges. The rate case project code here should likewise be
6 charged its share of depreciation expense.
7 Accordingly, State Agencies' proposed disallowance should be
8 rejected.
g
10 Q. DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY?
11 A. Yes.
Exhibit MPC-R-1
Docket No. 40295
Page 1 of 14
ENTERGY TEXAS, lNC.
RATE CASE EXPENSES PAID AND ACCRUED THROUGH THE MONTH ENDED SEPTEMBER. 30, 2012
ET! 6/30/11 COS DOCKET 39896 RATE CASE EXPENSES STAFF DATA REQUEST9-1 ADDENDUM 3
AMOUNT
• ACCOUNTING
DELOlTIE & TOUCHE LLP Total 915,970 SEE ATTACHED DETAIL
LESS: NON-CONFORMING D&T EXPENSES (2.373)
PRlCEWATERHOUSE COOPERS Ll.P Total 122,168 SEE ATTACHED DETAIL
LESS: NON·CONFORM!NG PWC EXPENSES (7)
ACCOUNTING TOTAL 1,035,758
CONSUL TANT$
DOLORES S STOKES DBA D STOKES CONSUi.TiNG 17,290 SEE ATTACHED DETAIL
EXPERT POWERHOUSE LLC OBA EXPERGY 172,752 SEE ATTACHED DETAIL
FINANCOlNC 125,220 SEE ATTACHED DETAIL
GERALD W TUCKER CPA 116,119 SEE ATTACHED DETAIL
JAY HARTZELL 12,825 SEE ATTACHED DETAIL
MILLER & CHEVALIER CHARTERED 19.443 SEE ATTACHED DETAIL
TOWERS WATSON PENNSYLVANIA INC 2,288 SEE ATTACHED DETAIL
LESS; NON·CONFORMlNG TWP EXPENSES {22)
CONSULTANTS TOTAL 465,915
DUGGINS WREN MANN & ROMERO LLP 2,406,607 SEE ATTACHED DETAIL
LESS: NON-CONFORMING DWMR EXPENSES (66)
l.EGAL TOTAL 2,406,541
l~TERNAL RATE CASES EXPENSES !NON-PAYROJ.JJ.
Business Meals/Entertainment 3,852 SEE ATTACHED DETAIL
Cities BiTis·l.awton Law Firm 1, 117,300 SEE ATTACHED DETAIL
Computer & Office Supplies WJ SEE ATTACHED DETAIL
Court Transcripts 38,466 SEE ATTACHED DETAIL
Depreciation & Amort Expenses 207,683 SEE ATTACHED DETAIL
Employ$ Mtgs/Functfons 7,762 SEE ATTACHED DETAIL
Legal Notices 100,799 SEE ATTACHED DETAIL
Lodging 16,959 SEE ATIACHED DETAIL
Other Employee Expenses 3,423 SEE ATTACHED DETAIL
Other Office & General 5,1329 SEE ATTACHED DETAlL
Pagers/Cellular PhOnes 10 SEE ATTACHED DETAIL
Personal Car M~eage • Local 2,764 SEE ATTACHED DETAIL
Postage and Overnight Delivery 13,699 SEE ATTACHED DETAIL
Printing, Mailing & Shipping 12,601 SEE ATTACHED DETAIL
Sefllice Company Recipient 346,640 SEE ATTACHED DETAIL
Temporary Services 66,943 SEE ATTACHED DETAIL
Travel Transportation 24,126 SEE ATTACHED DETAIL
U!IU!y81ns 2,51!l SEE ATTACHED DETAll.
LESS: NON-CONFORMING COMPANY EXPENSES (560)
INTERNAL RATE CASES EXPENSES (NON-PAYROLL) TOTAL 1,968,581
ES! PAYROLL, BENEFIT§ & TAXES 2,875,781 SEE ATTACHED DETAIL
f'AIE CA$E EXPENSES .I!jSQUGH 913QL12 a,752,576
-----··············---
Exhibit MPC-R-1
Docket No. 40295
Page 2of14
ENTERGY TEXAS. INC.
RATE CASE PAYROLL FOR ESI EMPLOYEES THROUGH SEPTEMBER 30, :2012
Ell 6130/11 COS DOCKET 39896 STAFF DATA REQUEST 9·1 ADDENDUM:;
DEPARTl/lEMT WAGES HOURS ACTIVITIES
14 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
----,,1~4 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN AATE CASE PREPAAA110N & RFI RESPONSES
---=::! ASSIST IN RATE CASE PREPAAATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
""""""'=="""":=---------+--*.:::+-----::"1 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
i,,--__,,...:.....,,...--,,.,,,...,.-~------+-....,,..,--..=-1---~..,.i ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
-----1---,.,:.;;~,i......--;.:.;.:;.;: ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
4
----+--~:.;;;;;+.--...:;::;;,;;,i ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE !'REPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE C~E PREPARATION & Rl'l RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
--~.;.t ASSIST IN RATE:: CASE PREPARATION & RFl RESPONSES
ASSIST IN RATE CASE PREPARATION & RF1 RESPONSES
ASSIST tN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
· - - - - - 1 · - - r i r . t - - - " ' " " " d ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
ASSIST IN RAT!:: CASE PREPARATION & RFI RESPONSES
--ru::,;e::l3 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
177 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
..;...;.;.;...;.._ _ _ _ _-+--,,;.:.~.:,:;+-.-......;,35d5 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
73 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
--~ ASSIST IN RATE CASE PREPARATION & Rf'I RESPONSES
---+---..,.,~.,+---~33=5,.i ASSIST IN RATE CASE PRE!'AAATION & RF! RESPONSES
339 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
-------=t---"""14 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
1,721 22 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
;;.:.;:.:..:::..:=;;;.:..----+---1..:8.:.:.,8::;59;.!.....---29::::.i5 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
17,0BS 215 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
h--"::""-:--....,,..--------1---..-,1""4,""71'"'9+---~245 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
5,966 45 ASSIST IN RATE CASE PREPARATION & Rl'l RESPONSES
--T3Jlj(i-·--4.,.,1""4 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
2,758 18 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
"""'+""""'_,,_.,..........;...;...._....::;..;_.___+--6::.-'0,,,,S5:-::7;.......--,..,r1"'17 ASSIST IN RATE CASE PREPAAATION & Rl'I RESPONSES
6,810 122 ASSIST IN RATE CASE PREPAAATION & RFI R!:Sf'ONSES
f=~~==::-----------+--71,"'39o.;3d-·---,2~2 ASSIST IN AATE CASE !'REPARATION & RFl RESPONSES
36,549 427 ASSIST IN RATE CASE !'REPARATION & Rl'I RESPONSES
------+---:1"'0"',3""915::+----5""19 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
;;,;;_-------l--...:9:,;,2;x6~8---;.;i ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
794 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
'--------!f---,-::-:::-::1-- ASSIST IN RATE CASE PREPARATION & Rl'I RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN AATE CASE PREPARATION & RFI RESPONSES
ir:".'::::r?Ei;p;------------1-----;;-;;m----:o.J ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
---,,,,; ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
ASSIST IN RATE CASE PREPARATION & Ri'l RESPONSES
:::------+---~:I--_-_-_-_ ...__-i;l-::i ASSIST IN AATE CASE PREPARATION & RFI RESPONSES
8 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
;;;._----+---=+---....;;i8 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
14 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
-----·r---....,,.,,'::-::;,;t---~.,.,e""°'s ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
184 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
--......,.41.,.i ASSIST IN RATE CASE PREPARATION & Rl'I RESPONSES
129 ASSIST IN RATE CASE PREPAAA110N & RFI RESPONSES
:::-r-'-------1f---:=':=I--------..,,-"'1·9°'" ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
167,308 fii.22 ASSIST IN RATE CASE PREPARATION & RA RESPONSES
1,&5& 49 ASSIST IN RATE CASE PREPARATION&RFI RESPONSES
----asli 7 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
::::======:::1:::::::::=1~3~,2:.-'sgcl----_-_-_-...;.10d7 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
3,016 29 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
-----+-.--;.1!;,,0.;,,90;.i_ _ _...;1;.;.i2 ASSIST IN RATE CASE !'REPARATION & FIFI RESPONSES
742 15 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
-(11,584) (133) ASSIST IN RATE CASE PREPARATION & RFl RESPONSES
-----+----'.........,..43,,;7;i----'-~4 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
--·---f--_,1,2::.c.2::-:5:-:::6;......._ _1.,,,o.:lo ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
46,512 4!17 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
1----4.,-,2"'7""71----~4~44 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES
6,820 $1 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES
------+--""2"'s"".s""asi:i----...39"--<9 ASSIST IN RATE CASI:. PR!:.PARATiON & RFI RESPONSES
TOTAL !:.SI WAGES 2,102,309 32,592
Roadmap to internal Rate Case Expenses - Tab 1
T'i!>E oVe~r' Reikl5 1477004_21
M 2011 11 124398 GUIDANT GROUP INC TEMPORARY SERVICES I 905.34 AP10480635 33801639 09752952 R273643-0·1-66165.!$6
M 2011 11 124398 GUIDANT GROUP INC TEMPORARY SERVICES 136.99 AP104!!0il35 331301657 0975283& R295477..0-1·66165-84
M 2011 11 124398 GUIDANT GROUP !NC TEMPORARY SERVICES 704.34 AP104!lOB35 33801671:! 09752860 R305710-0-1-6615M05
~ M
M
2011
2011
11124398
12 124398
GUIDANT GROUP INC
GUIDANT GROUP INC
TEMPORARY SERVICES
TEMPORARY SERVICES
I' 1,000.95 AP10400835
401.19 AP"l04!13223
33001680
33823011
09752002
09759311
R305768-0-1-66165-107
R359765-0-1-·65370-46
M 2011 12 124396 GUIDANT GROUP INC TEMPORARY SERVICES 568.!!9 AP104&3223 33623073 09759302 R441438--0-1-6637o-91il
M 2011 12 124398 GUIDANT GROUP INC TEMPORARY SERVICES 397.32 AP10483223 33823101 09759200 R473125.0·1-SG37()-126
M 2011 12 124398 GUIDANT GROUP INC TEMPORARY SERVICES 496.85 AP10483223 33623159 09759554 R53178&.()..1-66370-174
M 2011 12 124396 GUIOANT GROUP !NC TEMPORARY SERVICES 511.71 AP10464ll47 33918299 097&4431 R72367S--0-1-07127-81
M 2011 12 1243!!8 GUIDANT GROUP INC TEMPORARY SERVICES 5!1.71 AP104B5651 33966905 09795246 RS70109-0-1-67519-55
'
M 2011 12 124398 GUIDANT GROUP INC TEMPORARY SERVICES 722.40 AP104S5651 33966907 09795256 RS70727-0-1-57519-57
' S030251l-0-1-S7&27-5!l
M 2011 12 124398 GU !DANT GROUP INC TEMPORARY SERVICES 577.92 AP10400291 33978309 09798773
M 2012 1 12439!! GUIDANT GROUP INC TEMPORARY SERVICES 408.35 APi0488804 33998055 09803506 S1$4592-0-i-66076-114
M !2012 1 1.24396 GUIDA."IT GROUP !NC TEMPORARY SERVICES ! 254.41 AP104BSS04 34031076 09810506 S23636S-0-1..S8473-96
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M 2012 1124398 GUIDANT GROUP INC TEMPORARY SERVICES 460.53 AP10488004 34031148 09810974
M 2012 1124398 GUIDANT GROUP INC
-- TEMPORARY SERVlCES 541.!lO AP104SBB04 34069179 09819123
S.264579-0-1·68473-158
S26462S-0·1·6BB12·32
M 2012 1 124396 GUIDANT GROUP INC TEMPORARY SERVICES 303.34 AP104l!8S04 34059256 09!119075 S317960-0-1.Q8612-108
M 2012 1124398 jGUIOANT GROUP INC TEMPORARY SERVICES- I 041.13 AP10490556 34108148 09828110 S335592-0.i-6913S-45
M 2012 1 124398 GUIDANT GROUP INC TEMPORARY SERVICES 283.77 AP10490551S 34108169 09823644 5366851..0-1-59136-66
M 2012 1 124398 GUIDANT GROUP INC TEMPORARY SERVICES ·} 1,566.1!4AP10490551l 34106257 09!!211763 S3$7971--0-1-69136-1M
M 12012 2 124398 .~UIOANT GROUPINC TEMPORARY SERVICES 117.42 AP10492710 34136824 09836565 S439105--0·1-59472-ll4
M 20121 2 124398 GUIDANT GROUP INC TEMPORARY SERVICES 451.65 AP10492710 34136$70 09!136600 S456634-Q..1-69472-130
M 2012 L .2 12439& GUIDANT GROUP INC TEMPORARY SERVICES 722.40 Af'10492710 34136940 091136$46 54S163().(l·1-69472-100
M 2 124398 GUIDANT GROUP INC TEMPORARY SERVICES 2,724.17 AP10492715 34136801 09836748 8425612-0-1·69472-61
201*
M 12012 2 124391! GUIDANT GROUP INC TEMPORARY SERVICES 105.$2 AP10493036 34174543 09644369 fS536019-0-1-69613·98
M 2012 2 124398 !GUIDANT GROUP !NC TEMPORARY SERVICES 735.95 AP10493036 34174560 091145113 SS44282-0-1-69813·115
M 2012 2 124398 GU!OANT GROOP INC TEMPORARY SERVICES I 60.22 AP1049303li 34174564 09844!;12 S5454®-0-1-600i3-119
M 2012 j 2 124398 GUIDANT GROUP INC TEMPORARY SERVICES 2,724.17 AP10493041 34174342 09644321 S478626.0-1-69ai3-37
M 2012 2 124398 GUIDANT GROUP INC TEMPORARY SERVICES 254.41 AP10494009 34212029 09853075 5633002-0-1-70207-110
M 2012 2 124396 GUIDANT GROUP INC TEMPORARY SERVICES 722-40 AP10494009 34212074 09853383 S68946!l-o.1-70207-155
M 2012 2 1243911 GUIDANT GROUP INC TEMPORARY SERVICES 2,332.46 AP10494014 34211955 09853857 S583344-0-1-70207-36
M 2012 2 124398 !GUIDANT GROUP INC TEMPORARY SERVICES 1.442.21 AP10494795 34:249064 09862186 S685807..0.1-70545-49
-
M 201:2 2 124398 !GUIDANT GROUP INC TEMPORARY SERVICES 136.99 AP10494982 34249168 09862437 S712631..0.1-70545-133
M 2012 2 12439$ GUIDANT GROUP !NC TEMPORARY SER.VICES 577.92 AP104949S2 34249170 09862436 $712930-0-1-70545-135
2012 3 1243$8
I~
GUIDANT GROUP INC TEMPORARY SERVICES 254.42 AP10497469 34261327 09670263 S79$668-0-1-70609·98
2012 3 124398 GUIDANT GROUP INC TEMPORARY SERVICES 577.92 AP10497469 34281357 09670571 S800514-0-1-roGO!M 26
M 2012 3 124396 GUIDANT GROUP INC TEMPORARY SERVICES 2,385.88 AP10497474 34281280 09870084 S738$49-0-1-7000!>-51
M 2012 3 124398 !GUIDANT GROUP INC TEMPORARY SERVICES 117.42 AP10497731 34324093 098791120 5900494-0-1-71240-104
M 2012 3 124398 GUIDANT GRO\JP INC TEMPORARY SERVICES 722.40 AP104Sn31 34324207 09879921 S964S67--0-1-71240-1 &!
,....--,.
M 2012 3 124398 GUIDANT GROUP INC TEMPORARY SER.VICES 1,210.74 AP1049n3e 34323993 09879787 SB63729-0-1-71240-44
~ M 2012
2012
3 124398
3 1243$8
GUIDANT GROUP INC TEMPORARY SERVICES 749.50 AP10498940 34367915 00691280 8965117-0.1-71624-52
M GUIDANT GROUP INC !TEMPORARY SERVICES 136.99 AP10496940 34367933 09891156 5973171--0·1·11624·70
M 2012 3 124398 !GUIDANT GROUP INC TEMPORARY SERVICES I 1,335.38 AP10496943 34367907 O!iB90964 S941602-0-i-71624-44
M 2012 ! 3 124398 GUIDANT GROUP INC TEMPORARY SERVICES 185 92 AP10499811 34403196 09$98482 T084663-0-1-71!102-118
M 2012 3124398 GUIDANT GROUP INC iTEMPORARY SERVICES 541.l!O AP1049961i 34403236 098911441 T0916504-1-71902-136
M 2012 3124398 GUIDANT GROUP INC TEMPORARY SERVICES 1,638.06 APi0-499814 34403119 09898653 T050743..Q..1-71902·59
M 2012 3 12439& GUIDANT GROUP INC TEMPORARY SERVICES 39. i4 AP10500962 34441064 09909306 T174551-0-1 ·72251·1i0
M 2012 3 1243911 GUIDANT GROUP !NC TEMPORARY SERVICES 577.92 AP10500002 34441112 09909276 T210366-0-i-72251-158
M 2012 3 124398 GUIDANT GROUP INC TEMPORARY SERVICES 668.70 AP10500006 34440946 09909396 719367-1-72251-32
M 2012 3 i.24398 GUIDANT GROUP INC TEMPORARY SERVICES 417.43 AP10500966 34440947 09909403 719367-1-72251-33
M 2012 3 124398 GUIDANT GROUP INC TEMPORARY SERVICES 2.846.60 Af'10500SGO 34440987 09909317 T124402-0-1-72251-53
M 2012 4 124398 GUIDANT GROUP !NC TEMPORARY SERVICES 29.35 AP10502995 34481744 09918922 T257743-0·1-72608-69
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..
M 2012 4 124398 GUIDANT GROUP INC TEMPORARY SERVICES 686.28 AP10502995 34481!l50 09918941 T266245·0-1-72SOB-135
M 2012 4 124398 GUIDANT GROUP INC TEMPORARY SERVICES 979.28 AP10503000 34481719 09910024 1"224020-0·1-72008-44
M 2012 4 124398 GUIDANT GROUP INC TEMPORARY SERVICES 29.:.lS
AP1050367B 34518260 09926918 T.168655.0-1·73004-56
M 2012 4 12439$ GUIDANT GROUP INC TEMPORARY SERVICES
- 577.92 AP1050367!1 34518204 09927111 T379437-0· 1-73004-!IO
M
,______ 2012 4 124398 GUIDANT GROUP INC TEMPORARY SERVICES 2,403.68 AP10503684 34516243 09926951 T332620.0·1-73004-39
M 2012 4 124398 GUIDANT GROUP INC TEMPORARY SERVICES 595.98 AP10504402 34558457 09935027 1"472727-0-1-73356-120
M 2012 4 124398 GUIDANT GROUP INC TEMPORARY SERV!CES 1,051.72 AP1050442m-0-1-7S47H3
V017386-0-1-7$il42-44
V15190B-0-1-7921S.56
--
l
M 2012 I'! 124398 GUIDANT GROUP INC TEMPORARY SERVICES -0.63 AP10524435 35124526 10092192 U26236i-0-i-7BS43-3
M 2012 !l 124398 GUIDANT GROUP INC TEMPORARY SERVICES -0.63 AP10524435 35124717 10091788 U670743-0-1-71l843-S4
M 2012 a 124398 GUIDANT GROUP INC TEMPORARY SERVICES -0.82 AP10524435 35124742 10091297 U781454-0-i-76!143-109
M 2012 8 1243911 GUIDANT GROUP INC TEMPORARY SERVICES -0.03 AP10524435 35124756 10091259 Ull86271l-0-1-7Sll43-123
M 2012 8 124398 GUIDANT GROUP INC TEMPORARY SERVICES 426.90 AP10524710 35235243 10098441 V37096141-00015-47
1,336,1'!7.88 TOTAL TYPENOT=M
626,757.00 TOTAlFROMTYPE=MTAS
1,962,874.88 TOTAL COMPANY DIRECT EXPENSES
====~(5::6:.;;0.,..Q;.;;0"-) LESS: NON-CONFORMING COMPANY EXPENSES (Sae Add 2 to Staff 9-13 for breakout}
1,962,314.88 TOTAL REQUESiED COMPANY DIRECT EXPENSES
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Roadmap to Internal Rate Case fxpen~es - Tab 2
li:IO'f;iil ;~~~~¥1W'~lfNatQe~~~i~f~~~~~rt,f~t~ lli\aWi~lNilJll$!J7 \P~ri'Wlll\Gii 1~;nime
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9 024 Bw;looss Meals!Emartarnment 24.09 EEX,_SUMMAAY APi0469IO'I 0010567 TAYLOOJR,JOHN E 33392500 09646$71 09061i13398
91024 }Business Maa!slEnt<>rtainmem ' 69.4SJEEX SUMMARY lAPi0469339 !9013559 BARRILLEAUX.CHRIS E 33410594 09653768 091211135036
' CALOWEU.,BRlAN W 33417570 09655771 091211145322
TAYl.OR JR.JOHN E 33554557 0$600104 10001i36244
OOSS,GENEE 336261111 09700411 101711126842
Business; Mea!s/Enlerta!nmenl 40.00 EEX_SUMMARY AF'\0476103 e01m::i CAWGERO,WENDY D 33657723 00713637 1025114000
lauslness Meals!Entertalnmoot 15.21 EID\_SUMMARY A?10478515 9012226 HERRINGTON.CHESTER 33712733 0072&295 i 10311219996
jBus!ness Meals/Enterlalnmenl 1,132.54 EEX_SUMMARY A?i04ll3434 9010509 FLOOO,JOHN C 33883061 oon3438 1201311627547
Business Mea!slEnlertalnment 27.66 EEX_SUMMARY AP10003678 9030496 THIRY,MICHELL.E H 34533003 00928559 04! 112190093
Business Mea!s!Entertalnmem 40.77 EEX_SUMMARY AP10504955 9010724 MORGAN,Wn.t.rAM R 345!'!6077 09'941357 04191268906
4 024 Business Mea!s/Entertalnmenl 207.13 EEX_SUMMAAY AP1050li194 9012152 OOMINO,JOSEPH F 34593266 00943519 041912415876
4 024 E!Yslness Meals/Entertalnment 50.14 EEX,_SUMMARY API0005873 9041283 OONS!OlNE.MICHAEl P 34008934 00948155 042612100869
5 024 Business Meals/Entertalnmenl 38.16 EEX SUMMARY AP10507633 0010645 COOPER.ROBERT R 34628123 09952004 ()4301200002
5 024 Business Meals/Eoteminment 4$.96 EEX_SUMl.~ -·
AP10507633 9012356 GARRISON, WINFRED W 3'«l6109S 09960070 050412325491
5 024 6usioos" Mea!s/En!erlalnment 123.39 EEX_SUMMARY Af'10507633 9025842 TUMMINEU.0,STEPHANIE 6 34528188 00952733 !l43012139144
5 024 Business Meals/Entertainment l 22.46 EEX._SUMMARY A.?10507533 9031046 CHIGH!ZOl..A.MAAIA F 34628237 09952737 0501121i8001
5 024 jBusloeSs Meals/Emertainmenl I 42.91 eex_SUMMARY AP10507633 9032452 LEBl.MlC,HEATHER G $4637593 09954418 043012106541
5 024 !Business Meals/Entertaiomenl 118.46 EEJCSUMMARY AP10507633 903299$ MCCIJt.LA,MARK F 34637507 09954423 050112499386
5 IJ24 Business MealsJEmer!ainmenl 21.58 EEX_SUMMARY API050013B 9010845 COOPER.ROBERT R 34682301 099639&6 05081243399
--·
5 024 Busln8$$ Mea!s/Entertalnmeol I 47.49 EEX_SUMMARY API0500139 9011616 CICIO,PATRICK J 34682213 Q'.il964003
5 024 Business Mee!s/Errteruolnment 215.01 EEX_SUMMARY AP1050813S 0014365 TAU}
Depreciation & Amort Expe~$ •••--- (Blank Value}
Oepreclat10o & Amor! Expensas (Blank Value)
O..precla1lon & Amort ~ses
0eprecla1ion & Amoit Expenses
Depreciation & Amort Expenses
Deprecialion & Amor! Expenses
Depreciation & Amort Expenses
IDE!)recialion & Amon Expenses
O@preciatloo & Amert Expenses
Depractatioo & Amort Expenses
w
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Employee Mt9s/functions/Awards
Employae Mtgs/functlooSIAwards
33242475
33313747
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33438423
33547707
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F5PPETX011 !2011 335<16852
F5PPETX011 !2011 33780590
F5PPETIC011 !~m 33703862
F5PPETX011 l201! 2.72!EEX_SUMMARY 33703862 09747976
F5PPETX011 l2011 M!9slFunctloos/Awards 1S4.95IEEX_SUMMARY 3384195! 09795010
RiPPETX011 12011 M!gs/Func!iC. °'..:..
Roadmap to internal Rate Case Expenses - Tab 2
F5PPETX011 2012 4 IJZl !Employee MlQslFunciionsJAwards ITHIRY,MICHELLE H 34533003
F5PF'ETI«l11 2012 5 IJZT lEinployea Mt9sll'mciiorn;/Awards CITIBANK USA NA PCARD
F5PPETXOi 1 2012 6 r:/1.7 IEmPIOyee Ml9s/FunctionslAwards 134899356
F5PPETX011 2012 7 WY !Employee MlQs/Functloos/Awards 35038263
F5PPETX011 2011 7 032 !Lodging 33110900
F5PPETI<011 201 t 9 032 jt.:>d9in9 33364230
F5PPE1'X011 2011 9 032 jLod9i119 33417570
F5PPE1'X011 2011 10 032 }l~9io9 33626811
F5PPETIC011 2011 11 032 ll<>dgin9 33712733
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F5PPETX011 2011 12 032 11..odQing 33893001
F5PPETX011 2012 3 002 ILod9in9 34317303
F5PPETX011 2012
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F5PPETX011 2012 9032996 MCCUll..A,MARK F 34637507 09954423 10501 !2499386
F5PPETX011 2012 9010845 COOPER.ROBERT R 34682301 00963986 105081243399
F5PPETX011 2012 10011616 CICIO,PATRICKJ !34682213 0!!964003 P-712298369
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'ROOERTS,RORY Ll.ITHER 052312172184
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0608121131171
062212100989
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I 49.00,EEX_SU~MARY
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12 028 Olffilr Emp!oyee Expenses 12.00IEEX.....SUMMAA.Y
12 ()2$ Other Employee E>pen""" 541.23!EEX_SUMMARY 120011627547
1 028 fOlller Employee Expenses S3.34IEEX_SUMMARY 1226116334
3 028 jO!Mr Emp~ee ElSeG 26.00IEEX_SUMMAAY 03021299207
3 028 other Employee Expenses :03081280408
F5PPETX011.l2012 ! 3 028 other Employae Exl)eno;es 34382946 030412114053
F5PPETX011 /2012 3 028 Oilier Employee E>penses 34444162
F5PPE1'X011 2012 4 028 Oltier Employee E>pense& 34533003
F5PPETX011 2012 4 026 Other Emplcyoe Elpanses 4().00 EEX_SUMMARY 346Si096
!F5PPETX011 2012 --sioo EEX_SUMMARY 34628188
26.00!EEX.JMAMAAY
152.15IEEX....SUMMAAY
Employee Expenses 101.51 lEEX_SUMMAAY
147.50!EEX_SUMMARY
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Roadmap to Internal Rate Case Experu.>es - Tab 2
s 740 1servj;;., Company Recipient 26,628.05 SCR_SUMMAAY ALOOS11301 {Blank Value)
6 740 Se!Vlce Campany Recipient 6,534.SS SCfUlUMMARY Al-00516356 (Blank Value)
7140 Sel\llee Campany Recipient £,153.14 SCR_SUMMARY Al00521270 (Blank Value)
8140 SQIV!ce Company Recipient 3,652.41 SCR_Sl.IMMARY AL005.26273 (Blllnl?m0112012r- 3 031 Travel Transportalion 686.62 E8USUMMARY l\P10497469 0043693 BOURG.JONATHAN 34317303 00876934
F5PPETX011 2012 I 3 031 iTravel Transportation 540 36 EEX_SUMMAR'I' AP10498996 0015259 VONGl504955 9010724 MORGAN,WILUAM R 34566077 09941357
F5PPEiJW11 2012 4 031 Travel Trall$porta!lon 575.70 EEX_SUMMARY AP1o505194 !0012152 OOMlNO.JOSEPH F 34593266 09943519
F5PPETX011 2012 4 031 Travel Transportation 581.70jEEX_SUMMARY !AP10505873 0041283 CONS!OINE,MICHAEL P 34608934 09948155
F5PPETX011 2012 5 031 Travel Transportation 596.20 EEX_SUMMAAY AP10507633 0025842 TIJMMINELLO,STEPHAHJE B 34628188 09252733 lM3012139144
F5PPETX011 2012 5 031 Travel Transpc'1ation 1;12.2tl EEX SUMMARY AP10007633 0031046 CHIGH!ZO!.A,MAAIA F 34628237 09952737 060112118001
F5PPETX011 2012 s o3! !Travel Transporta!icn 594.70 EEX_SUMMAFIY AP10507633 9032452 LEBLANC.HEATHER G 34637593 0995441& 043012106541
5 031 Trav&I Transportation 1,492.45 EEX_SUMMARY AP!0007633 90:12996 MCCULlA.MAAK F 34637507 !099544:23 050112499386
s 031 TravQI Transporlalion 1,117.27 EEX_SUMMARY AP10500139 9011616 CICIO,PATRICK J 34682213 00964003 05071:2298369
5 031 Travel Transportallan 1.900.So EEX_SUMIMRY AP10500139 9014365 TALK!NGTON,MYRA L 34682262 09963$93 050812301556
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Travel Transportallcn 638.70 EEX_SUMMARY AP10510290 9035153 MCCLOSKEY.IJ.ARGARET 34777185 00985837 052412115121
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---
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Travel Transportation 1,059.SS EEJ(_SUMMAAY AP 1051:2621 9013£98 ROBERTS.RORY LIJTHER 34816362 00995198 05:2312172184
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·1·· · · · · · · · SOAH DOCKET NO. XXX-XX-XXXX
· ·
·2·· · · · · · · · · · PUC DOCKET NO. 40295
· ·
·3··
· ·
·4··APPLICATION OF ENTERGY· · ·§··BEFORE THE STATE OFFICE
· · · · · · · · · · · · · · ·· §
·5··TEXAS, INC. FOR RATE CASE··§
· · · · · · · · · · · · · · ·· §· · · · · ··OF
·6··EXPENSES PERTAINING TO· · ·§
· · · · · · · · · · · · · · ·· §
·7··PUC DOCKET NO. 39896· · · ·§··ADMINISTRATIVE HEARINGS
· ·
·8··
· ·
·9·· · · · · · · · ·· HEARING ON THE MERITS
· ·
10·· · · · · · · · WEDNESDAY, NOVEMBER 28, 2012
· ·
11··
· ·
12·· · · · ·· BE IT REMEMBERED THAT at 10:00 a.m., on
· ·
13··Wednesday, the 28th day of November 2012, the
· ·
14··above-entitled matter came on for hearing at the State
· ·
15··Office of Administrative Hearings, 300 West 15th Street,
· ·
16··Room 408A, Austin, Texas, before HUNTER BURKHALTER,
· ·
17··Administrative Law Judge, and the following proceedings
· ·
18··were reported by Steven Stogel, a Certified Shorthand
· ·
19··Reporter.
· ·
20··
· ·
21··
· ·
22··
· ·
23··
· ·
24··
· ·
25··
Page 2
·1·· · · · · · · · ··A P P E A R A N C E S
· ·
·2··
·FOR ENTERGY TEXAS, INC.:
· ·
·3··
· · · ··Mr. Steven Neinast
·4·· · ··Assistant General Counsel
· · · · · · ·- and -
·5·· · ··Ms. Wajiha S. Rizvi
· · · ··Counsel
·6·· · ··ENTERGY SERVICES, INC.
· · · ··919 Congress Avenue, Suite 840
·7·· · ··Austin, Texas 78701
· · · ··Telephone:··512.487.3957 - Fax:··512.487.3958
·8·· · ··Email: wrizv90@entergy.com
· · · · · · ·- and -
·9·· · ··Mr. George Hoyt
· · · ··DUGGINS WREN MANN & ROMERO, LLP
10·· · ··600 Congress Avenue, Suite 1900
· · · ··Austin, Texas··78701
11·· · ··Telephone:··512.744.9300 - Fax: 512.744.9399
· · · ··Email: ghoyt@dwmrlaw.com
12··
· ·
13··FOR THE OFFICE OF THE PUBLIC UTILITY COUNSEL:
· ·
14·· · ··Ms. Sara J. Ferris
· · · ··Assistant Public Counsel
15·· · ··OFFICE OF PUBLIC UTILITY COUNSEL
· · · ··1701 N. Congress Avenue, Suite 9-180
16·· · ··Austin, Texas 78701
· · · ··Telephone:··512.936.7500
17·· · ··Email: opuc_eservice@opc.state.tx.us
· ·
18··
·FOR THE PUBLIC INTEREST:
· ·
19··
· · · ··Mr. Brennan J. Foley
20·· · ··Attorney-Legal Division
· · · ··PUBLIC UTILITY COMMISSION OF TEXAS
21·· · ··1701 N. Congress Avenue, Suite 8-110
· · · ··Austin, Texas 78701
22·· · ··Telephone:··512.936.7163 - Fax:··512.936.7268
· ·
23··
· ·
24··
· ·
25··
KENNEDY REPORTING SERVICE, INC.
512.474.2233
Page 3
·1·· · · · · · · · ··A P P E A R A N C E S
· ·
·2··
· ·
·3··FOR THE CITIES:
· ·
·4·· · ··Mr. Stephen Mack
· · · ··LAWTON LAW FIRM
·5·· · ··701 Brazos, Suite 500
· · · ··Austin, Texas 78701
·6·· · ··Telephone:··512.322.0019 - Fax:··512.716.8917
· ·
·7··
·FOR STATE AGENCIES:
· ·
·8··
· · · ··Ms. Susan M. Kelley
·9·· · ··Assistant Attorney General
· · · ··OFFICE OF THE ATTORNEY GENERAL
10·· · ··P.O. Box 12548
· · · ··Austin, Texas 78711-2548
11·· · ··Telephone:··512.475.4173 - Fax:··512.320.0167
· · · ··Email: susan.kelley@texasattorneygeneral.gov
12··
· ·
13··FOR TEXAS INDUSTRIAL ENERGY CONSUMERS:
· ·
14·· · ··Ms. Meghan E. Griffiths
· · · ··ANDREWS KURTH, LLP
15·· · ··111 Congress Avenue, Suite 1700
· · · ··Austin, Texas 78701
16·· · ··Telephone:··512.320.9214 - Fax:··512.320.9292
· · · ··email: meghangriffiths@andrewskurth.com
17··
· ·
18··
· ·
19··
· ·
20··
· ·
21··
· ·
22··
· ·
23··
· ·
24··
· ·
25··
KENNEDY REPORTING SERVICE, INC.
512.474.2233
Page 4
·1·· · · · · · · · · ··TABLE OF CONTENTS
· ·
·2·· · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE
· ·
·3··PROCEEDINGS, WEDNESDAY, NOVEMBER 28, 2012· · · · · ··11
· ·
·4··OPENING STATEMENT ON BEHALF OF
·APPLICANT ENTERGY TEXAS, INC.· · · · · · · · · · · ··17
· ·
·5··
·OPENING STATEMENT ON BEHALF OF CITIES· · · · · · · ··22
· ·
·6··
·OPENING STATEMENT ON BEHALF OF
· ·
·7··OFFICE OF PUBLIC UTILITY COUNSEL· · · · · · · · · · ·22
· ·
·8··OPENING STATEMENT ON BEHALF OF STATE AGENCIES· · · ··23
· ·
·9··OPENING STATEMENT ON BEHALF OF
·TEXAS INDUSTRIAL ENERGY CONSUMERS· · · · · · · · · ··28
· ·
10··
·PRESENTATION ON BEHALF OF
· ·
11··APPLICANT ENTERGY TEXAS, INC.· · · · · · · · · · · ··30
· ·
12·· · ··MICHAEL P. CONSIDINE
· · · · · · ·- Direct (Rizvi)· · · · · · · · · · · · · ·30
13·· · · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·32
· · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·43
14·· · · · · ·- Redirect (Rizvi)· · · · · · · · · · · · ·46
· · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·48
15··
· · · ··STEPHEN F. MORRIS
16·· · · · · ·- Direct (Hoyt)· · · · · · · · · · · · · ··51
· · · · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·54
17·· · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·75
· · · · · · ·- Redirect (Hoyt)· · · · · · · · · · · · ··80
18··
·PRESENTATION ON BEHALF OF
· ·
19··OFFICE OF PUBLIC UTILITY COUNSEL· · · · · · · · · · ·83
· ·
20·· · ··NATHAN BENEDICT
· · · · · · ·- Direct (Ferris)· · · · · · · · · · · · ··83
21·· · · · · ·- Cross (Foley)· · · · · · · · · · · · · ··85
· · · · · · ·- Clarifying (Burkhalter)· · · · · · · · ··86
22·· · · · · ·- Redirect (Ferris)· · · · · · · · · · · ··87
· ·
23··PROCEEDINGS CONCLUDED· · · · · · · · · · · · · · · ··89
· ·
24··REPORTER'S CERTIFICATE· · · · · · · · · · · · · · · ·90
· ·
25··
KENNEDY REPORTING SERVICE, INC.
512.474.2233
Page 5
·1·· · · · · · · · · · ··EXHIBIT INDEX
· ·
·2··CITIES· · · · · · · · · · · · · · · · · ·MARKED ADMITTED
· ·
·3··1.· · · ··Direct Testimony and Exhibits
· · · · · · ·of Amalija J. Hodgins filed in
·4·· · · · · ·Docket No. 39896· · · · · · · · · ·11· · · ·82
· ·
·5··2.· · · ··Supplemental Direct Testimony
· · · · · · ·of Amalija J. Hodgins· · · · · · ··11· · · ·82
·6··
· ·
·7··
· ·
·8··
· ·
·9··
· ·
10··
· ·
11··
· ·
12··
· ·
13··
· ·
14··
· ·
15··
· ·
16··
· ·
17··
· ·
18··
· ·
19··
· ·
20··
· ·
21··
· ·
22··
· ·
23··
· ·
24··
· ·
25··
KENNEDY REPORTING SERVICE, INC.
512.474.2233
Page 6
·1·· · · · · · · · · · ··EXHIBIT INDEX
· ·
·2··COMMISSION STAFF· · · · · · · · · · · · ·MARKED ADMITTED
· ·
·3··1.· · · ··Direct Testimony of Brian T.
· · · · · · ·Murphy· · · · · · · · · · · · · · ·11· · · ·89
·4··
·2.· · · ··ETI Response to State of
· ·
·5·· · · · · ·Texas RFI 3-17· · · · · · · · · · ·11
· ·
·6··
· ·
·7··
· ·
·8··
· ·
·9··
· ·
10··
· ·
11··
· ·
12··
· ·
13··
· ·
14··
· ·
15··
· ·
16··
· ·
17··
· ·
18··
· ·
19··
· ·
20··
· ·
21··
· ·
22··
· ·
23··
· ·
24··
· ·
25··
KENNEDY REPORTING SERVICE, INC.
512.474.2233
Page 7
·1·· · · · · · · · · · ··EXHIBIT INDEX
· ·
·2··ENTERGY· · · · · · · · · · · · · · · · ··MARKED ADMITTED
· ·
·3··1.· · · ··Docket No. 39896 - Direct
· · · · · · ·Testimony of Michael P.
·4·· · · · · ·Considine (Redacted filed
· · · · · · ·11/28/11)· · · · · · · · · · · · ··11· · · ·31
·5··
·2.· · · ··Schedule G-14.1· · · · · · · · · ··11· · · ·31
· ·
·6··
·3.· · · ··Rate Case Expenses Rider and
· ·
·7·· · · · · ·Cost Allocations· · · · · · · · · ·11· · · ·31
· ·
·8··4.· · · ··Docket No. 39896 - Supplemental
· · · · · · ·Direct Testimony and Exhibits of
·9·· · · · · ·Michael P. Considine (3/13/12)· · ·11· · · ·31
· ·
10··5.· · · ··Docket No. 40295 - Supplemental
· · · · · · ·Direct Testimony and Exhibits of
11·· · · · · ·Michael P. Considine (10/5/12)· · ·11· · · ·31
· ·
12··6.· · · ··Docket No. 40295 - Supplemental
· · · · · · ·Direct Testimony and Exhibits of
13·· · · · · ·Michael P. Considine (10/25/12)· ··11· · · ·31
· ·
14··7.· · · ··Docket No. 40295 - Rebuttal
· · · · · · ·Testimony and Exhibits of
15·· · · · · ·Michael P. Considine (11/15/12)· ··11· · · ·31
· ·
16··8.· · · ··Docket No. 39896 - Direct
· · · · · · ·Testimony and Exhibits of
17·· · · · · ·Stephen F. Morris (11/28/11)· · · ·11· · · ·53
· ·
18··9.· · · ··Docket No. 39896 - Supplemental
· · · · · · ·Direct Testimony of Stephen F.
19·· · · · · ·Morris (3/13/12)· · · · · · · · · ·11· · · ·53
· ·
20··10.· · · ·Docket No. 40295 - Supplemental
· · · · · · ·Direct Testimony of Stephen F.
21·· · · · · ·Morris (10/5/12)· · · · · · · · · ·11· · · ·53
· ·
22··11.· · · ·Docket No. 40295 - Supplemental
· · · · · · ·Direct Testimony of Stephen F.
23·· · · · · ·Morris (10/25/12)· · · · · · · · ··11· · · ·53
· ·
24··12.· · · ·Docket No. 40295 - Rebuttal
· · · · · · ·Testimony of Stephen F.
25·· · · · · ·Morris (11/15/12)· · · · · · · · ··11· · · ·53
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·1·· · · · · · · · · · ··EXHIBIT INDEX
· ·
·2··OPUC· · · · · · · · · · · · · · · · · · ·MARKED ADMITTED
· ·
·3··1.· · · ··Direct Testimony and Workpapers
· · · · · · ·of Nathan A. Benedict· · · · · · ··11· · · ·84
·4··
·2.· · · ··ETI Response to OPUC RFI 3-1,
· ·
·5·· · · · · ·3-2 and 3-3· · · · · · · · · · · ··43· · · ·46
· ·
·6··3.· · · ··2/3/11 PUC Open Meeting
· · · · · · ·Excerpt· · · · · · · · · · · · · ··75· · · ·75
·7··
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·1·· · · · · · · · · · ··EXHIBIT INDEX
· ·
·2··STATE AGENCIES· · · · · · · · · · · · · ·MARKED ADMITTED
· ·
·3··1.· · · ··Response to Staff's RFI 9-1,
· · · · · · ·Including Add. 1, Add. 2 and
·4·· · · · · ·Add. 3 (on CD)· · · · · · · · · · ·11· · · ·16
· ·
·5··2.· · · ··Invoices from Naman Howell
· · · · · · ·(Included in SA #1)· · · · · · · ··54· · · ·61
·6··
·3.· · · ··ETI Response to State
· ·
·7·· · · · · ·Agencies' RFI 3-17· · · · · · · · ·11· · · ·16
· ·
·8··4.· · · ··ETI Response to State
· · · · · · ·Agencies' RFI 1-2· · · · · · · · ··34· · · ·35
·9··
·5.· · · ··ETI Response to Staff RFI 9-9· · ··38· · · ·39
· ·
10··
·6.· · · ··ETI Response to State
· ·
11·· · · · · ·Agencies' RFI 10-1· · · · · · · · ·54· · · ·58
· ·
12··7.· · · ··ETI Response to State
· · · · · · ·Agencies' RFI 10-2· · · · · · · · ·54· · · ·58
13··
·8.· · · ··ETI Response to State
· ·
14·· · · · · ·Agencies' RFI 10-11· · · · · · · ··54· · · ·62
· ·
15··9.· · · ··ETI Response to State
· · · · · · ·Agencies' RFI 9-13· · · · · · · · ·36· · · ·37
16··
·10.· · · ·OPEN
· ·
17··
·11.· · · ·ETI Response to State
· ·
18·· · · · · ·Agencies' RFI 9-8· · · · · · · · ··38· · · ·41
· ·
19··12.· · · ·ETI Response to Staff RFI 1-8· · ··38· · · ·40
· ·
20··13.· · · ·ETI Response to State
· · · · · · ·Agencies' RFI 10-6· · · · · · · · ·11· · · ·16
21··
·14.· · · ·Texas Lawyer Hourly Billing
· ·
22·· · · · · ·Rates Survey 2011· · · · · · · · ··54· · · ·63
· ·
23··15.· · · ·Duggins, Wren Contract with
· · · · · · ·Naman Howell· · · · · · · · · · · ·54· · · ·55
24··
· ·
25··
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·1·· · · · · · · · · · ··EXHIBIT INDEX
· ·
·2··STATE AGENCIES· · · · · · · · · · · · · ·MARKED ADMITTED
· ·
·3··16.· · · ·ETI Response to State
· · · · · · ·Agencies' RFI 2-3· · · · · · · · ··11· · · ·16
·4··
·17.· · · ·Excerpt of 12/8/11 Duggins,
· ·
·5·· · · · · ·Wren Law Firm Bill (Entire
· · · · · · ·Bill Included in Exhibit 1)· · · ··54· · · ·71
·6··
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·7··
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·8··
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·9··
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10··
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11··
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12··
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·1·· · · · · · · · ··P R O C E E D I N G S
·2·· · · · · · · ·WEDNESDAY, NOVEMBER 28, 2012
·3·· · · · · · · · · · · ·(10:00 a.m.)
·4·· · · · · · · ·(Exhibit Cities Nos. 1 and 2 marked)
·5·· · · · · · · ·(Exhibit Commission Staff Nos. 1 and 2
·6·· · · · · · · ·marked)
·7·· · · · · · · ·(Exhibit ETI Nos. 1 through 12 marked)
·8·· · · · · · · ·(Exhibit OPUC No. 1 marked)
·9·· · · · · · · ·(Exhibit State Agencies Nos. 1, 3, 13 and
10·· · · · · · · ·16 marked)
11·· · · · · · · ·JUDGE BURKHALTER:··I'll call to order
12··Docket No. XXX-XX-XXXX.··It's PUC Docket No. 40295.
13··It's a case styled Application of Entergy Texas, Inc.,
14··for Rate Case Expenses Severed from PUC Docket
15··No. 39896.
16·· · · · · · · ·This is Judge Burkhalter.··It's Wednesday,
17··November 28, 2012.··It's 10:00 in the morning, and we
18··are in Austin, Texas.··Let me take appearances, and I'll
19··just start with the Applicant and work our way down the
20··table, please.
21·· · · · · · · ·MR. NEINAST:··Thank you, Your Honor.
22··Steve Neinast with Entergy Texas.··I'd also like to
23··enter the appearance of Wajiha Rizvi with Entergy Texas
24··and George Hoyt with the Duggins Wren law firm.
25·· · · · · · · ·JUDGE BURKHALTER:··Welcome to you-all.
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·1·· · · · · · · ·MR. MACK:··Stephen Mack for the Cities,
·2··Your Honor.
·3·· · · · · · · ·MS. FERRIS:··Good morning, Your Honor.
·4··Sarah Ferris with the Office of Public Utility Counsel.
·5·· · · · · · · ·MS. KELLEY:··Good morning, Your Honor.
·6··Sue Kelley for the State Agencies.
·7·· · · · · · · ·MS. GRIFFITHS:··Good morning.··Meghan
·8··Griffiths for Texas Industrial Energy Consumers.
·9·· · · · · · · ·MR. FOLEY:··Good morning, Your Honor.
10··Brennan Foley for Commission Staff.
11·· · · · · · · ·JUDGE BURKHALTER:··Okay.··We took care of
12··a little bit of business before we went on the record by
13··agreement.··The parties are going to admit the direct
14··testimony of Cities' witness, Amy Hodgins, and waive
15··cross on her, and likewise with Staff's witness, Brian
16··Murphy.··Correct?
17·· · · · · · · ·MR. MACK:··Your Honor, and she also had
18··supplemental direct testimony, Exhibits 1 and 2.··Her
19··direct is Exhibit 1 and supplemental is Exhibit 2.
20·· · · · · · · ·JUDGE BURKHALTER:··All right.··Thanks.··Is
21··there any other business we can take care of before we
22··go to opening statements?
23·· · · · · · · ·MS. KELLEY:··Yes, Your Honor.··I have some
24··exhibits I put up there near you which the Company has
25··agreed can be admitted.··And I don't think anybody else
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·1··has objection to it, but I'll let them speak for
·2··themselves.··That would be --
·3·· · · · · · · ·JUDGE BURKHALTER:··Let me first ask --
·4·· · · · · · · ·MS. KELLEY:··Yes.
·5·· · · · · · · ·JUDGE BURKHALTER:··Has everybody given me
·6··a copy?
·7·· · · · · · · ·MS. KELLEY:··Yes.
·8·· · · · · · · ·JUDGE BURKHALTER:··And two record copies
·9··of exhibits?··I've got a bunch of paper up here, but I
10··just want to make sure.··Yes?
11·· · · · · · · ·MS. KELLEY:··Yes.
12·· · · · · · · ·JUDGE BURKHALTER:··Okay.··And, of course,
13··the court reporter as well.··Okay.··So you are State
14··Agencies --
15·· · · · · · · ·MS. KELLEY:··And it will be State Agency
16··No. 1, which includes a CD, which you've been given.··A
17··brief explanation about the CD --
18·· · · · · · · ·JUDGE BURKHALTER:··Wait just a second.
19··Let me get organized here.
20·· · · · · · · ·MS. KELLEY:··Okay.··Yes, sir.
21·· · · · · · · ·JUDGE BURKHALTER:··I have -- they're not
22··in order, I guess.··I've got State's Exhibit 1, 3 -- a
23··couple of State's Exhibit 3 and 16 and 13.
24·· · · · · · · ·MS. KELLEY:··Okay.
25·· · · · · · · ·JUDGE BURKHALTER:··And 13.
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·1·· · · · · · · ·MS. KELLEY:··And 13, yes.
·2·· · · · · · · ·JUDGE BURKHALTER:··Is that the universe of
·3··exhibits you're wanting --
·4·· · · · · · · ·MS. KELLEY:··That is.··If you don't mind
·5··if I recover that No. 3.
·6·· · · · · · · ·JUDGE BURKHALTER:··I don't mind.
·7·· · · · · · · ·MS. KELLEY:··Because that means that
·8··someone else has got them.··Thank you.
·9·· · · · · · · ·A brief explanation about No. 1.··It is a
10··copy of the Company's response plus three addendum
11··responses all on that same disc to Staff's RFI 9-1.
12··Whenever we copy a CD that we've been provided with, as
13··was the case here, it's encrypted.··So the decryption
14··program is also on that disc, and the password -- yes,
15··sir.
16·· · · · · · · ·JUDGE BURKHALTER:··Wait, wait.··I have a
17··piece of paper that is State's Exhibit 1.
18·· · · · · · · ·MS. KELLEY:··Yes.··They go together.
19·· · · · · · · ·JUDGE BURKHALTER:··These go together?
20·· · · · · · · ·MS. KELLEY:··Yes.
21·· · · · · · · ·JUDGE BURKHALTER:··Okay.··All right.··Go
22··ahead.
23·· · · · · · · ·MS. KELLEY:··Okay.··The decryption
24··password is right on the front with no spaces, just as
25··you see here, and then you can read it very easily.
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·1·· · · · · · · ·JUDGE BURKHALTER:··Okay.··So -- well, go
·2··ahead.··You want to describe them all, and then we'll
·3··see if we have any objections.
·4·· · · · · · · ·MS. KELLEY:··Okay.··Exhibit 3 is a
·5··response to -- Company's response to State Agencies' RFI
·6··3-17, 13 is a response to State Agencies' RFI 10-6, and
·7··16 is a response to State Agencies' RFI 2-3.··We would
·8··offer those into evidence.
·9·· · · · · · · ·JUDGE BURKHALTER:··All right.··Any
10··objection to the admission of State's Exhibits 1, 3, 13,
11··and 16?
12·· · · · · · · ·MR. NEINAST:··Your Honor, if you could
13··give me just a minute.··I don't have them in front of
14··me.··If they're the same exhibits, I don't have a
15··problem.··I just need to --
16·· · · · · · · ·JUDGE BURKHALTER:··While he's looking, let
17··me ask you, Ms. Kelley.··You've given me an exhibit list
18··with 17 exhibits listed.
19·· · · · · · · ·MS. KELLEY:··Yes.
20·· · · · · · · ·JUDGE BURKHALTER:··Are you not offering
21··the remainder, or are you going to be offering them
22··later?
23·· · · · · · · ·MS. KELLEY:··They're coming in --
24·· · · · · · · ·JUDGE BURKHALTER:··All right.
25·· · · · · · · ·MS. KELLEY:··-- because I have some
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·1··questions about them.
·2·· · · · · · · ·JUDGE BURKHALTER:··Okay.
·3·· · · · · · · ·MR. NEINAST:··No objections, Your Honor.
·4·· · · · · · · ·JUDGE BURKHALTER:··All right.··They're
·5··admitted.
·6·· · · · · · · ·(Exhibit State Agencies Nos. 1, 3, 13, and
·7·· · · · · · · ·16 admitted)
·8·· · · · · · · ·JUDGE BURKHALTER:··Does anybody else want
·9··to take care of exhibits at this point?
10·· · · · · · · ·(No response)
11·· · · · · · · ·JUDGE BURKHALTER:··All right.··Opening --
12·· · · · · · · ·MR. NEINAST:··Before we get started --
13·· · · · · · · ·JUDGE BURKHALTER:··Yes, sir.
14·· · · · · · · ·MR. NEINAST:··We can do this later, but
15··the record from the rate case was not technically
16··carried forward into this docket, but there are a number
17··of documents that are in the record of the rate case
18··that I think are going to be -- or referenced or
19··relevant to this one.··So we would ask that you take
20··judicial notice of the record in Docket 39896 so that we
21··can use documents from that docket in this docket.
22·· · · · · · · ·JUDGE BURKHALTER:··Anybody object to that?
23·· · · · · · · ·(No response)
24·· · · · · · · ·JUDGE BURKHALTER:··All right.··So I think
25··we're ready for opening statements.··Mr. Neinast?
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·1·· · · · · · ··OPENING STATEMENT ON BEHALF OF
·2·· · · · · · ··APPLICANT ENTERGY TEXAS, INC.
·3·· · · · · · · ·MR. NEINAST:··Good morning, Your Honor.
·4··My name is Steve Neinast, and I'm counsel for Entergy
·5··Texas.··We appreciate the opportunity to make a brief
·6··opening statement.
·7·· · · · · · · ·In this case, ETI seeks authority to
·8··recover a total of approximately 8.75 million in rate
·9··case expenses incurred through September 30, 2012.
10··These costs include roughly 7.6 million incurred by the
11··Company and roughly 1.1 million incurred by the Cities.
12··The Company proposes to recover these amounts through a
13··three-year surcharge with a return on the unamortized
14··balance.··In addition, the Company seeks authority to
15··defer until the next rate case all rate case expenses
16··incurred after September 30, 2012.
17·· · · · · · · ·The Company's rate case expenses are
18··presented and supported by testimonies and exhibits of
19··Company witnesses Michael Considine and Stephen Morris,
20··and the Company responded to numerous RFIs regarding the
21··detail of those expenses in both this case and the rate
22··case in Docket No. 39896.
23·· · · · · · · ·The testimony and recommendations filed by
24··Staff and Intervenors were limited to relatively few
25··issues.··First, Staff filed testimony proposing a
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·1··slightly different allocation of the expenses.··The
·2··Company does not object to Staff's proposal.··On the
·3··other hand, Staff recommended that the Company not be
·4··permitted a return on the unamortized balance of the
·5··rate case expenses.
·6·· · · · · · · ·As explained in the Company's rebuttal
·7··testimony, rejecting the requested return component
·8··would prevent the Company from recovering the full cost
·9··of these expenses over time since it would simply do
10··away with any consideration of the time value of money.
11·· · · · · · · ·We're proposing to recover these costs
12··over three years rather than immediately in a lump sum.
13··With regard to the limited number of specific rate case
14··expenses challenged by Staff and Intervenors, the
15··Company addressed each category of cost in rebuttal
16··testimony to show that the challenged costs were
17··reasonable.
18·· · · · · · · ·Finally, State Agencies and OPC recommend
19··global and novel disallowances based on unprecedented
20··methods of determining rate case expense recovery.··In
21··particular, they seek to require that admittedly
22··reasonable and necessary costs of preparing and
23··participating in a rate case be disallowed and borne by
24··shareholders.··Based on these novel policy-based
25··disallowances, State Agencies and OPC recommend
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·1··disallowances ranging from roughly 1.3 million to 6.4
·2··million, representing disallowances of from 14.5 percent
·3··to 73.6 percent of ETI's rate case expenses.
·4·· · · · · · · ·This range of disallowances bears no
·5··relationship to those very charges challenged as
·6··unreasonable by State Agencies and OPC and no
·7··relationship to the reasonable cost of preparing and
·8··prosecuting this case.··These claims should be rejected.
·9·· · · · · · · ·Moreover, these proposals represent a
10··radical departure from established Commission precedent.
11··For example, in the Commission's last litigated rate
12··case expense docket, which was AEP Texas Central, Docket
13··No. 31433.··The Commission allowed the utility to
14··recover all the rate case expenses found to be
15··reasonable and necessary and did not require that
16··shareholders bear any portion of those costs via any
17··sort of policy-based sharing.··Such an approach is at
18··odds -- the approach that OPC and the State Agencies
19··propose is at odds with the provisions of PURA allowing
20··the Company to recover its reasonable and necessary
21··expense incurred to prosecute rate cases.
22·· · · · · · · ·OPC and State Agencies have not shown why
23··the Commission should start using a different approach
24··in this case, an approach that has no connection to
25··whether cost incurred was a reasonable cost in the
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·1··context of the given case.
·2·· · · · · · · ·It is important to understand ETI's rate
·3··case expenses are driven by the Commission's RFP
·4··requirements and the fact that the utility has the
·5··burden of proof to justify all of its requested
·6··revenues, not just the requested rate increase, with an
·7··even heightened standard applied to the Company's
·8··affiliate expenses.
·9·· · · · · · · ·ETI has filed three rate cases in the last
10··five years, each of those cases, either through
11··settlement or litigation, resulted in a rate increase.
12··To now adopt a new rate case expense paradigm that would
13··disallow actual incurred costs shown to be reasonable is
14··simply punitive and confiscatory.
15·· · · · · · · ·It is also important to note that ETI has
16··attempted, in these past three rate cases, to implement
17··ratemaking mechanisms that would reduce the number of
18··rate cases that the Company needs to file in an attempt
19··to recover its actual cost of service.··These include
20··purchase capacity recovery factors and a formula rate
21··plan.··But the parties that here seek to disallow
22··reasonable rate case expenses vigorously oppose ETI's
23··attempts to implement purchase capacity and formula rate
24··plan mechanisms.··It is surprising that State Agencies
25··and OPC argue that ETI's rate case expenses should be
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·1··drastically disallowed even when reasonable, while on
·2··the other hand opposing the very rate case streamlining
·3··mechanism that would have mitigated those expenses.
·4·· · · · · · · ·As everyone in this room is aware, the
·5··ratemaking scheme in place today is very work intensive.
·6··For example, ETI was served with over 1,900 RFI
·7··questions, including subparts, in the base rate case.
·8··We needed 19 witnesses with subject matter expertise to
·9··present our affiliate case.··If a utility is
10··under-recovering its costs, it has no choice but to file
11··another base rate case.··And given ETI's recent history
12··with the three rate cases, it really can't be disputed
13··that our revenue requirements have been scrutinized and
14··scrutinized again to ensure that we are not
15··over-recovering.··In fact, given the purchase capacity
16··disallowances in the last rate case, we were already
17··under-recovering our costs on the first day of the rate
18··year.
19·· · · · · · · ·In summary, the policy disallowances
20··approach advocated by State Agencies and OPC is novel,
21··contrary to longstanding Commission precedent, punitive
22··and confiscatory.··The better approach to addressing
23··State Agencies' and OPC's concerns would be to
24··streamline the ratemaking paradigm currently in place.
25··Accordingly, the Company respectfully requests that it
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·1··be authorized to recover its requested rate case
·2··expenses through a three-year surcharge, with a return
·3··on the unamortized balance.··Thank you.
·4·· · · · · · · ·JUDGE BURKHALTER:··Thank you.··Mr. Mack?
·5·· · · · ··OPENING STATEMENT ON BEHALF OF CITIES
·6·· · · · · · · ·MR. MACK:··Thank you, Your Honor.··Stephen
·7··Mack for Cities.··Cities in this case are requesting
·8··reimbursement from ETI of their rate case expenses
·9··pursuant to PURA Section 33.023.··Those rate case
10··expenses are set out in the direct testimony of Amy
11··Hodgins, and we're requesting a finding of
12··reasonableness and that they be reimbursed.··Thank you.
13·· · · · · · · ·JUDGE BURKHALTER:··And the amount is what?
14·· · · · · · · ·MR. MACK:··The amount is 1.2 million,
15··which is actual expenses and estimated expenses for the
16··Long Law Firm and eight consulting firms.
17·· · · · · · · ·JUDGE BURKHALTER:··Thank you.··Ms. Ferris?
18·· · · · · · ··OPENING STATEMENT ON BEHALF OF
19·· · · · · ·THE OFFICE OF PUBLIC UTILITY COUNSEL
20·· · · · · · · ·MS. FERRIS:··Thank you, Your Honor.··This
21··is a rate case expense docket, not a rulemaking
22··regarding how rates are set at the Commission.
23·· · · · · · · ·However, the one thing that OPC is really
24··asking the Commission to do in this case is to exercise
25··its discretion under PURA 36.061 to decide what
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·1··reasonable expenses should be allowed to be recovered by
·2··the Company.··Traditionally this exercise has looked at
·3··accounting entries and there's nothing wrong with that.
·4··That's appropriate.··But it's not the limit of what the
·5··Commission's discretion is.
·6·· · · · · · · ·OPC is asking the Commission to look at
·7··other considerations when they set what the reasonable
·8··rate case expenses to be recovered are.··And the
·9··testimony of Nathan Benedict outlines some of the
10··reasonable considerations that the Commission should
11··look at, and we ask them to look at.··And that may
12··include frequency of how they come in.··It could be what
13··the award was versus how much the expense was.··It could
14··be was longstanding precedent challenged.··There are
15··other things.··That's not the limit of the Commission's
16··discretion.··It's fairly broad.··And we are asking the
17··Commission to exercise their discretion in this case.
18··Thank you.
19·· · · · · · · ·JUDGE BURKHALTER:··Thank you.··Ms. Kelley?
20·· · ··OPENING STATEMENT ON BEHALF OF STATE AGENCIES
21·· · · · · · · ·MS. KELLEY:··Yes, Your Honor.··You know,
22··I've been thinking in this case as I've reviewed some of
23··the evidence that's been submitted and a lot of what's
24··on State Agencies No. 1.
25·· · · · · · · ·I've had occasion, a lot of times,
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·1··traveling to Southeast Texas to visit relatives, and
·2··I've been mindful as I review those documents about one
·3··of my favorite political commentators, Paul Burka, has
·4··said about the Texas Legislation.··They imply something
·5··called a Bubba factor to the legislation, and it's
·6··basically how would the ordinary person feel about the
·7··practical effects of what we're asking them to do.
·8·· · · · · · · ·So I've asked myself as I've reviewed
·9··these costs how would Bubba the ratepayer feel about $7
10··cab fares by law firm staffers from the PUC back to the
11··law firm that's only a few blocks away and on a main
12··baseline?··How would the ratepayer feel about frequent
13··courier service to deliver copies when email or fax
14··would suffice?··How would the ratepayer feel about ten
15··outside lawyers on a case, in addition to internal
16··staff, many of whom merely sit observing during a
17··hearing, even though that same law firm orders overnight
18··transcripts of the hearing that could be consulted when
19··needed?
20·· · · · · · · ·How would the ratepayer feel about
21··furnishing ordinary snacks for the workday, bottled
22··water and catered lunches for employees that otherwise
23··would have to pay for that themselves?··How would the
24··ratepayer feel about paying not just for the salaries of
25··company people who work on rate cases, but for so-called
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·1··loaders who try and load in indirect costs and pass
·2··along the costs of buildings and equipment, if we can
·3··load in depreciation, can mortgage payments be much
·4··farther behind?
·5·· · · · · · · ·Now, I know the argument will be made
·6··that -- and sort of has been made already by the
·7··Company -- as if the burden of proof is on the
·8··Intervenors to kind of fly through this with more
·9··limited resources than the available to the Company to
10··come up with dollar amounts.··And I know there will be
11··considerable verbiage that we have "only" -- I put air
12··quotes, Mr. Court Reporter -- identified small costs
13··against nearly $10 million.··And that's -- it's nearly
14··10 million if you include the carrying charges they
15··seek.
16·· · · · · · · ·JUDGE BURKHALTER:··Include what?··Courier
17··charges?··Or did you say --
18·· · · · · · · ·MS. KELLEY:··Carrying charges.
19·· · · · · · · ·JUDGE BURKHALTER:··Carrying charges?
20·· · · · · · · ·MS. KELLEY:··Yes.··I'm sorry.
21·· · · · · · · ·JUDGE BURKHALTER:··Thank you.
22·· · · · · · · ·MS. KELLEY:··If you include the carrying
23··charges the Company seeks, we're approaching close to 10
24··million.
25·· · · · · · · ·But I would ask the Administrative Law
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·1··Judge to consider that given a reliance that Mr. Morris
·2··and Mr. Considine placed in their testimony, what
·3··they've described as kind of a vast and supposedly
·4··pinpoint accurate ETI cost review process -- it's no
·5··small matter if the Intervenors, with their considerable
·6··and less resources, have shown that even the allegedly
·7··small areas -- errors or unnecessary and unreasonable
·8··expenses exist.··It should cause one to believe that
·9··it's fairly easy to catch errors that are made.··Even in
10··the bill review process, it should call into question
11··the integrity of ESI's whole cost review system, but we
12··don't have the opportunity to see.
13·· · · · · · · ·Let's keep in mind that none of our state
14··regulators in any state ever sees the total picture of
15··the cost or indirect costs that are passed down to
16··ratepayers.··They're different test years.··A lot of it
17··is under seal -- most of it is under seal.··And the
18··Company's assertion through witnesses who are largely
19··pretty interested in the outcome of an infallible system
20··that passes along only reasonable costs is, in essence,
21··just a variation of "trust us."
22·· · · · · · · ·I think this is why the legislation has
23··given the Commission discretion to consider, on a
24··case-by-case basis, the entire range of what's gone on
25··in a case and whether or not the services for which the
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·1··ratepayers seem to be held responsible are justified to
·2··be passed through.
·3·· · · · · · · ·That's one reason we've proposed what's
·4··described as a radical approach.··I would put forward
·5··it's not any more radical than some of the -- what Texas
·6··disciplinary rules of professional conduct require
·7··attorneys -- requires factors to be considered in
·8··determining the reasonableness of a fee, and one of
·9··those factors is the amount involved in the results
10··obtained.
11·· · · · · · · ·We're simply asking that the investor be
12··given some skin in the game, and we think it's long
13··overdue.··Right now shareholders have nothing to lose.
14··They have no incentive to review the frequency and scope
15··of ratemaking and ancillary proceedings, for which costs
16··are also sought in base rate cases.··They have no
17··incentive to do that, but simply pass along cost of
18··whatever nature to the ratepayer.
19·· · · · · · · ·If they're given some interest --
20··financial interest, they may more closely scrutinize the
21··priorities that the Company management decides to pursue
22··in rate cases and in ancillary proceedings.
23·· · · · · · · ·You'll notice for example -- let's compare
24··and contrast the capable folks who work for the Cities.
25··For their fees, which are considerably smaller
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·1··percentage than the rate cases that Entergy is seeking,
·2··they achieve a far greater return on the dollars they
·3··spend.··They put their priorities and limited resource
·4··to good use, but most importantly you'll also notice
·5··that the Texas Industrial Energy Consumers, whose
·6··members are actually paying the rate case expense -- it
·7··isn't passed on -- they do a very successful and
·8··efficient job on presenting targeted review.
·9·· · · · · · · ·Finally, in concluding the statute, to
10··emphasize again -- it can't be emphasized enough --
11··gives the Commission discretion, they may allow
12··reasonable cost of participating.··So they're not
13··confined just to analyzing whether or not something is
14··reasonable.··They can look at costs and say, "Sure, that
15··was reasonable, but in this case, it's excessive."
16·· · · · · · · ·And that's what we're asking the
17··Administrative Law Judge, as well as the Commission, to
18··ultimately do.··Thank you.
19·· · · · · · · ·JUDGE BURKHALTER:··Thank you.
20·· · · · · · ··OPENING STATEMENT ON BEHALF OF
21·· · · · · ··TEXAS INDUSTRIAL ENERGY CONSUMERS
22·· · · · · · · ·MS. GRIFFITHS:··Your Honor, my comments
23··will be very brief.··We agree with the State and the
24··Office of Public Utility Commission that the recovery of
25··rate case expenses under PURA is discretionary, it's not
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·1··mandatory, and that the Commission has broad authority
·2··to determine what constitutes reasonable rate case
·3··expenses.··We think that the State and OPUC and Staff
·4··have raised good arguments and that you should consider
·5··them in this case.
·6·· · · · · · · ·JUDGE BURKHALTER:··Thank you.··Mr. Foley?
·7·· · · · · · · ·MR. FOLEY:··Staff has no opening
·8··statement, Your Honor.
·9·· · · · · · · ·JUDGE BURKHALTER:··All right.
10··Mr. Neinast, you may proceed.
11·· · · · · · · ·MR. NEINAST:··Thank you, Your Honor.
12··Commission calls to the stand Mr. Michael Considine.
13·· · · · · · · ·(Witness Considine sworn)
14·· · · · · · · ·JUDGE BURKHALTER:··Tell me your name
15··again, ma'am.
16·· · · · · · · ·MS. RIZVI:··Wajiha Rizvi representing
17··Entergy Texas.
18·· · · · · · · ·JUDGE BURKHALTER:··Would you spell that
19··last name?
20·· · · · · · · ·MS. RIZVI:··Sure.··It's R-I, Z as in
21··zebra, V as in Victor, I.
22·· · · · · · · ·JUDGE BURKHALTER:··Thank you.··Whenever
23··you're ready.
24·· · · · · · · ·MS. RIZVI:··Thank you, Your Honor.
25··
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·1·· · ··PRESENTATION ON BEHALF OF ENTERGY TEXAS, INC.
·2·· · · · · · · · ··MICHAEL P. CONSIDINE,
·3··having been first duly sworn, testified as follows:
·4·· · · · · · · · · ··DIRECT EXAMINATION
·5··BY MS. RIZVI:
·6·· · ·Q· ··Good morning.
·7·· · ·A· ··Good morning.
·8·· · ·Q· ··Please state your name for the record.
·9·· · ·A· ··Michael Considine.
10·· · ·Q· ··Mr. Considine, do you have before you a number
11··of documents marked Entergy Texas Exhibits 1 through 7?
12·· · ·A· ··I do.
13·· · ·Q· ··Okay.··And can you go through and identify
14··these exhibits, please?
15·· · ·A· ··Exhibit 1 is my direct testimony from
16··Docket 39896 filed in November of 2011.··It's actually a
17··redacted version of that.
18·· · · · · · · ·Exhibit No. 2 is Schedule G-14.1 from
19··Docket 39896.
20·· · · · · · · ·Exhibit 3 is the rate case expense rider
21··and cost allocation tariff and supporting workpapers.··I
22··don't have the date that that was filed, but it was
23··sometime in October of this year.
24·· · · · · · · ·Exhibit 4 is my supplemental direct
25··testimony filed in March of 2012 in Docket 39896.
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·1·· · · · · · · ·Exhibit 5 is supplemental direct testimony
·2··filed in October of 2012 in Docket 40295.
·3·· · · · · · · ·Exhibit 6 is another set of supplemental
·4··direct testimony filed in Docket 40295 on October 25th,
·5··2012.
·6·· · · · · · · ·And Exhibit 7 is my rebuttal testimony
·7··filed in Docket 40295 filed on November 15th, 2012.
·8·· · ·Q· ··Thank you.··And were these documents prepared
·9··by you or under your direct supervision?
10·· · ·A· ··Yes, they were.
11·· · ·Q· ··And if I were to ask you the same questions
12··that are in your testimony today, would your responses
13··be the same?
14·· · ·A· ··Yes, they would.
15·· · · · · · · ·MS. RIZVI:··Your Honor, the Company moves
16··to admit Entergy Texas Exhibits 1 through 7.
17·· · · · · · · ·JUDGE BURKHALTER:··Any objection?
18·· · · · · · · ·(No response)
19·· · · · · · · ·JUDGE BURKHALTER:··They're admitted.
20·· · · · · · · ·(Exhibit ETI Nos. 1 through 7 admitted)
21·· · · · · · · ·MR. NEINAST:··At this time, I'd like to
22··tender the witness for cross.
23·· · · · · · · ·MR. MACK:··Cities have no questions.
24·· · · · · · · ·JUDGE BURKHALTER:··Ms. Ferris?
25·· · · · · · · ·MS. FERRIS:··Yes, I do have question, Your
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·1··Honor.
·2·· · · · · · · ·JUDGE BURKHALTER:··I'm sorry.··We're going
·3··to wait on you.
·4·· · · · · · · ·MS. KELLEY:··Are you going to go before
·5··Staff?
·6·· · · · · · · ·MS. FERRIS:··Right before Staff.
·7·· · · · · · · ·MS. KELLEY:··Okay.
·8·· · · · · · · ·JUDGE BURKHALTER:··So Ms. Kelley.
·9·· · · · · · · · · ··CROSS-EXAMINATION
10··BY MS. KELLEY:
11·· · ·Q· ··Mr. Considine, I just have a few questions.··If
12··we can turn to your supplemental direct -- and I think
13··both of them probably have the same page -- pagination.
14··Beginning on Page 3, 19 --
15·· · · · · · · ·JUDGE BURKHALTER:··I'm sorry, Ms. Kelley.
16··What exhibit are you in?
17·· · · · · · · ·MS. KELLEY:··Yeah, I've got to --
18·· · · · · · · ·JUDGE BURKHALTER:··Did you say his direct
19··testimony?
20·· · · · · · · ·MS. KELLEY:··It would be his supplemental
21··direct testimony, Exhibit 5.
22·· · ·A· ··Which page?
23·· · ·Q· ··(BY MS. KELLEY)··Let's look at Exhibit 6,
24··because that's the one I've got.··Exhibit 6, your
25··supplemental direct.··And if we can start with Page 3 at
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·1··Line 19.··It appears -- is it fair to say that your main
·2··basis for concluding that costs are reasonable and
·3··necessary in this case is the system that ESI has in
·4··place for review of the costs?
·5·· · ·A· ··Yes, ma'am, the internal controls of the
·6··Company are heavily weighed upon when deciding that the
·7··costs are reasonable and necessary.
·8·· · ·Q· ··Okay.
·9·· · · · · · · ·JUDGE BURKHALTER:··Ms. Kelley, I'm sorry
10··to interrupt.··Ms. Rizvi, I have a question for you.
11·· · · · · · · ·MS. RIZVI:··Yes.
12·· · · · · · · ·JUDGE BURKHALTER:··So Exhibit 5 is
13··supplemental direct testimony of Michael Considine.
14··Exhibit 6 is supplemental direct testimony of Michael
15··Considine.··Are they different?
16·· · · · · · · ·MS. RIZVI:··Yes, Your Honor.··These
17··supplemental direct testimonies provided updates, so
18··it's actually best to identify them by date.··I think
19··that would make that a little bit more clear.
20·· · · · · · · ·MS. KELLEY:··Right.··I'm using the October
21··25th.
22·· · · · · · · ·MS. RIZVI:··Yeah, the October 25th one is
23··the one we're referring to now.
24·· · · · · · · ·JUDGE BURKHALTER:··All right.
25·· · ·Q· ··(BY MS. KELLEY)··And so to be clear, you
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·1··yourself did not go through each one of these line items
·2··that are part of ETI's overall rate case requests.··Is
·3··that fair to say?
·4·· · ·A· ··Which line items are you referring to?
·5·· · ·Q· ··Well, anything that would be on your Schedules
·6··MPC-R-1 -- anything that constitutes a rate case expense
·7··that's percolated up to you.··You didn't review each and
·8··every individual entry, did you?
·9·· · ·A· ··No, ma'am, I did not.··I did review several of
10··the invoices that are presented here.
11·· · ·Q· ··I understand.
12·· · ·A· ··And other people that work for the Company
13··reviewed the other pieces, yes, ma'am.
14·· · ·Q· ··But I know you recite this to me, along with
15··various other people, Mr. Gardner -- you have heavy
16··reliance on what they have to say about their review of
17··those costs.··Is that fair to say?
18·· · ·A· ··I do, as well as the controls the Company has
19··in place.
20·· · ·Q· ··Okay.··I want to show you what I've marked as
21··State's Exhibit No. 4.
22·· · · · · · · ·(Exhibit State Agencies No. 4 marked)
23·· · · · · · · ·MS. KELLEY:··And I apologize.··Our
24··administrative assistant is out sick today, sad to say,
25··so it's all up to me.
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·1·· · ·Q· ··(BY MS. KELLEY)··Now, is this an RFI response
·2··that you sponsored regarding purchased power capacity
·3··rider costs?
·4·· · ·A· ··Yes, ma'am.
·5·· · · · · · · ·MS. KELLEY:··I offer this into evidence,
·6··Your Honor.
·7·· · · · · · · ·JUDGE BURKHALTER:··Any objection to the
·8··admission of Exhibit 4?
·9·· · · · · · · ·(No response)
10·· · · · · · · ·JUDGE BURKHALTER:··It's admitted.
11·· · · · · · · ·(Exhibit State Agencies No. 4 admitted)
12·· · ·Q· ··(BY MS. KELLEY)··So is it fair to say the
13··system on which you relied in determining the fair and
14··reasonable cost related to purchase power has no way to
15··break out the costs that are specifically related to
16··that issue?
17·· · ·A· ··That's correct.··Employees charge their time
18··and expenses to a rate case project code that's set up
19··specifically for Docket 39896.
20·· · ·Q· ··But not issue specific?
21·· · ·A· ··No, ma'am.
22·· · ·Q· ··Now I'm going show you what I've marked as
23··State Agencies Exhibit No. 9.
24·· · · · · · · ·JUDGE BURKHALTER:··Ms. Kelley, do you have
25··a batch of exhibits you want to cover with this witness?
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·1··If you want to go ahead and hand them all out.
·2·· · · · · · · ·MS. KELLEY:··Okay.··I've got some of them
·3··separated.··Next time I make a pass, I'll bring them all
·4··up.
·5·· · · · · · · ·(Exhibit State Agencies No. 9 marked)
·6·· · ·Q· ··(BY MS. KELLEY)··Is this also an RFI response
·7··that you sponsored?
·8·· · ·A· ··Yes, ma'am, as well as Mr. Morris.
·9·· · ·Q· ··Okay.··And does it set out all the adjustments
10··that ETI has made to its rate case expense since direct
11··testimony was filed?
12·· · ·A· ··If you'll give me a second to just review it.
13·· · ·Q· ··Sure.
14·· · ·A· ··Yes, ma'am, it appears to.
15·· · ·Q· ··And can you tell me, sir, where those
16··adjustments have been made in this case?
17·· · ·A· ··If we would refer to my exhibit in the same set
18··of testimony, Exhibit -- well, it's marked as Page 8 in
19··Exhibit 6.
20·· · ·Q· ··And that would be the October 25th --
21·· · ·A· ··Yes, ma'am.
22·· · ·Q· ··-- testimony?
23·· · · · · · · ·Okay.··For example, on Exhibit No. 9, if
24··you look on the second page, I believe that one thing
25··you said has come out -- if you look about midway down
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·1··that addendum response, "The Company has excluded
·2··$582.02, the total amount by which the charges for meals
·3··exceeded $25 per person, per meal."
·4·· · ·A· ··Yes, ma'am.
·5·· · ·Q· ··Can you show me where that particular deduction
·6··has been made on your schedule?
·7·· · ·A· ··I believe that that -- if you -- it does not
·8··have line numbers, but if you look under the Company --
·9··or the consultant's bucket, there's a less
10··non-conforming expenses line for $22.
11·· · ·Q· ··Okay.
12·· · ·A· ··That plus the $560 of non-conforming expenses
13··down in the internal rate case expense line --
14·· · ·Q· ··Okay.
15·· · ·A· ··-- is the $582.
16·· · ·Q· ··Okay.··Now I'm going to show you what I've
17··marked as Exhibit No. 5.
18·· · · · · · · ·JUDGE BURKHALTER:··Would you like to have
19··9 admitted?
20·· · · · · · · ·MS. KELLEY:··Yes, I would like to have 9
21··admitted, Your Honor.
22·· · · · · · · ·JUDGE BURKHALTER:··Any objection to 9?
23·· · · · · · · ·(No response)
24·· · · · · · · ·JUDGE BURKHALTER:··It's admitted.
25·· · · · · · · ·(Exhibit State Agencies No. 9 admitted)
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·1·· · · · · · · ·MS. KELLEY:··And I'm going to bring you up
·2··number -- I'm going to bring up a few others at the same
·3··time.
·4·· · · · · · · ·(Exhibit State Agencies Nos. 5 and 11
·5·· · · · · · · ·marked)
·6·· · · · · · · ·MS. KELLEY:··Your Honor, I'm a little
·7··short on No. 12, but I'll bring them up in a minute.
·8·· · · · · · · ·(Exhibit State Agencies No. 12 marked)
·9·· · ·Q· ··(BY MS. KELLEY)··Okay.··If I can ask you to
10··look at Exhibit No. 5 --
11·· · ·A· ··Yes, ma'am.
12·· · ·Q· ··-- Mr. Considine.··Is this an RFI response that
13··you and Mr. Morris co-sponsored?
14·· · ·A· ··Yes, it is.
15·· · ·Q· ··And was it a response to Staff about how many
16··meals exceeded $25?
17·· · · · · · · ·MS. RIZVI:··Excuse me.··I did not get
18··Exhibit No. 5.
19·· · · · · · · ·MS. KELLEY:··I'm sorry.··Okay.
20·· · ·A· ··Yes, ma'am, that's what it appears to be.
21·· · ·Q· ··(BY MS. KELLEY)··Now, were you relying on the
22··same system that you did for review of costs to identify
23··these meals?
24·· · ·A· ··Yes, ma'am.
25·· · ·Q· ··Did you personally go through the receipts to
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·1··try and pull these meals out?
·2·· · ·A· ··I did not.··People that work for the Company
·3··did, though, yes, ma'am.
·4·· · ·Q· ··Okay.
·5·· · · · · · · ·MS. KELLEY:··I'd like to offer Exhibit
·6··No. 5, Your Honor.
·7·· · · · · · · ·JUDGE BURKHALTER:··Any objection?
·8·· · · · · · · ·(No response)
·9·· · · · · · · ·JUDGE BURKHALTER:··It's admitted.
10·· · · · · · · ·(Exhibit State Agencies No. 5 admitted)
11·· · ·Q· ··(BY MS. KELLEY)··Now, Mr. Considine, if we can
12··pull out Exhibit No. 12.··By the way, do you think it's
13··possible that on Exhibit No. 5 some of those meals got
14··overlooked?··That there may be more meals out there over
15··$25 that the Company didn't disclose on its answer to
16··No. 5?
17·· · ·A· ··No, ma'am, I don't.
18·· · ·Q· ··Okay.··Can you turn to Exhibit No. 12?··Is this
19··an RFI response that you sponsored when Staff requested
20··some additional invoices from Duggins Wren Mann &
21··Romero's May 15th invoice?
22·· · ·A· ··Yes, it is.
23·· · ·Q· ··Okay.··Now, Mr. Considine, can we turn to --
24··what's numbered as Page 3 down in the corner?
25·· · ·A· ··Okay.
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·1·· · ·Q· ··Does it appear that these receipts include a
·2··request for reimbursement from Duggins Wren attorney
·3··Scott Olson?
·4·· · ·A· ··It appears that way.
·5·· · ·Q· ··Okay.··Could you please flip to Page No. 7,
·6··sir?··Now we appear to have some restaurant receipts.
·7··Can you identify if there are any meals on Page 7 that
·8··are in excess of $25?
·9·· · ·A· ··Yes, there are.··There are -- well, exactly
10··three.
11·· · ·Q· ··Okay.··Can you find those in the response to
12··RFI 9-9, shown on State's Exhibit No. 5?··Are they
13··listed on that exhibit?
14·· · ·A· ··I'll have to review State 5 again.
15·· · ·Q· ··Okay.
16·· · ·A· ··I do not see those specifically, no, ma'am.
17·· · ·Q· ··Okay.··So those aren't on here, and that's just
18··one invoice, then.
19·· · · · · · · ·MS. KELLEY:··Your Honor, I'd like to offer
20··State Agency Exhibit No. 12.
21·· · · · · · · ·JUDGE BURKHALTER:··Any objection?
22·· · · · · · · ·(No response)
23·· · · · · · · ·JUDGE BURKHALTER:··It's admitted.
24·· · · · · · · ·(Exhibit State Agencies No. 12 admitted)
25·· · ·Q· ··(BY MS. KELLEY)··Now, do you have State's
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·1··Exhibit No. 11?··Is that one of the ones I brought up
·2··there?
·3·· · ·A· ··I do.
·4·· · ·Q· ··Good.··Okay.··Is this also an RFI response that
·5··you sponsored?
·6·· · ·A· ··Along with Mr. Morris, yes.
·7·· · · · · · · ·MS. KELLEY:··Okay.··Your Honor, I'd like
·8··to offer this into evidence.
·9·· · · · · · · ·JUDGE BURKHALTER:··Any objection?
10·· · · · · · · ·(No response)
11·· · ·Q· ··(BY MS. KELLEY)··Now, is it fair to say --
12·· · · · · · · ·JUDGE BURKHALTER:··Hang on a second.··Let
13··me make sure there's no objection.
14·· · · · · · · ·MS. KELLEY:··Okay.
15·· · · · · · · ·JUDGE BURKHALTER:··Ms. Rizvi, do you have
16··any objection to Exhibit 11?
17·· · · · · · · ·MS. RIZVI:··No, Your Honor.
18·· · · · · · · ·JUDGE BURKHALTER:··It's admitted.
19·· · · · · · · ·(Exhibit State Agencies No. 11 admitted)
20·· · ·Q· ··(BY MS. KELLEY)··Is it fair to say that the
21··Company doesn't regard those items as luxury items, that
22··that's the gist of your answer?
23·· · ·A· ··Yes, ma'am.··Bottled water, the Company in this
24··RFI doesn't consider to be a luxury item.
25·· · ·Q· ··Okay.··But I think that response says that all
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·1··of those items at this point the Company doesn't agree
·2··are luxury items.··Is that fair to say?
·3·· · ·A· ··It says, "The Company disagrees with the
·4··premise that each of the examples in this question
·5··constitute a luxury item."
·6·· · ·Q· ··Okay.··And is it fair to say that there hasn't
·7··been a deduction from rate case expense for any of these
·8··items?
·9·· · ·A· ··For the two items listed here, the --
10·· · ·Q· ··Well, for any items that would --
11·· · ·A· ··-- $5 --
12·· · ·Q· ··-- qualify as luxury items; bottled water --
13·· · · · · · · ·JUDGE BURKHALTER:··You're referring to the
14··items listed in your question.··Correct?
15·· · · · · · · ·MS. KELLEY:··Your Honor, I'm referring
16··to --
17·· · · · · · · ·JUDGE BURKHALTER:··The items listed in the
18··question, not in the response.··Is that correct?
19·· · · · · · · ·MS. KELLEY:··Yes, the items in the
20··question.··Yes, Your Honor.
21·· · ·A· ··The Company makes an effort to remove any items
22··like this.··I can't say that there are items like this
23··that the Company is requesting either.
24·· · ·Q· ··(BY MS. KELLEY)··And is it possible there may
25··be bottled water costs, for example, that were missed
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·1··that are not included on State Exhibit No. 11?
·2·· · ·A· ··Yes, ma'am, that's possible.
·3·· · ·Q· ··Out of curiosity, would you think that
·4··purchases of clothing by an attorney who is working on a
·5··case, should that be passed through as a rate case
·6··expense?
·7·· · ·A· ··No, ma'am, I wouldn't think so.
·8·· · · · · · · ·MS. KELLEY:··I have no further questions,
·9··Your Honor.··I pass the witness.
10·· · · · · · · ·JUDGE BURKHALTER:··All right.··Thank you.
11··Ms. Griffiths?
12·· · · · · · · ·MS. GRIFFITHS:··No questions, Your Honor.
13·· · · · · · · ·JUDGE BURKHALTER:··Ms. Ferris?
14·· · · · · · · ·MS. FERRIS:··Yes, Your Honor.··Thank you.
15·· · · · · · · ·(Exhibit OPUC No. 2 marked)
16·· · · · · · · · · ··CROSS-EXAMINATION
17··BY MS. FERRIS:
18·· · ·Q· ··Good morning, Mr. Considine.
19·· · ·A· ··Good morning.
20·· · ·Q· ··I've handed you what's been marked as OPUC
21··Exhibit No. 2.··Do you have it?
22·· · ·A· ··I do.
23·· · ·Q· ··And were you the sponsoring witness for two of
24··the three questions contained in this response?
25·· · ·A· ··I was.
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·1·· · ·Q· ··Thank you.··Question No. 3-1(c) asks you a
·2··question about Robert Cooper.··Is that correct?
·3·· · ·A· ··Yes, ma'am.
·4·· · ·Q· ··What was the subject of Robert Cooper's
·5··testimony?
·6·· · ·A· ··His overall direct testimony in the rate case?
·7·· · ·Q· ··Yes, sir.
·8·· · ·A· ··He discussed basically the system planning
·9··process for purchase power.
10·· · ·Q· ··Would you characterize him as a major witness
11··on the purchase power issue?
12·· · ·A· ··I would.
13·· · ·Q· ··Would that also include third party purchase
14··power agreements?
15·· · ·A· ··Yes, it would.
16·· · ·Q· ··And on the second question, 3-2, on Subquestion
17··(b), we ask you about the test -- about the attorney
18··Dick Westerburg.··Are you familiar with Mr. Westerburg?
19·· · ·A· ··I am.
20·· · ·Q· ··What's his title with the Company?
21·· · ·A· ··I don't know his specific title.··He's an
22··attorney with the Company.
23·· · ·Q· ··Okay.··He was the attorney who was in charge of
24··Mr. Cooper's testimony.··Is that correct?
25·· · ·A· ··I don't know that.
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·1·· · ·Q· ··Do you know whether he handled the direct
·2··examination of Mr. Cooper during the hearing on the
·3··merits in 39896?
·4·· · ·A· ··I was not in the room, so I don't know that he
·5··did.
·6·· · ·Q· ··Do you know if he was the attorney for the
·7··deposition of Mr. Cooper in that docket?
·8·· · ·A· ··I do not.
·9·· · ·Q· ··Regarding Mr. Cooper's testimony, I believe
10··your response to Question (b) of 3-1 was that -- well,
11··actually, more generally in Question (c) and
12··Question (b), did the Company respond that they did
13··not -- could not reasonably estimate the percentage of
14··expenses related to capacity purchase?··Is that right?
15·· · ·A· ··That's a fair statement.
16·· · ·Q· ··And they could not -- you could not tell us
17··what part of Mr. Cooper's expenses related to his
18··testimony were related to purchase power or to third
19··party purchase power agreements.··Is that right?
20·· · ·A· ··That's correct.··The Company tracks time on a
21··project level basis, and the entire project related to
22··the rate case as a whole.
23·· · ·Q· ··And we asked you to make the best efforts to
24··estimate the percentage of time, and the Company was not
25··able to do so.··Is that right?
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·1·· · ·A· ··Yes, ma'am.··I personally was not going to
·2··guess.
·3·· · ·Q· ··Okay.··And the same is true for the time of
·4··Mr. Westerburg.··Is that correct?
·5·· · ·A· ··That's correct.
·6·· · · · · · · ·MS. FERRIS:··Your Honor, at this time, we
·7··offer OPUC Exhibit No. 2.
·8·· · · · · · · ·JUDGE BURKHALTER:··Any objection?
·9·· · · · · · · ·(No response)
10·· · · · · · · ·JUDGE BURKHALTER:··It's admitted.
11·· · · · · · · ·(Exhibit OPUC No. 2 admitted)
12·· · · · · · · ·MS. FERRIS:··And I pass the witness.
13·· · · · · · · ·JUDGE BURKHALTER:··Mr. Foley?
14·· · · · · · · ·MR. FOLEY:··Staff has no questions.
15·· · · · · · · ·JUDGE BURKHALTER:··Okay.··Redirect?
16·· · · · · · · ·MS. RIZVI:··Thank you.
17·· · · · · · · · · ·REDIRECT EXAMINATION
18··BY MS. RIZVI:
19·· · ·Q· ··Mr. Considine, going back to State Agencies
20··Exhibit No. 5.··Would you pull that up?
21·· · ·A· ··I have it.
22·· · ·Q· ··Okay.··So these amounts and these charges that
23··you see, do you know whether these are the total meals
24··going over $25 or the amount by which it goes over $25?
25·· · ·A· ··It's just the incremental amount above $25.
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·1·· · ·Q· ··So these are not the totals?
·2·· · ·A· ··That's my understanding.
·3·· · ·Q· ··Counsel for OPC just now was asking you the
·4··subject matter of Mr. Cooper's testimony.··Do you
·5··know -- could you repeat that, the subject matter that
·6··his testimony covers?
·7·· · ·A· ··Mr. Cooper basically covers system planning as
·8··a whole for generation.
·9·· · ·Q· ··Would you say that's a wide breadth of areas
10··covered?
11·· · ·A· ··Yes, it is.
12·· · ·Q· ··And do you know the position that Mr. Cooper
13··holds with the Company?
14·· · ·A· ··I believe he's the manager of generation
15··planning I think is his specific title.
16·· · ·Q· ··Okay.··Now, can you please explain how Company
17··employees charge their time to the rate case project
18··code?
19·· · ·A· ··Sure.··For an example, I, myself, am an Entergy
20··Services employee and charge time based on the hours I
21··spend to the specific project code set up for this rate
22··case, and that time is billed 100 percent to Entergy
23··Texas, because it's a Texas specific rate case.··My time
24··is approved by my supervisor.··I have direct supports
25··that I approve time for.··So there are internal controls
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·1··within the Company to make sure that the time being
·2··reported by every employee is correctly charged.··And
·3··the only dollars that the Company is requesting in this
·4··docket are the charges charged to that specific project
·5··code.··There's no double recovery, if you will, that's
·6··being suggested.
·7·· · · · · · · ·MS. RIZVI:··Pass the witness.
·8·· · · · · · · ·JUDGE BURKHALTER:··Mr. Mack?
·9·· · · · · · · ·MR. MACK:··No questions.
10·· · · · · · · ·JUDGE BURKHALTER:··Ms. Kelley?
11·· · · · · · · ·MS. KELLEY:··No questions.
12·· · · · · · · ·JUDGE BURKHALTER:··Ms. Griffiths?
13·· · · · · · · ·MS. GRIFFITHS:··No questions.
14·· · · · · · · ·JUDGE BURKHALTER:··Ms. Ferris?
15·· · · · · · · ·MS. FERRIS:··Yes, Your Honor.
16·· · · · · · · ·JUDGE BURKHALTER:··Go ahead.
17·· · · · · · · · · ·RECROSS-EXAMINATION
18··BY MS. FERRIS:
19·· · ·Q· ··Mr. Considine, your attorney just asked you a
20··follow-up question regarding the subject matter of
21··Mr. Cooper's testimony.··Do you recall that?
22·· · ·A· ··Yes, I do.
23·· · ·Q· ··Purchase power was a large part of the request
24··that was sponsored by -- that was sponsored by
25··Mr. Cooper.··Is that correct?
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·1·· · · · · · · ·MS. RIZVI:··Objection, Your Honor.
·2··Counsel is testifying.
·3·· · · · · · · ·JUDGE BURKHALTER:··Overruled.
·4·· · ·A· ··Can you repeat the question?
·5·· · ·Q· ··(BY MS. FERRIS)··Yes.··Purchase power was a
·6··large portion of that system planning testimony that
·7··Mr. Cooper asked.··Correct?
·8·· · ·A· ··In addition to talking in generalities about
·9··generation planning as a whole, Mr. Cooper did
10··specifically address purchase power, yes.
11·· · ·Q· ··Wasn't the Company's request on purchase power
12··worth between 20 and $30 million?
13·· · ·A· ··As part of the overall rate request, yes, it
14··was.
15·· · ·Q· ··Do you know -- but the Company has no idea what
16··percentage of Mr. Cooper's testimony was spent on the
17··purchase power issues?
18·· · ·A· ··No.··Mr. Cooper would have charged the general
19··rate case project code for that time.
20·· · ·Q· ··It could have been five minutes or 500 hours.
21··Correct?
22·· · ·A· ··And that's why --
23·· · · · · · · ·MS. RIZVI:··Objection, Your Honor.··This
24··calls for speculation.
25·· · · · · · · ·JUDGE BURKHALTER:··Overruled.
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·1·· · · · · · · ·MS. FERRIS:··Pass the witness.··Oh, I'm
·2··sorry.
·3·· · · · · · · ·JUDGE BURKHALTER:··Do you want an answer?
·4·· · · · · · · ·MS. FERRIS:··I wanted him to answer.··I
·5··withdraw my pass.
·6·· · ·A· ··I don't know the answer to that question.
·7·· · · · · · · ·MS. FERRIS:··Now I pass.··Thank you, Your
·8··Honor.
·9·· · · · · · · ·JUDGE BURKHALTER:··Mr. Foley?
10·· · · · · · · ·MR. FOLEY:··No questions.
11·· · · · · · · ·JUDGE BURKHALTER:··Ms. Rizvi?
12·· · · · · · · ·MS. RIZVI:··Pass the witness.
13·· · · · · · · ·JUDGE BURKHALTER:··All right.··Thank you,
14··Mr. Considine.··You may step down.··Ms. Rizvi, who is
15··your next witness?
16·· · · · · · · ·MS. RIZVI:··We call Stephen Morris to the
17··stand, please.
18·· · · · · · · ·(Witness Morris sworn)
19·· · · · · · · ·JUDGE BURKHALTER:··And tell me your name
20··again, sir.
21·· · · · · · · ·MR. HOYT:··George Hoyt for the Company.
22·· · · · · · · ·JUDGE BURKHALTER:··Thank you.
23··
24··
25··
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·1·· · · · · · · · · ··STEPHEN F. MORRIS,
·2··having been first duly sworn, testified as follows:
·3·· · · · · · · · · ··DIRECT EXAMINATION
·4··BY MR. HOYT:
·5·· · ·Q· ··Good morning.
·6·· · ·A· ··Good morning.
·7·· · ·Q· ··Could you state your name for the record,
·8··please?
·9·· · ·A· ··Stephen F. Morris.
10·· · ·Q· ··Do you have before you what have been marked
11··ETI Exhibits 8 through 12?
12·· · ·A· ··Yes, sir.
13·· · ·Q· ··Can you explain what each of these exhibits
14··are?
15·· · ·A· ··Yes, sir.··Starting with Exhibit 8, it is my
16··direct testimony that was filed in Docket 39896, which
17··was the underlying rate case, in November of 2011.
18·· · · · · · · ·ETI Exhibit 9 is my supplemental direct
19··testimony, also filed in Docket 39896, in March of 2012.
20·· · · · · · · ·Exhibit 10 is my supplemental direct
21··testimony in this docket, 40295, that was filed in
22··October of 2012.··That would be October 5th, 2012.
23·· · · · · · · ·ETI Exhibit 11 is my supplemental direct
24··testimony filed in this docket, 40295, on October 25th,
25··2012.
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·1·· · · · · · · ·And finally, ETI Exhibit 12 is my rebuttal
·2··testimony filed in this docket, 40295, on November 15th,
·3··2012.
·4·· · ·Q· ··Okay.··Thank you.··And was your testimony
·5··prepared by you or under your direct supervision?
·6·· · ·A· ··Yes, sir, it was.
·7·· · ·Q· ··Do you have any corrections to any of these
·8··pieces of testimony at this time?
·9·· · ·A· ··I have a correction on Exhibit 12, which is my
10··rebuttal testimony.··If you would, please turn to
11··Page 7, Line 13.··There are two percentages on Line 13,
12··14.3 percent --
13·· · · · · · · ·JUDGE BURKHALTER:··I'm sorry.··Are you on
14··the handwritten page number or the --
15·· · ·A· ··I'm sorry.··The top right number.··Page 7 of
16··14.
17·· · · · · · · ·JUDGE BURKHALTER:··Okay.··Thank you.
18·· · ·A· ··On Line 13, there were two percentages, both
19··14.3 percent.··That is a typographical error.··It should
20··be 14.5 percent as referenced in the question
21··immediately above.··Should I make that correction on
22··this copy?
23·· · ·Q· ··(BY MR. HOYT)··That would be fine.
24·· · ·A· ··Okay.
25·· · · · · · · ·JUDGE BURKHALTER:··And will you make the
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·1··same correction on the record copy, Mr. Hoyt?··Or maybe
·2··you already have.
·3·· · · · · · · ·MR. HOYT:··We will.
·4·· · · · · · · ·JUDGE BURKHALTER:··All right.··Thank you.
·5·· · ·Q· ··(BY MR. HOYT)··Okay.··And with those
·6··corrections, is your written testimony a true and
·7··accurate representation of what it would be if I asked
·8··you the same questions today?
·9·· · ·A· ··Yes, sir.
10·· · ·Q· ··Okay.
11·· · · · · · · ·MR. HOYT:··And with that, ETI moves to
12··admit Exhibits 8 through 12 into the record.
13·· · · · · · · ·JUDGE BURKHALTER:··Any objection?
14·· · · · · · · ·MS. FERRIS:··Yes, Your Honor.··Actually,
15··subject to optional completeness on Exhibit No. 12.··And
16··we have an exhibit we could offer that would exercise
17··that.
18·· · · · · · · ·JUDGE BURKHALTER:··All right.··Any other
19··objections?
20·· · · · · · · ·(No response)
21·· · · · · · · ·JUDGE BURKHALTER:··They're admitted.
22·· · · · · · · ·(Exhibit ETI Nos. 8 through 12 admitted)
23·· · · · · · · ·MR. HOYT:··At this time, we tender for
24··cross.
25·· · · · · · · ·JUDGE BURKHALTER:··Okay.··Mr. Mack?
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·1·· · · · · · · ·MR. MACK:··Cities have no questions, Your
·2··Honor.
·3·· · · · · · · ·JUDGE BURKHALTER:··Ms. Kelley?
·4·· · · · · · · ·MS. KELLEY:··I do.··Again, I have some
·5··exhibits.
·6·· · · · · · · ·(Exhibit State Agencies Nos. 2, 6, 7, 8,
·7·· · · · · · · ·14, 15, 17 marked)
·8·· · · · · · · · · ··CROSS-EXAMINATION
·9··BY MS. KELLEY:
10·· · ·Q· ··Okay.··Mr. Morris, I'd like to start by asking
11··about your own firm's arrangement for services in the
12··case.··Now, Naman Howell entered into a contract with
13··the Duggins Wren law firm and with Entergy.··Is that
14··correct.
15·· · ·A· ··Yes, ma'am.
16·· · ·Q· ··Okay.··And is it fair to say that Duggins Wren
17··entered into contracts with most of the outside
18··consultants and experts in this case?
19·· · ·A· ··I believe it entered into a contract with some
20··of them, yes.
21·· · ·Q· ··Okay.··But everybody that's the subject of your
22··testimony or review, were those pretty much direct
23··contracts with Duggins Wren?
24·· · ·A· ··Some of them were, yes.
25·· · ·Q· ··Okay.··Now, did you review contracts as part of
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·1··your own bill and review?
·2·· · ·A· ··The consulting services agreement?
·3·· · ·Q· ··Yes, sir.
·4·· · ·A· ··I did.
·5·· · ·Q· ··Okay.··And if you can, look at Exhibit No. 15.
·6··Is that part of your packet?
·7·· · ·A· ··Yes, it is.
·8·· · ·Q· ··Okay.··And I want to emphasize that this was a
·9··public contract.··It was disclosed publically.··It was
10··an RFI response.
11·· · · · · · · ·Is this a copy of your contract with
12··Duggins Wren?
13·· · ·A· ··Yes, it is.
14·· · · · · · · ·MS. KELLEY:··Okay.··I would like to offer
15··Exhibit 15 into evidence, Your Honor.
16·· · · · · · · ·JUDGE BURKHALTER:··Any objection?
17·· · · · · · · ·(No response)
18·· · · · · · · ·JUDGE BURKHALTER:··It's admitted.
19·· · · · · · · ·(Exhibit State Agencies No. 15 admitted)
20·· · ·Q· ··(BY MS. KELLEY)··Now, are the contracts that
21··Duggins Wren has entered into with outside consultants,
22··are they fairly standard on how meals and outside
23··expenses are handled?
24·· · ·A· ··I believe they are, yes.
25·· · ·Q· ··Okay.··So is that contract language in your
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·1··contract typical of other contracts that they entered
·2··into with the consultants?
·3·· · ·A· ··Without having whatever other unnamed contracts
·4··that you're talking about in front of me, I -- subject
·5··to check, I believe so.
·6·· · ·Q· ··Okay.··Subject to check.··For example, you
·7··couldn't bill Duggins Wren for meals you had working out
·8··of your own office during a regular day, could you?
·9·· · ·A· ··Conceivably, yes, if we were having a working
10··lunch where there would be, say, a meeting to go over
11··rate case items.
12·· · ·Q· ··Well, I understand what you're saying, but I
13··meant you particularly -- let me be a little more clear.
14·· · · · · · · ·When you're at your desk and not at a
15··meeting with anybody else, could you typically bill for
16··some of your lunch during the ordinary working day?
17·· · ·A· ··If I personally worked through lunch, I didn't
18··bill Duggins Wren for a meal.
19·· · ·Q· ··Okay.··How about snacks that you get at your
20··desk during an ordinary working day?··If you're snacking
21··on peanuts or popcorn or snack crackers, is that
22··something that you would bill through to them?
23·· · ·A· ··One of the legal assistants in our office has a
24··little snack jar, and if I -- I don't usually eat
25··snacks, but if I do, I'll just go over and get one out
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·1··of her jar.
·2·· · ·Q· ··Okay.··Well, that's a good way to handle that.
·3··But does she turn in receipts to you for reimbursements
·4··for that?
·5·· · ·A· ··No.··I believe lately it's been leftover
·6··Halloween candy.
·7·· · ·Q· ··Okay.··Can I ask you to look at State Agencies
·8··Exhibits No. 6 and 7 that you sponsored?··Are these
·9··answers true and correct still?··I mean, you've not
10··filed an addendum to either of these answers.··Is that
11··fair to say?
12·· · · · · · · ·MR. HOYT:··Which one is 7, Sue?
13·· · · · · · · ·(Simultaneous discussion)
14·· · ·Q· ··(BY MS. KELLEY)··Do you have 6 and 7, sir?
15·· · ·A· ··I do.
16·· · ·Q· ··Okay.··And I think I said these answers are
17··still true and correct?
18·· · ·A· ··They are.
19·· · · · · · · ·MS. KELLEY:··Okay.··I'd like to offer
20··these into evidence, please.
21·· · · · · · · ·JUDGE BURKHALTER:··Any objection to
22··admission of 6 and 7?
23·· · · · · · · ·MR. HOYT:··No.
24·· · · · · · · ·JUDGE BURKHALTER:··They're admitted.
25··
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·1·· · · · · · · ·(Exhibit State Agencies Nos. 6 and 7
·2·· · · · · · · ·admitted)
·3·· · ·Q· ··(BY MS. KELLEY)··Now, if we could turn to
·4··Exhibit No. 7, Mr. Morris, I see that you attached some
·5··emails to your staff.··By the way, what's -- what is the
·6··billing rate for your staff if they worked on a case
·7··project for this particular case?
·8·· · ·A· ··(No audible response)
·9·· · ·Q· ··Okay.··We're looking at No. 7 right now.
10·· · ·A· ··I believe it's $70 an hour.
11·· · ·Q· ··Okay.··Take a look at the last page of No. 7.
12··It refers -- counsels one of your assistants to review
13··them using the ETI checklist.··What's the ETI checklist?
14·· · ·A· ··That is a checklist that I use in reviewing the
15··invoices that I review that can -- it has, say, a check
16··list or punch list of items.··Are the rates in
17··conformance with the consulting services agreement?
18··Were there more than 12 hours spent on any one day?
19··Were there any, say, meals over $25 or luxury items, you
20··know, in-room hotel movies, first class airfare, things
21··like that, that helps facilitate my review of the
22··invoices.
23·· · ·Q· ··To your knowledge, is that ETI checklist -- was
24··that produced in response to any discovery requests in
25··this case?
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·1·· · ·A· ··I don't believe it was requested, no, ma'am.
·2·· · ·Q· ··Okay.··But you'll agree that the Company was
·3··requested to furnish all documents that you referred --
·4··in RFI No. 6 in the rate case, you'll agree that we
·5··asked for production of all documents upon which their
·6··expert witnesses relied.··Is that correct?
·7·· · · · · · · ·No, not our Exhibit 6, but during the rate
·8··case, the Company was asked to produce all documents
·9··upon which their experts relied.··Do you know --
10·· · ·A· ··Okay.
11·· · ·Q· ··-- that to be true?
12·· · ·A· ··I believe I furnished that to Duggins Wren as
13··part of doing my review.··I'm not aware of it being
14··produced.
15·· · ·Q· ··Okay.··The checklist wasn't produced as far as
16··we know.··Is that a fair summary of what you just said?
17·· · ·A· ··I don't know if it was produced.
18·· · ·Q· ··Okay.··Now, what instruction did you give your
19··Staff as to how to assess whether charges were
20··reasonable or necessary over and above what you've
21··already described?
22·· · ·A· ··My staff would do -- perform more of a factual
23··evaluation.··You know, were more than 12 hours spent on
24··one day?··Were any meals more than $25?··I mean, things
25··like that.
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·1·· · · · · · · ·The reasonable -- and the evaluation of
·2··the reasonableness of those expenses was something that
·3··I performed.··I did not delegate that to staff.
·4·· · ·Q· ··Okay.··Now, I realize it's already included in
·5··Exhibit 1, but I have demonstrative Exhibit No. 2.··I
·6··think you were just looking at that a moment ago.··Can
·7··you identify what these documents are in State Exhibit
·8··No. 2?
·9·· · ·A· ··They are invoices from Naman Howell to Duggins
10··Wren regarding the ETI rate case matter.
11·· · ·Q· ··And these would be bills for your services.··Is
12··that correct?
13·· · ·A· ··Yes, ma'am.
14·· · ·Q· ··Now, there are no time sheets or memorandum
15··containing information about your services beyond what's
16··reflected in these invoices.··Is that correct to say?
17·· · ·A· ··That's correct.
18·· · ·Q· ··Okay.··So what you see is what you get on these
19··bills?
20·· · ·A· ··That's right.··What's reflected on the bills is
21··what I have on my time sheets.
22·· · ·Q· ··Okay.··Now, let's turn to Page No. -- well, it
23··says Page No. 8 on the bottom in this exhibit.··And I'll
24··explain it starts with No. 3 because when these were
25··copied, inadvertently one document was copied twice.··So
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·1··that's why we started with Page No. 3.··But if you look
·2··at Page No. 8, sir.
·3·· · ·A· ··Okay.
·4·· · ·Q· ··We can conclude from your previous answer that
·5··this is an accurate representation of the services that
·6··you rendered.··Is that correct?
·7·· · ·A· ··Yes, ma'am.
·8·· · ·Q· ··And as well as the person who performed the
·9··services as designated by those initials?
10·· · ·A· ··That would be me, yes, ma'am.
11·· · ·Q· ··Okay.··Now, if you can, look at Exhibit No. 8,
12··State's Exhibit No. --
13·· · · · · · · ·MS. KELLEY:··Your Honor, I would like to
14··offer No. 2, if I did not do so already.
15·· · · · · · · ·JUDGE BURKHALTER:··You did not, and I'll
16··take it now.··Any objection?
17·· · · · · · · ·MR. HOYT:··No.
18·· · · · · · · ·JUDGE RIGHT:··It's admitted.
19·· · · · · · · ·(Exhibit State Agencies No. 2 admitted)
20·· · · · · · · ·MS. KELLEY:··If we could, turn to Exhibit
21··No. 8, Your Honor.
22·· · ·Q· ··(BY MS. KELLEY)··And, Mr. Morris, can I confirm
23··that this is your response to a State of Texas RFI that
24··asked about that particular billing?
25·· · ·A· ··RFI 10-11?
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·1·· · ·Q· ··Yes.
·2·· · ·A· ··It is, yes, ma'am.
·3·· · · · · · · ·MS. KELLEY:··I'd like to offer Exhibit
·4··No. 8.
·5·· · · · · · · ·JUDGE BURKHALTER:··Any objection?
·6·· · · · · · · ·MR. HOYT:··No, Your Honor.
·7·· · · · · · · ·JUDGE BURKHALTER:··It's admitted.
·8·· · · · · · · ·(Exhibit State Agencies No. 8 admitted)
·9·· · ·Q· ··(BY MS. KELLEY)··Okay.··Now, Mr. Morris, in
10··your direct testimony, I believe it's Page 11 of what I
11··have, beginning on Line No. 18, you talk about how you
12··reviewed the hourly rate.
13·· · ·A· ··Which exhibit?
14·· · · · · · · ·MS. KELLEY:··It's his direct testimony,
15··Your Honor.
16·· · · · · · · ·JUDGE BURKHALTER:··His direct testimony?
17·· · · · · · · ·MS. KELLEY:··Yes.
18·· · · · · · · ·JUDGE BURKHALTER:··Thank you.
19·· · · · · · · ·MS. KELLEY:··What is the exhibit number?
20··It's ETI --
21·· · · · · · · ·JUDGE BURKHALTER:··8.
22·· · · · · · · ·MS. KELLEY:··8.··That's right.
23·· · ·Q· ··(BY MS. KELLEY)··And let me know when you're
24··there.
25·· · ·A· ··On Page 11?
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·1·· · ·Q· ··Page 11.
·2·· · ·A· ··Yes, ma'am, I'm there.
·3·· · ·Q· ··And Line 18, rather, not Line 8.··Where you
·4··begin to discuss how you evaluated the rates of Duggins
·5··Wren law firm.
·6·· · ·A· ··Yes.
·7·· · ·Q· ··Okay.··Now, you go on to say that you took
·8··these rates from the Texas Lawyer 2011 hourly billing
·9··survey.··And I believe I've handed out what we've marked
10··as State Exhibit No. 14.··And I want to confirm that
11··that's the billing survey that you relied upon?
12·· · ·A· ··It is, yes.
13·· · ·Q· ··Okay.
14·· · · · · · · ·MS. KELLEY:··I'd like to offer Exhibit
15··No. 14, Your Honor.
16·· · · · · · · ·JUDGE BURKHALTER:··Any objection?
17·· · · · · · · ·MR. HOYT:··Subject to optional
18··completeness -- I'm not sure if this is the whole
19··survey.··I have one page.
20·· · · · · · · ·MS. KELLEY:··Right.··That's what your
21··office provided me yesterday when I asked --
22·· · · · · · · ·MR. HOYT:··Is it?··Okay.··No objection.
23·· · · · · · · ·JUDGE BURKHALTER:··It's admitted.
24·· · · · · · · ·(Exhibit State Agencies No. 14 admitted)
25·· · · · · · · ·MS. KELLEY:··If there are more, I'm glad
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·1··to look --
·2·· · · · · · · ·MR. HOYT:··I just wanted to make sure that
·3··was what the --
·4·· · ·A· ··That is it, yes.
·5·· · · · · · · ·MR. HOYT:··Okay.
·6·· · ·Q· ··(BY MS. KELLEY)··Okay.··And I believe you say
·7··on Page 12 of your testimony -- no.··Actually, it is on
·8··Page 11.··You say on Line 21 that you compared the
·9··Duggins Wren rates against the average hourly rates of
10··firms of the size that typically represent utilities in
11··rate applications.··If we look at Exhibit No. 4, can we
12··agree that this hourly billing survey is not restricted
13··to utility attorneys?
14·· · ·A· ··I'm sorry.··I don't have an Exhibit 4.
15·· · ·Q· ··That's the Texas -- I'm sorry.··14.··You're
16··right.
17·· · ·A· ··Oh.
18·· · ·Q· ··That's the Texas Lawyer --
19·· · ·A· ··Okay.
20·· · ·Q· ··-- hourly billing rate.··There's nothing on
21··that that restricts the survey to utility attorneys.
22··Isn't that correct?
23·· · ·A· ··No.··It distinguishes them by size of -- by
24··firm size and by location.
25·· · ·Q· ··Yes, I understand.··How many firms does
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·1··Exhibit 14 say took part in that survey?
·2·· · ·A· ··Could you repeat that?
·3·· · ·Q· ··On Exhibit No. 14, how many firms took part in
·4··this survey?
·5·· · ·A· ··I don't know.
·6·· · ·Q· ··Let me call your attention at the very bottom
·7··where it says "source."
·8·· · ·A· ··Oh, I'm sorry.··Yes.··101 firms.··I'm sorry.
·9·· · ·Q· ··Okay.··And for all we know, there could be bond
10··attorneys, personal injury attorneys, tax attorneys that
11··are included in this 101 firms.··Isn't that correct?
12·· · ·A· ··It could, certainly.
13·· · ·Q· ··Okay.··Do you have a feel for how many firms
14··there are in Texas?
15·· · · · · · · ·MR. HOYT:··Objection; calls for
16··speculation.
17·· · · · · · · ·MS. KELLEY:··Well, he's the expert.
18·· · · · · · · ·JUDGE BURKHALTER:··Right.··Overruled.
19·· · ·A· ··At least 101.
20·· · ·Q· ··(BY MS. KELLEY)··Oh, okay.··Well, that's -- and
21··I believe -- but I think we can conclude there are
22··probably more than 101 firms.··Isn't that fair to say?
23··Thousands?
24·· · ·A· ··I think you may be right, Counselor, but in my
25··25 years of experience in dealing with PUC matters,
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·1··there's a fairly small set of firms that actually
·2··practice before the Commission.··It's certainly less
·3··than 101.
·4·· · ·Q· ··Okay.
·5·· · ·A· ··You know, at least that represent utilities.
·6·· · ·Q· ··That's fine.··But this is the document that
·7··your testimony says -- this is the metric that you used
·8··in assessing whether or not the Duggins Wren law firm
·9··charges were reasonable?
10·· · ·A· ··That's right.
11·· · ·Q· ··Okay.··And I believe you said that firms that
12··typically represent investor-owned utilities have more
13··than 100 lawyers.··Did you make that statement on
14··Page 12 of your testimony?
15·· · ·A· ··That's correct.
16·· · ·Q· ··Okay.··And you represent -- I believe your
17··resume says that you represent investor-owned utilities.
18··Fair to say?
19·· · ·A· ··That's right.
20·· · ·Q· ··Okay.··But Naman Howell has only slightly over
21··60 attorneys in six cities.··Is that correct?
22·· · ·A· ··That's correct.
23·· · ·Q· ··Well, let's move to another topic.··It was part
24··of your job to review requests for reimbursement that
25··Duggins Wren employees turned into the Company that were
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·1··attached to their bills.··Is that correct?
·2·· · ·A· ··Yes, ma'am.
·3·· · ·Q· ··And is it the policy that an employee can't get
·4··reimbursed without having a receipt for that expense?
·5·· · ·A· ··I believe that is their policy.
·6·· · ·Q· ··Now, we know that alcoholic beverages shouldn't
·7··be charged to the ratepayers.··That's correct, isn't it?
·8·· · ·A· ··That's correct.
·9·· · ·Q· ··And if somebody brings a family member, those
10··costs won't be charged to the ratepayer as well, if
11··they're caught.··Is that correct?
12·· · ·A· ··Yes.
13·· · ·Q· ··In your opinion, is it reasonable to charge
14··ratepayers if a lawyer has dry cleaning or laundry
15··services that they say are related to the case?··Would
16··that be fair for them to pass that on as an expense to
17··the ratepayers?
18·· · ·A· ··I have personal experience -- I had a hearing
19··that went beyond one week, unbeknownst to me up in
20··Jefferson City, Missouri, many years ago, and on
21··Friday -- I had brought a week's worth of clothes for
22··the hearing, and it was going to pick up the following
23··Monday, so I spent the weekend in Jefferson City and
24··went down to the laundry and had that done and, you
25··know, got reimbursed for that.··So, yes.··I mean, there
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·1··are instances where, you know, it's reasonable for
·2··someone to be reimbursed for, you know, laundry, dry
·3··cleaning expenses, you know, whatever you want to call
·4··it.
·5·· · ·Q· ··Oh.··When you say you went to the laundry, you
·6··went down and you fed quarters in the machine yourself?
·7·· · ·A· ··I did, down on Missouri Boulevard.
·8·· · ·Q· ··Okay.··And I believe you said that was in
·9··relation to your attendance at a hearing.··Is that
10··correct?
11·· · ·A· ··Yes, ma'am.
12·· · ·Q· ··If you're not in attendance at a hearing, there
13··might be a different standard that would apply.··Is that
14··fair to say?
15·· · ·A· ··I think it depends on the circumstances.
16·· · ·Q· ··Okay.··Now, I believe we have Exhibit No. 5
17··that Mr. Considine talked about, and that was to
18··identify meals in excess of $25.··And you were a
19··co-sponsor for that RFI as well.··Is that correct?
20·· · ·A· ··Let me find that.··Yes, ma'am.
21·· · ·Q· ··Okay.··Now, one exhibit I passed out is Exhibit
22··No. 17, Mr. Morris.··And I'll represent to you even
23··though the total invoice -- subject to check, I'll
24··represent that this is an excerpted copy of an
25··exhibit -- of an invoice from Duggins Wren law firm
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·1··dated December 8th, 2011 that's included in State
·2··Agencies Exhibit No. 1 on a CD disc, and ask you to
·3··review it.··Does it look similar -- does it have
·4··components of some of the bills that you would have
·5··reviewed?
·6·· · ·A· ··It appears to, yes, ma'am.
·7·· · ·Q· ··Okay.··Now, is it possible -- we heard
·8··Mr. Considine agree that there were two meals in excess
·9··of $25 that weren't included on Exhibit No. 5 from a May
10··15th, 2012 invoice.··How about you?··Do you think in
11··addition to those there might be others that didn't make
12··the list?
13·· · ·A· ··What was that invoice that you referenced?
14·· · ·Q· ··Yeah, I didn't phrase the question very well.
15··I'll withdraw that question.
16·· · · · · · · ·Looking at State Agencies Exhibit No. 5,
17··did you have a hand in reviewing the meal receipts to
18··determine which meals should be disclosed on that chart
19··that's part of Exhibit No. 5?
20·· · ·A· ··Yes, ma'am.
21·· · ·Q· ··Okay.··So you would have reviewed those meal
22··invoices as part of your review in this case?
23·· · ·A· ··That's correct.
24·· · ·Q· ··Okay.··Now, if we look at Exhibit No. 17, can
25··we turn to Pages 18, 19, and 20?··And I'd like to have
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·1··you review those.
·2·· · · · · · · ·Now, if we look at 18, 19, and 20 and
·3··consult Exhibit No. 5 again, how many of these meal
·4··charges in excess of $25 are on the answer to Exhibit
·5··No. -- the answer to Staff's 9-9, which is Exhibit
·6··No. 5?
·7·· · ·A· ··(No audible response)
·8·· · ·Q· ··Well, in the interest of time, is it fair to
·9··say there's only one of these?
10·· · ·A· ··Which one?
11·· · ·Q· ··Look on Page 18.··Is the Royal House $60 charge
12··included in response to Staff's request for meals over
13··$25?
14·· · ·A· ··It is, yes.
15·· · ·Q· ··Now, looking on Page 19 and 20, are there other
16··meals that exceeded $25?
17·· · ·A· ··Yes.
18·· · ·Q· ··Okay.··Are those on State's Exhibit No. 5?
19··Were those disclosed in responses to Staff's request?
20·· · ·A· ··There is -- that's correct.
21·· · ·Q· ··Okay.
22·· · · · · · · ·MS. KELLEY:··I'd like to offer as a
23··demonstrative exhibit Exhibit No. 17, Your Honor.
24·· · · · · · · ·JUDGE BURKHALTER:··As a demonstrative?
25·· · · · · · · ·MS. KELLEY:··The complete invoice is
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·1··included in Exhibit No. 1, the CD that the State is
·2··offering.
·3·· · · · · · · ·JUDGE BURKHALTER:··Any objection to
·4··Exhibit No. 17?
·5·· · · · · · · ·MR. HOYT:··Not as a demonstrative.
·6·· · · · · · · ·JUDGE BURKHALTER:··It's admitted.
·7·· · · · · · · ·(Exhibit State Agencies No. 17 admitted)
·8·· · ·Q· ··(BY MS. KELLEY)··Now, I had just a brief
·9··question about Gerald Tucker, the behind-the-scenes
10··consultant that was not a witness in this case.
11·· · ·A· ··He was a consulting expert.
12·· · ·Q· ··Okay.··You agree, don't you, that Mr. Tucker is
13··not and never has been an attorney?
14·· · ·A· ··I believe he's a certified public accountant.
15·· · ·Q· ··Well, is that status inactive, sir?
16·· · ·A· ··I don't know.
17·· · ·Q· ··Okay.··Well, just to refresh your recollection,
18··let me show you an RFI response that you sponsored in
19··response to State of Texas 3-5.··I'll ask you if you can
20··look that over.
21·· · ·A· ··Yes.
22·· · ·Q· ··Okay.··And can I ask you again, is Mr. Tucker's
23··CPA status inactive according to this response?
24·· · ·A· ··He has a CPA certificate.··He has an inactive
25··license.
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·1·· · ·Q· ··Okay.
·2·· · · · · · · ·MS. KELLEY:··And I'm not offering this,
·3··Your Honor.··He's testifying about it.
·4·· · ·Q· ··(BY MS. KELLEY)··And finally, how long ago was
·5··the affiliates decision in Docket No. 16705 issued, the
·6··one we hear so much about as the reason why we need to
·7··document affiliates' costs?
·8·· · ·A· ··I believe that was in the early '90s.··I don't
·9··have an exact date.
10·· · ·Q· ··Okay.··Roughly two decades.··Correct?
11·· · ·A· ··That would be about right.
12·· · ·Q· ··Okay.··Isn't it logical by now that lessons
13··learned by a company and its law firm should have
14··included how to carry the burden of proof on affiliates'
15··cost after 20 years?
16·· · ·A· ··I disagree with your premise.··A company like
17··Entergy has, in this case, 19 affiliate witnesses.
18·· · · · · · · ·MS. KELLEY:··Well, Your Honor, I think it
19··was a "yes" or "no" question.
20·· · ·A· ··(BY MS. KELLEY)··Shouldn't the learning curve
21··by now have included --
22·· · · · · · · ·JUDGE BURKHALTER:··You've got your answer.
23··He disagrees.
24·· · ·Q· ··(BY MS. KELLEY)··So you don't believe after 20
25··years that the Duggins Wren law firm or ETI and ESI
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·1··employees should know and understand how to
·2··document affiliates' costs?
·3·· · · · · · · ·MR. HOYT:··Objection; asked and answered.
·4·· · · · · · · ·JUDGE BURKHALTER:··Overruled.
·5·· · ·A· ··As I'm sure you know, the regulatory
·6··environment in Texas is an evolving area of law, and
·7··that, coupled with the fact that Entergy has a fairly
·8··complicated rate filing packet -- rate filing
·9··application that it has to make, being an integrated
10··utility, not a wires only company, that it, out of
11··necessity, needs to present the breadth and scope of the
12··case that it did.
13·· · ·Q· ··(BY MS. KELLEY)··So it's not reasonable we
14··should expect the Duggins Wren attorneys after two
15··decades to know and understand how to document an
16··affiliate's case?
17·· · ·A· ··It's not simply up to Duggins Wren.··It's the
18··Company -- I mean, the same people that provided
19··affiliate testimony in this underlying case were not the
20··same ones that -- or at least I guess for the most
21··part -- not the same ones that started providing
22··affiliate testimony two decades ago.
23·· · ·Q· ··Well, you said you guess.··You don't know
24··exactly how long some of these people that are providing
25··affiliates' testimony have been with the Company
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·1··exactly, do you?
·2·· · ·A· ··I don't have the exact time where each and
·3··every affiliate witness has testified in prior rate
·4··applications.··What I am saying is that over 20 years,
·5··you can expect that there would be personnel changes in
·6··areas where they would have responsibility for
·7··presenting their piece of that -- of the affiliate cost
·8··for a particular application.··You know, once -- once
·9··it's -- the fact that it may be figured out, so to
10··speak, in a particular case doesn't mean that it's then
11··cast in stone and that's all you do going forward.··You
12··know, there are lessons to be learned from every case.
13·· · ·Q· ··I understand.··But basically the case -- the
14··reason we've been given it, you'll agree, boils down to
15··Docket No. 16705.··Isn't that correct?
16·· · ·A· ··That was the case where Entergy --
17·· · ·Q· ··Yeah, I understand.··I think the case speaks
18··for itself.
19·· · ·A· ··All right.
20·· · ·Q· ··What I'm asking is that has been the primary
21··reason identified by Entergy as justifying the need for
22··much of the rate case expense in this case.··Is that
23··correct?
24·· · ·A· ··It has certainly contributed to the rate case
25··expense.
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·1·· · ·Q· ··Okay.
·2·· · ·A· ··Not only --
·3·· · · · · · · ·MS. KELLEY:··I pass the witness.
·4·· · · · · · · ·JUDGE BURKHALTER:··All right.··Thank you,
·5··Ms. Griffiths?
·6·· · · · · · · ·MS. GRIFFITHS:··No questions, Your Honor.
·7·· · · · · · · ·JUDGE BURKHALTER:··Ms. Ferris?
·8·· · · · · · · ·MS. FERRIS:··Yes, Your Honor.··Thank you.
·9·· · · · · · · · · ··CROSS-EXAMINATION
10··BY MS. FERRIS:
11·· · ·Q· ··Good morning, Mr. Morris?
12·· · ·A· ··Good morning.
13·· · · · · · · ·MS. FERRIS:··First, Your Honor, we'd like
14··to exercise the right of optional completeness and offer
15··OPC Exhibit No. 3, which is based on Mr. Morris -- an
16··attachment to Mr. Morris' testimony that has a
17··transcript.··The transcript page cuts off the end of a
18··sentence, and we offer this to complete that discussion.
19··This page was not in there.
20·· · · · · · · ·JUDGE BURKHALTER:··Any objection?
21··Mr. Hoyt, any objection?
22·· · · · · · · ·MR. HOYT:··No, Your Honor.
23·· · · · · · · ·JUDGE BURKHALTER:··It's admitted.
24·· · · · · · · ·(Exhibit OPUC No. 3 marked and admitted)
25·· · ·Q· ··(BY MS. FERRIS)··Mr. Morris, my questions for
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·1··you today are going to be limited to your rebuttal
·2··testimony.··Do you have that in front of you?
·3·· · ·A· ··I do.
·4·· · ·Q· ··What exhibit number is that again?
·5·· · ·A· ··ETI Exhibit 12.
·6·· · ·Q· ··Thank you.··I believe on Pages 6 and 7 of your
·7··rebuttal testimony -- and I'm referring to the 6 and 7
·8··of 14.
·9·· · ·A· ··Okay.
10·· · ·Q· ··You have a Q and A in which you state that
11··Mr. Benedict recommends a disallowance based on the
12··Commission's rejection of ETI's purchased capacity
13··rider.··Is that a fair characterization of your
14··testimony there?
15·· · ·A· ··Yes.
16·· · ·Q· ··Are you aware that Mr. Benedict's testimony,
17··that his -- the lower bound -- the lower boundary of his
18··recommended disallowances only includes financial-based
19··incentive compensation and transmission equalization
20··costs and does not include this issue?
21·· · ·A· ··Do you have a copy of his testimony?
22·· · ·Q· ··Yes.··Let me -- Mr. Court Reporter, do you have
23··what's been marked as OPC Exhibit 1.··If not, I can
24··bring a copy.
25·· · · · · · · ·MS. FERRIS:··We anticipate offering this,
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·1··Your Honor, when Mr. Benedict is called.
·2·· · · · · · · ·JUDGE BURKHALTER:··Sure.··He's got a copy.
·3·· · ·A· ··I've got a copy.
·4·· · ·Q· ··(BY MS. FERRIS)··Okay.··Great.··Thank you.
·5··Mr. Morris, if you could turn in Mr. Benedict's
·6··testimony on Page 10.··I believe it's Page 10.··Yes.
·7··Page 10, Lines -- well, it begins at the very end of
·8··Line 13 with the word "as."··Line 13 through Line 22, it
·9··ends at the very beginning of Line 22.··Could you read
10··that passage, please?
11·· · ·A· ··"As described earlier" --
12·· · · · · · · ·JUDGE BURKHALTER:··Do you want him to read
13··it to himself?
14·· · ·Q· ··(BY MS. FERRIS)··You can read it into the
15··record.··That's fine.
16·· · ·A· ··Let me just read it --
17·· · ·Q· ··Well, read it to yourself.··That's fine.
18·· · ·A· ··Okay.
19·· · ·Q· ··Just let me know when you're done.
20·· · ·A· ··Okay.··I've read it.
21·· · ·Q· ··Okay.··So do you understand that the lower
22··bound of Mr. Benedict's recommendation did not
23··include -- only included the financial-based incentive
24··compensation and the transmission equalization costs?
25·· · ·A· ··That's what he says, yes.
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·1·· · ·Q· ··Thank you.··And do you have any reason to
·2··dispute that?
·3·· · ·A· ··No.
·4·· · ·Q· ··Okay.··Thank you.··Then I'd like to turn to
·5··Page 5 of 14 of your rebuttal testimony.··And it does go
·6··over to Page 6 just a tad.··What I'm looking at is
·7··starting at Line 18 and continuing to the very first
·8··line of Page 6, you discuss the testimony of Cities'
·9··witness, Dennis Goins, and TIEC witness, Jeffry Pollock,
10··and state that they also recommended post test year
11··adjustments.··Is that correct?
12·· · ·A· ··Yes, ma'am.
13·· · ·Q· ··Do you understand that their recommendations
14··were both based upon test year costs, test year data?
15·· · ·A· ··I read it to mean that it involved a post test
16··year adjustment.
17·· · ·Q· ··But you don't know what the post test year
18··adjustment was calculated upon, do you?
19·· · ·A· ··No.··The point I was making was that they were
20··proposing a post test year adjustment from 1.84 to
21··4.1 million for Goins and adjustment to 2.7 million for
22··Pollock.
23·· · ·Q· ··Right.··But you --
24·· · ·A· ··That was the point I was trying --
25·· · ·Q· ··But you made no distinguishing -- you did not
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·1··make the distinction or did not consider what their post
·2··test year adjustment was based upon.··Is that right?
·3·· · · · · · · ·MR. HOYT:··Objection; vague.··I'm not sure
·4··what she means by what it's based upon.··I mean, he's
·5··saying he thinks they --
·6·· · · · · · · ·JUDGE BURKHALTER:··I think it's pretty
·7··clear.··You can clarify it if you want to.
·8·· · · · · · · ·MS. FERRIS:··I thought it was very clear,
·9··Your Honor.
10·· · · · · · · ·JUDGE BURKHALTER:··Do you understand the
11··question?
12·· · ·A· ··I think so.
13·· · · · · · · ·JUDGE BURKHALTER:··Okay.
14·· · ·A· ··My point was that they were proposing post test
15··year adjustments.
16·· · ·Q· ··(BY MS. FERRIS)··Do you know if the Company's
17··post test year adjustment is based upon projected costs
18··after the test year?
19·· · ·A· ··Part of it, yes.
20·· · ·Q· ··Okay.··And even their alternate recommendation
21··was also based on data after the test year.··Is that
22··correct?
23·· · ·A· ··Yeah, part of it.··Yes.··Well --
24·· · · · · · · ·MS. FERRIS:··I pass the witness.
25·· · · · · · · ·JUDGE BURKHALTER:··All right.··Thank you.
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·1··Mr. Foley?
·2·· · · · · · · ·MR. FOLEY:··I have no questions.
·3·· · · · · · · ·JUDGE BURKHALTER:··Mr. Hoyt?
·4·· · · · · · · · · ·REDIRECT EXAMINATION
·5··BY MR. HOYT:
·6·· · ·Q· ··Just a couple of things, Mr. Morris.··Referring
·7··to the checklist Ms. Kelley asked you about, the rate
·8··case expense checklist, did you rely on the checklist in
·9··making the substantive determination as to whether
10··expenses were reasonable?
11·· · ·A· ··No.··That was my own adjustment and analysis.
12··The checklist was used primarily for a factual check, to
13··make sure that, you know, expenses and hours conformed
14··with the requirements in the agreements.
15·· · ·Q· ··And could you have performed that factual check
16··without the checklist?
17·· · ·A· ··Yes.
18·· · ·Q· ··Now I want to switch topics to -- you recall
19··Ms. Kelley asked you about affiliate -- the Company's
20··lessons learned about how to put on an affiliate case.
21··Correct?
22·· · ·A· ··Yes, sir.
23·· · ·Q· ··Okay.··And do you -- are you aware of whether
24··in 2002 the PUC issued additional guidelines related to
25··affiliate costs?
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·1·· · ·A· ··I believe they did.
·2·· · ·Q· ··Okay.··And do you recall when Docket 16708 was?
·3·· · ·A· ··I believe that was in the early '90s, if I'm
·4··not mistaken.··I'm sorry.··I don't have the exact date.
·5·· · ·Q· ··Okay.··And since 16705, has the Company seen
·6··the disallowances to its affiliate costs that it
·7··received in that docket?
·8·· · ·A· ··No, not -- certainly not to that extent.
·9·· · ·Q· ··Okay.
10·· · · · · · · ·MR. HOYT:··That's all.
11·· · · · · · · ·JUDGE BURKHALTER:··Mr. Mack?
12·· · · · · · · ·MR. MACK:··No questions.
13·· · · · · · · ·JUDGE BURKHALTER:··Ms. Kelley?
14·· · · · · · · ·MS. KELLEY:··No questions.
15·· · · · · · · ·MS. GRIFFITHS:··No questions.
16·· · · · · · · ·MS. FERRIS:··No questions, Your Honor.
17·· · · · · · · ·MR. FOLEY:··No questions.
18·· · · · · · · ·JUDGE BURKHALTER:··All right.··Thank you.
19··Mr. Morris, you can step down.
20·· · · · · · · ·WITNESS MORRIS:··Thank you, sir.
21·· · · · · · · ·JUDGE BURKHALTER:··Let's go off the
22··record.
23·· · · · · · · ·(Recess from 11:34 a.m. to 11:40 a.m.)
24·· · · · · · · ·JUDGE BURKHALTER:··Okay.··Let's go back on
25··the record.··Mr. Neinast, you rest, I gather?
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·1·· · · · · · · ·MR. NEINAST:··Yes, Your Honor.
·2·· · · · · · · ·MS. KELLEY:··By way of housekeeping, I
·3··want to make sure that I offered all of my exhibits,
·4··Your Honor.
·5·· · · · · · · ·JUDGE BURKHALTER:··I just checked, and the
·6··answer is yes, you have, and I have them all.
·7·· · · · · · · ·MS. KELLEY:··Thank you.
·8·· · · · · · · ·JUDGE BURKHALTER:··Mr. Mack, we talked
·9··about your witnesses.··Do you want to offer Cities
10··Exhibits 1 and 2?
11·· · · · · · · ·MR. MACK:··We do.
12·· · · · · · · ·JUDGE BURKHALTER:··Okay.··Any objections
13··to Cities Exhibits 1 and 2?
14·· · · · · · · ·MR. NEINAST:··No objection.
15·· · · · · · · ·JUDGE BURKHALTER:··They're admitted.
16·· · · · · · · ·(Exhibit Cities Nos. 1 and 2 admitted)
17·· · · · · · · ·JUDGE BURKHALTER:··And I gather you rest?
18·· · · · · · · ·MR. MACK:··We do.
19·· · · · · · · ·JUDGE BURKHALTER:··Okay.··Let's see.
20··Ms. Kelley, I have got all your exhibits?
21·· · · · · · · ·MS. KELLEY:··Yes.
22·· · · · · · · ·JUDGE BURKHALTER:··All right.
23··Ms. Griffiths, do you have any exhibits you want to
24··offer?
25·· · · · · · · ·MS. GRIFFITHS:··No, Your Honor.
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·1·· · · · · · · ·JUDGE BURKHALTER:··All right.··I think
·2··we're ready for you, Ms. Ferris.
·3·· · · · · · · ·MS. FERRIS:··Thank you.··The Office of
·4··Public Utility Counsel calls Mr. Benedict.
·5·· · · · · · · ·(Witness Benedict sworn)
·6·· · · · · · · ·JUDGE BURKHALTER:··Whenever you are ready.
·7·· · · · · · · ·MS. FERRIS:··Thank you.
·8·· · · · · · · ··PRESENTATION ON BEHALF OF
·9·· · · · · ·THE OFFICE OF PUBLIC UTILITY COUNSEL
10·· · · · · · · · · · ·NATHAN BENEDICT,
11··having been first duly sworn, testified as follows:
12·· · · · · · · · · ··DIRECT EXAMINATION
13··BY MS. FERRIS:
14·· · ·Q· ··Good morning, Mr. Benedict.
15·· · ·A· ··Good morning.
16·· · ·Q· ··Do you have before you what's been marked as
17··OPUC Exhibit No. 1?
18·· · ·A· ··I do.
19·· · ·Q· ··Can you identify this for the record, please?
20·· · ·A· ··It is my direct testimony and workpapers
21··submitted in this docket.
22·· · ·Q· ··Do you have any corrections to make?
23·· · ·A· ··I do.··I'd like to make a correction on Page 7.
24··And the correction is that Footnote 7, the text there
25··should be deleted.
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·1·· · ·Q· ··Other than that correction, is the testimony
·2··before you -- if the questions were asked of you today,
·3··would your answers be the same?
·4·· · ·A· ··They would.
·5·· · · · · · · ·MS. FERRIS:··At this time, Your Honor, we
·6··offer OPUC Exhibit No. 1.
·7·· · · · · · · ·JUDGE BURKHALTER:··Ms. Ferris, was that
·8··correction made in the court reporter's copies and the
·9··record copies?
10·· · · · · · · ·MS. FERRIS:··Yes, Your Honor, it was.
11·· · · · · · · ·JUDGE BURKHALTER:··All right.··Any
12··objection to OPUC Exhibit No. 1?
13·· · · · · · · ·MR. NEINAST:··With the elimination of
14··Footnote 7, ETI has no objection.
15·· · · · · · · ·JUDGE BURKHALTER:··It's admitted.
16·· · · · · · · ·(Exhibit OPUC No. 1 admitted)
17·· · · · · · · ·MS. FERRIS:··We tender the witness.
18·· · · · · · · ·JUDGE BURKHALTER:··All right.··Thank you.
19··Let me see here.··Mr. Mack?
20·· · · · · · · ·MR. MACK:··No questions.
21·· · · · · · · ·JUDGE BURKHALTER:··Ms. Kelley?
22·· · · · · · · ·MS. KELLEY:··No.
23·· · · · · · · ·JUDGE BURKHALTER:··Ms. Griffiths?
24·· · · · · · · ·MS. GRIFFITHS:··No.
25·· · · · · · · ·JUDGE BURKHALTER:··Mr. Foley?
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·1·· · · · · · · ·MR. FOLEY:··Briefly.
·2·· · · · · · · ·JUDGE BURKHALTER:··Go ahead.
·3·· · · · · · · · · ··CROSS-EXAMINATION
·4··BY MR. FOLEY:
·5·· · ·Q· ··Mr. Benedict, could you turn to Page 10 of your
·6··testimony?
·7·· · ·A· ··Yes.··I'm there.
·8·· · ·Q· ··And at the bottom of the page, you refer to a
·9··$15.2 million quantification of three issues that, in
10··your opinion, were clearly -- that were litigated by
11··Entergy in the underlying rate case and were clearly
12··contrary to Commission precedent?
13·· · ·A· ··Well, it's two issues, to be correct.
14·· · ·Q· ··Okay.··And the two issues are what?
15·· · ·A· ··Incentive -- or financial-based incentive
16··compensation and transmission equalization costs.
17·· · ·Q· ··And the three -- okay.··And so could you
18··explain how you got to the quantification of 15.2
19··million?
20·· · ·A· ··Sure.··The transmission equalization cost, that
21··was the upward adjustment to MSS-2 proposed by the
22··Company, and that was a $9 million adjustment.··The
23··financial-based incentive compensation fees, I believe
24··the actual amount was at issue in the case, but
25··ultimately it was determined by the ALJs to be worth 6.2
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·1··million.··And when you add the 9 million to 6.2 million,
·2··you get to the 15.2 million.
·3·· · · · · · · ·MR. FOLEY:··Thank you.··That's all I have.
·4·· · · · · · · ·JUDGE BURKHALTER:··Mr. Neinast?
·5·· · · · · · · ·MR. NEINAST:··No questions.
·6·· · · · · · · ·JUDGE BURKHALTER:··I have a question,
·7··Mr. Benedict.
·8·· · ·A· ··Yes.
·9·· · · · · · · · ··CLARIFYING EXAMINATION
10··BY JUDGE BURKHALTER:
11·· · ·Q· ··I think that the -- I'm not positive, but first
12··off, are you aware that there's a pending motion for
13··rehearing?
14·· · ·A· ··Yes.
15·· · ·Q· ··I think the MSS-2 and financial-based incentive
16··compensation issues might be among the issues that are
17··being argued in the pending motions for rehearing.··Are
18··you aware of that?
19·· · ·A· ··They very well could be.
20·· · ·Q· ··Okay.··Do you have an opinion on how the
21··outcome of this rate case expenses case could be
22··impacted by the outcome of those pending -- the
23··Commission's decision on those pending motions for
24··rehearing?
25·· · ·A· ··Those two items form a lower bound of my
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·1··recommendation, so that lower bound could move around
·2··based on that outcome.··But, otherwise, the rest of my
·3··testimony would be the same.
·4·· · ·Q· ··I didn't understand that.··As to -- let us
·5··hypothesize.··I don't know if it's likely or not, but if
·6··the Commission agrees with Entergy as to, say,
·7··financial-based incentive compensation -- whatever it's
·8··arguing in its motion for rehearing -- this may be
·9··hypothetical.··They may not be arguing about that issue.
10··But if they agreed with them and gave them what they
11··want on the motion for reconsideration, would that alter
12··your testimony?
13·· · ·A· ··It would change the amount of that lower bound
14··that I discussed in my testimony.
15·· · ·Q· ··In other words, are you saying you would then
16··believe they were entitled to reimbursement for that --
17··for those expenses?
18·· · ·A· ··I think that's an accurate way to construe
19··that, yes.
20·· · · · · · · ·JUDGE BURKHALTER:··All right.··Thank you.
21··Ms. Ferris, in light of my questions, any redirect?
22·· · · · · · · ·MS. FERRIS:··I do have one, Your Honor.
23·· · · · · · · · · ·REDIRECT EXAMINATION
24··BY MS. FERRIS:
25·· · ·Q· ··Mr. Benedict, is it your understanding that the
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·1··motions for rehearing that are pending are on the order
·2··on rehearing?··Is that right?
·3·· · ·A· ··I don't know.··I presume that's true.
·4·· · · · · · · ·MS. FERRIS:··Okay.··I pass the witness.
·5·· · · · · · · ·JUDGE BURKHALTER:··Okay.··Anybody?
·6·· · · · · · · ·(No response)
·7·· · · · · · · ·JUDGE BURKHALTER:··Mr. Neinast?
·8·· · · · · · · ·MR. NEINAST:··No, Your Honor.
·9·· · · · · · · ·JUDGE BURKHALTER:··Okay.··Mr. Benedict,
10··thank you very much.
11·· · · · · · · ·WITNESS BENEDICT:··Great.··Thank you.
12·· · · · · · · ·JUDGE BURKHALTER:··Ms. Ferris, do you
13··rest?
14·· · · · · · · ·MS. FERRIS:··I rest, Your Honor.
15·· · · · · · · ·JUDGE BURKHALTER:··Do we have any other
16··witnesses?
17·· · · · · · · ·MR. FOLEY:··I do not.
18·· · · · · · · ·JUDGE BURKHALTER:··Does that mean we're
19··done?
20·· · · · · · · ·MR. FOLEY:··Has Staff's exhibit been
21··admitted, just for the record?
22·· · · · · · · ·JUDGE BURKHALTER:··No, sir.
23·· · · · · · · ·MR. FOLEY:··Okay.··I move to admit Staff's
24··Exhibit 1.
25·· · · · · · · ·JUDGE BURKHALTER:··1 and 2?
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·1·· · · · · · · ·MR. FOLEY:··No.··Just 1, actually.··2 is
·2··already in.
·3·· · · · · · · ·JUDGE BURKHALTER:··Okay.··Any objection to
·4··Staff's Exhibit 1?
·5·· · · · · · · ·(No response)
·6·· · · · · · · ·JUDGE BURKHALTER:··It's admitted.
·7·· · · · · · · ·(Exhibit Commission Staff No. 1 admitted)
·8·· · · · · · · ·JUDGE BURKHALTER:··Any other evidence that
·9··needs to come in?
10·· · · · · · · ·(No response)
11·· · · · · · · ·JUDGE BURKHALTER:··Okay.··Are we ready for
12··closing argument?··I'm sorry.··Let's go off the record
13··and talk about briefing schedule.
14·· · · · · · · ·(Recess from 11:47 a.m. to 11:51 a.m.)
15·· · · · · · · ·JUDGE BURKHALTER:··We have agreed off the
16··record that we will have a briefing schedule whereby
17··initial briefs will be due on December 10th, 2012, and
18··replies will be due December 21st, 2012.··And I don't
19··think there's anything else we need to discuss, so with
20··that, we are adjourned.··Thank you all very much, and
21··have a happy holiday.
22·· · · · · · · ·(Proceedings concluded at 11:52 a.m.)
23··
24··
25··
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·1·· · · · · · · · ··C E R T I F I C A T E
· ·
·2··
· ·
·3··STATE OF TEXAS· ··)
· ·
·4··COUNTY OF TRAVIS··)
· ·
·5··
· ·
·6·· · · · · ·I, Steven Stogel, Certified Shorthand Reporter
· ·
·7··in and for the State of Texas, do hereby certify that
· ·
·8··the above-mentioned matter occurred as hereinbefore set
· ·
·9··out.
· ·
10·· · · · · ·I FURTHER CERTIFY THAT the proceedings of such
· ·
11··were reported by me or under my supervision, later
· ·
12··reduced to typewritten form under my supervision and
· ·
13··control, and that the foregoing pages are a full, true
· ·
14··and correct transcription of the original notes.
· ·
15·· · · · · ·IN WITNESS WHEREOF, I have hereunto set my
· ·
16··hand and seal this 3rd day of December 2012.
· ·
17··
· ·
18·· · · · · · · · · · · ··_________________________________
· · · · · · · · · · · · ··Steven Stogel
19·· · · · · · · · · · · ··Certified Shorthand Reporter
· · · · · · · · · · · · ··CSR No. 6174 - Expires 12/31/2012
20··
· · · · · · · · · · · · ··Firm Certification No. 276
21·· · · · · · · · · · · ··Kennedy Reporting Service, Inc.
· · · · · · · · · · · · ··1016 La Posada Drive, Suite 294
22·· · · · · · · · · · · ··Austin, Texas··78752
· · · · · · · · · · · · ··512.474.2233
23··
· ·
24··
· ·
25··Job No. 105605
KENNEDY REPORTING SERVICE, INC.
512.474.2233
·1·· · · · · · · · · TRANSCRIPT OF PROCEEDINGS
· ·
·2·· · · · · · · · · · · ·· BEFORE THE
· ·
·3·· · · · · ·· PUBLIC UTILITY COMMISSION OF TEXAS
· ·
·4·· · · · · · · · · · · · AUSTIN, TEXAS
· ·
·5··
· ·
·6··
· ·
·7··
· ·
·8··
· ·
·9··
·IN THE MATTER OF THE OPEN MEETING)
· ·
10··OF THURSDAY, APRIL 11, 2013· · ··)
· ·
11··
· ·
12··
· ·
13··
· ·
14··
· ·
15··
· ·
16·· · · · · · BE IT REMEMBERED THAT AT approximately 9:35
· ·
17··a.m., on Thursday, the 11th day of April 2013, the
· ·
18··above-entitled matter came on for hearing at the Public
· ·
19··Utility Commission of Texas, 1701 North Congress Avenue,
· ·
20··William B. Travis Building, Austin, Texas,
· ·
21··Commissioners' Hearing Room, before DONNA L. NELSON,
· ·
22··CHAIRMAN and KENNETH W. ANDERSON, JR., COMMISSIONER; and
· ·
23··the following proceedings were reported by Lou Ray,
· ·
24··Certified Shorthand Reporter.
· ·
25··
Page 2
·1·· · · · · · · · · · ·TABLE OF CONTENTS
· ·
·2·· · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE
· ·
·3··PROCEEDINGS, THURSDAY, APRIL 11, 2013 ..............· ·6
· ·
·4·· · · · · · · · · ·COMMUNICATIONS AGENDA
· ·
·5·· · · · · · · · · · ·AGENDA ITEM NO. 1
· ·
·6··DOCKET NO. 40582 - APPLICATION OF IMPERIO
·NETWORKS, LLC FOR A SERVICE PROVIDER
· ·
·7··CERTIFICATE OF OPERATING AUTHORITY ........... CONSENTED
· ·
·8·· · · · · · · · · · ·AGENDA ITEM NO. 2
· ·
·9··DISCUSSION AND POSSIBLE ACTION REGARDING FCC
·ORDER ON RECONSIDERATION RELATING TO SUBMISSION
· ·
10··OF SERVICE AREA BOUNDARY DATA (WC DOCKET
·NO. 10-90 AND WC DOCKET NO. 05-337) .......... NOT HEARD
· ·
11··
· ·
12·· · · · · · · · · · ·AGENDA ITEM NO. 3
· ·
13··DISCUSSION AND POSSIBLE ACTION REGARDING
·IMPLEMENTATION OF STATE AND FEDERAL
· ·
14··LEGISLATION AFFECTING TELECOMMUNICATIONS
·MARKETS, CURRENT AND PROJECTED RULEMAKING
· ·
15··PROJECTS, AND COMMISSION PRIORITIES .......... NOT HEARD
· ·
16·· · · · · · · · · · ··ELECTRIC AGENDA
· ·
17·· · · · · · · · · · ·AGENDA ITEM NO. 4
· ·
18··DOCKET NO. 40295; SOAH DOCKET NO. XXX-XX-XXXX -
·APPLICATION OF ENTERGY TEXAS, INC.··FOR RATE
· ·
19··CASE EXPENSES PERTAINING TO P.U.C. DOCKET
·NO. 39896 ..........................................· ·6
· ·
20··
· ·
21·· · · · · · · · · · ·AGENDA ITEM NO. 5
· ·
22··PROJECT NO. 39246 - RULEMAKING PROCEEDING
·CONCERNING RECOVERY OF PURCHASED POWER
· ·
23··CAPACITY COSTS, INCLUDING AMENDMENT TO SUBST. R.
·25.238 .............................................··21
· ·
24··
· ·
25··
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·1·· · · · · · · · · · ·TABLE OF CONTENTS
· ·
·2·· · · · · · · · · · · · · ·PAGE
· ·
·3·· · · · · · · · · · ·AGENDA ITEM NO. 6
· ·
·4··PROJECT NO. 40979 - PROCEEDING TO TRACK
·COMPLIANCE WITH THE TERMS AND CONDITIONS
· ·
·5··SET FORTH IN THE COMMISSION'S ORDER ISSUED
·IN DOCKET NO. 40346 AND THE NUS, AND
· ·
·6··ASSOCIATED STUDIES ARISING FROM THE ORDER
·AND/OR NUS ................................... NOT
· · HEARD
·7··
· ·
·8·· · · · · · · · · · ·AGENDA ITEM NO. 7
· ·
·9··PROJECT NO. 41060 - PROCEEDING TO EXAMINE
·THE INPUTS INCLUDED IN THE ERCOT CAPACITY,
· ·
10··DEMAND AND RESERVES REPORT ................... NOT HEARD
· ·
11·· · · · · · · · · · ·AGENDA ITEM NO. 8
· ·
12··PROJECT NO. 41061 - RULEMAKING REGARDING DEMAND
·RESPONSE IN THE ELECTRIC RELIABILITY COUNCIL
· ·
13··OF TEXAS (ERCOT) MARKET ...................... NOT HEARD
· ·
14·· · · · · · · · · · ·AGENDA ITEM NO. 9
· ·
15··PROJECT NO. 41210 - INFORMATION RELATED TO
·THE SOUTHWEST POWER POOL REGIONAL STATE
· ·
16··COMMITTEE .................................... NOT HEARD
· ·
17·· · · · · · · · · ··AGENDA ITEM NO. 10
· ·
18··PROJECT NO. 41211 - INFORMATION RELATED TO
·THE ORGANIZATION OF MISO STATES .............. NOT
· · HEARD
19··
· ·
20·· · · · · · · · · ··AGENDA ITEM NO. 11
· ·
21··PROJECT NO. 40000 - COMMISSION PROCEEDING TO
·ENSURE RESOURCE ADEQUACY IN TEXAS ............ NOT
· · HEARD
22··
· ·
23··
· ·
24··
· ·
25··
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·1·· · · · · · · · · · ·TABLE OF CONTENTS
· ·
·2·· · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE
· ·
·3·· · · · · · · · · ··AGENDA ITEM NO. 12
· ·
·4··PROJECT NO. 37344 - INFORMATION RELATED TO
·THE ENTERGY REGIONAL STATE COMMITTEE ......... NOT HEARD
· ·
·5··
· ·
·6·· · · · · · · · · ··AGENDA ITEM NO. 13
· ·
·7··DISCUSSION AND POSSIBLE ACTION ON ELECTRIC
·RELIABILITY; ELECTRIC MARKET DEVELOPMENT;
· ·
·8··ERCOT OVERSIGHT; TRANSMISSION PLANNING,
·CONSTRUCTION, AND COST RECOVERY IN AREAS
· ·
·9··OUTSIDE OF ERCOT; SPP REGIONAL STATE
·COMMITTEE AND ELECTRIC RELIABILITY
· ·
10··STANDARDS AND ORGANIZATIONS ARISING UNDER
·FEDERAL LAW .................................. NOT HEARD
· ·
11··
· ·
12·· · · · · · · · · ··AGENDA ITEM NO. 14
· ·
13··DISCUSSION AND POSSIBLE ACTION REGARDING
·IMPLEMENTATION OF STATE AND FEDERAL
· ·
14··LEGISLATION, AFFECTING ELECTRICITY MARKETS,
·CURRENT AND PROJECTED RULEMAKING PROJECTS,
· ·
15··AND COMMISSION PRIORITIES ..........................··33
· ·
16·· · · · · · · · · · ··GENERAL AGENDA
· ·
17·· · · · · · · · · ··AGENDA ITEM NO. 15
· ·
18··DISCUSSION AND POSSIBLE ACTION REGARDING
·AGENCY REVIEW BY SUNSET ADVISORY COMMISSION,
· ·
19··OPERATING BUDGET, STRATEGIC PLAN,
·APPROPRIATIONS REQUEST, PROJECT ASSIGNMENTS,
· ·
20··CORRESPONDENCE, STAFF REPORTS, AGENCY
·ADMINISTRATIVE ISSUES, FISCAL MATTERS
· ·
21··AND PERSONNEL POLICY ......................... NOT HEARD
· ·
22··
· ·
23··
· ·
24··
· ·
25··
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·1·· · · · · · · · · · ·TABLE OF CONTENTS
· ·
·2·· · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE
· ·
·3·· · · · · · · · · ··AGENDA ITEM NO. 16
· ·
·4··DISCUSSION AND POSSIBLE ACTION REGARDING
·CUSTOMER SERVICE ISSUES, INCLUDING BUT
· ·
·5··NOT LIMITED TO CORRESPONDENCE AND
·COMPLAINT ISSUES ............................. NOT HEARD
· ·
·6··
· ·
·7·· · · · · · · · · ··AGENDA ITEM NO. 17
· ·
·8··DISCUSSION AND POSSIBLE ACTION ON
·INFRASTRUCTURE RELIABILITY, EMERGENCY
· ·
·9··MANAGEMENT; AND HOMELAND SECURITY ............ NOT HEARD
· ·
10·· · · · · · · · · ··AGENDA ITEM NO. 18
· ·
11··ADJOURNMENT FOR CLOSED SESSION .....................··35
· ·
12··RECONVENING OF OPEN MEETING ........................··36
· ·
13··PROCEEDINGS CONCLUDED...............................··36
· ·
14··REPORTER'S CERTIFICATE .............................··37
· ·
15··
· ·
16··
· ·
17··
· ·
18··
· ·
19··
· ·
20··
· ·
21··
· ·
22··
· ·
23··
· ·
24··
· ·
25··
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·1·· · · · · · · · · ·P R O C E E D I N G S
· ·
·2·· · · · · · · · ·THURSDAY, APRIL 11, 2013
· ·
·3·· · · · · · · · · · · ··(9:35 a.m.)
· ·
·4·· · · · · · · ·CHAIRMAN NELSON:··Okay.··Let's go ahead
· ·
·5··and get started.··This meeting of the Public Utility
· ·
·6··Commission of Texas will come to order to consider
· ·
·7··matters that have been duly posted with the Secretary of
· ·
·8··State of Texas for today, April 11, 2013.
· ·
·9·· · · · · · · ·Stephen, I think we have a very short
· ·
10··consent agenda, but would you walk us through it?
· ·
11·· · · · · · · ·MR. JOURNEAY:··Yes, ma'am.··Good morning,
· ·
12··Commissioners.··By individual ballot the following item
· ·
13··was added to your consent agenda:··Item No. 1.
· ·
14·· · · · · · · ·CHAIRMAN NELSON:··The Chair will entertain
· ·
15··a motion to approve the consent agenda.
· ·
16·· · · · · · · ·COMM. ANDERSON:··You have the motion.
· ·
17·· · · · · · · ·CHAIRMAN NELSON:··Thank you.··Second.
· ·
18·· · · · · · · · · · ·AGENDA ITEM NO. 4
· ·
19··DOCKET NO. 40295; SOAH DOCKET NO. XXX-XX-XXXX -
·APPLICATION OF ENTERGY TEXAS, INC.··FOR RATE
· ·
20··CASE EXPENSES PERTAINING TO P.U.C. DOCKET
·NO. 39896
· ·
21··
· ·
22·· · · · · · · ·CHAIRMAN NELSON:··Okay.··And No. 2 is not
· ·
23··taken up; 3 is not taken up, which brings us to Item 4.
· ·
24··Let me call up Docket No. 40295.
· ·
25·· · · · · · · ·So I generally agreed with the PFD on this
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·1··issue, but I would reverse on a few of the findings in
·2··the PFD.··So the first one I would -- I think not -- I
·3··think we were clear in a recent decision that we would
·4··not allow estimated rate expenses to be recovered in --
·5··because they're estimated, and they could be recovered
·6··in the next docket when they're --
·7·· · · · · · · ·COMM. ANDERSON:··Oh, you mean the --
·8·· · · · · · · ·CHAIRMAN NELSON:··Yes, the Cities
·9··estimated -- I guess I should be clear, 4B the Cities
10··rate case expenses, I would -- I agree with the ALJ in
11··terms of everything except for the 75,800 that are
12··estimated.
13·· · · · · · · ·COMM. ANDERSON:··I agree.··And I agree
14··with you generally with just a couple of exceptions.··I
15··thought -- I agreed with the PFD.
16·· · · · · · · ·CHAIRMAN NELSON:··Right.
17·· · · · · · · ·COMM. ANDERSON:··I do think that one --
18··that there's a finding of fact and conclusion of law
19··that will need to be added just to comply with the
20··requirements of 36.058.
21·· · · · · · · ·CHAIRMAN NELSON:··I agree, on affiliate
22··transactions.
23·· · · · · · · ·COMM. ANDERSON:··Yeah.··But we can get
24··back to that at the end.
25·· · · · · · · ·CHAIRMAN NELSON:··Okay.··And on C.2.a.
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·1··which is financially based incentive compensation, I
·2··kind of struggled with this issue because I -- I
·3··understood what all the different parties were
·4··articulating, but ultimately I'm not sure in this docket
·5··it's appropriate for us to impose a new policy of
·6··disallowing rate case expenses related to advocacy of
·7··long-shot positions.
·8·· · · · · · · ·What I would like to do is, if it's okay
·9··with you, is open a rulemaking.··I think just the issue
10··in general of rate case expenses, whether it's a utility
11··or the cities, I think it's something that we've needed
12··to look at for a while, and this is the type of issue
13··that would be appropriate to include in that type of a
14··rulemaking.
15·· · · · · · · ·COMM. ANDERSON:··Well, I agree that we
16··ought to open up a rulemaking on it.··I -- with respect
17··to the PFD itself -- because interestingly in the four
18··and a half years I've been on the Commission, this is
19··actually the first contested case that is -- with
20··respect to --
21·· · · · · · · ·CHAIRMAN NELSON:··Right.
22·· · · · · · · ·COMM. ANDERSON:··-- the expenses that's
23··actually has gotten to us.··On the issue of the PFD
24··itself, this is one where I spent a lot of time.··I
25··would actually adopt the PFD on the issue of the -- the
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·1··financial incentive compensation --
·2·· · · · · · · ·CHAIRMAN NELSON:··Okay.
·3·· · · · · · · ·COMM. ANDERSON:··-- because I think that
·4··that was clearly -- whether you articulate it as a long
·5··shot or -- and you do raise, I think -- or you'll get to
·6··a point, if we end up going down this road in this
·7··particular case -- there's a question of a standard and
·8··then what the consequences are --
·9·· · · · · · · ·CHAIRMAN NELSON:··Right.
10·· · · · · · · ·COMM. ANDERSON:··-- and that's a fair
11··point.··And that may dictate going back to just doing it
12··in a rulemaking.··But it was clear to me that all the
13··precedent we have excludes that kind of recovery.··And
14··so this was a -- it's almost charitable to call it a
15··long shot.
16·· · · · · · · ·CHAIRMAN NELSON:··Right.
17·· · · · · · · ·COMM. ANDERSON:··I know there was an
18··amicus brief that -- or amici brief that labeled that.
19··But the fact of the matter is that all the precedent is
20··against it.··We're not saying that a utility -- or the
21··judges aren't saying a utility can't raise the issue or
22··can't raise any issue.··They're simply saying that you
23··can't expect the ratepayers to bear it.··And so on this
24··issue I would actually adopt the PFD.
25·· · · · · · · ·However, on the next issue --
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·1·· · · · · · · ·CHAIRMAN NELSON:··Okay.
·2·· · · · · · · ·COMM. ANDERSON:··-- where the judges
·3··struck down the -- let me get to it -- struck down the
·4··transmission -- you know, the future transmission
·5··expenses.··That one I actually would probably reverse
·6··the PFD because when I went back and actually looked
·7··at -- while the judges were absolutely correct that we
·8··ultimately -- that the judges recommended and that
·9··the -- this is the post test year transmission
10··equalization.··I understood what the judges were saying
11··in the -- in the PFD.
12·· · · · · · · ·However, I went back and actually looked
13··at the sections of the PFD in the Entergy rate case.
14··And while again they ultimately -- they ultimately found
15··that Entergy didn't meet its burden of proof, the
16··discussion in there was not, you know, as clear cut that
17··this was just a wild reach.
18·· · · · · · · ·CHAIRMAN NELSON:··Right.
19·· · · · · · · ·COMM. ANDERSON:··It was just that they
20··didn't meet their burden of proof, it wasn't known and
21··measurable.··And so on that particular issue I'd
22··actually cut Entergy some slack as opposed to
23··reversing -- I mean as opposed to adopting the PFD.··And
24··then I would -- and then adopt the PFD with respect to
25··the purchased power capacity rider.
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·1·· · · · · · · ·So I don't feel -- this isn't a
·2··fall-on-my-sword thing, but that's sort of where I came
·3··down.
·4·· · · · · · · ·CHAIRMAN NELSON:··So what I'm hearing you
·5··say is when you look at the issue under C.2.a., which is
·6··the issue of financially based incentives compensation,
·7··what I'm hearing is almost like a -- in a civil court
·8··case where there's a frivolous -- a frivolous whatever
·9··it is.··You know, a Rule 13 under federal law, and I
10··don't know what it is under state law, but where you are
11··found to have filed a frivolous claim.··Actually, in
12··that case, I think you have to pay the attorneys' fees
13··of the other side.··But that is akin to the standard
14··that you're articulating for the financially based
15··incentive compensation.
16·· · · · · · · ·You're saying if there's a long line of
17··precedent and it doesn't -- and it's a decided issue at
18··the Commission, you can take your shot at trying to
19··overturn it.··But to the extent you lose, then you don't
20··get your attorneys' fees for that --
21·· · · · · · · ·COMM. ANDERSON:··That's kind of where I
22··would come out, because it just seems -- and it's
23··particularly acute, I think, on the issue of the
24··financial incentive compensation because -- besides the
25··fact that there's long precedent for it, and consistent
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·1··precedent, it really does go to the benefit more of
·2··shareholders and investors than to ratepayers.··And, you
·3··know, at some point, utilities need to be -- exercise,
·4··you know, some prudence in their arguments.··So that's
·5··sort of where I come down, that it borders on frivolous.
·6·· · · · · · · ·But I wouldn't stop them from making the
·7··claim.··It's just they run the risk that if they do that
·8··it affects their recovery.··I just don't think it was a
·9··reasonable argument to make and then to ask ratepayers
10··to pay for it.··And that certainly would be my position
11··in the rulemaking.
12·· · · · · · · ·Now, to kind of close the loop on this, I
13··would adopt, then, the issue-specific reduction
14··approach, and --
15·· · · · · · · ·CHAIRMAN NELSON:··Before we go there, can
16··I --
17·· · · · · · · ·(Simultaneous discussion)
18·· · · · · · · ·CHAIRMAN NELSON:··Before we talk about how
19··we would address it, let me just say I do think it's --
20··I agree with you.··I was going to say I don't disagree
21··with you, which is the same as agreeing with you.
22·· · · · · · · ·(Laughter)
23·· · · · · · · ·CHAIRMAN NELSON:··But I want to make sure,
24··as we move forward on this rulemaking, that we put the
25··same standard in place for all the parties so that --
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·1··because I feel like -- I've always felt like we, as a
·2··Commission, could do a better job of scrubbing some of
·3··those numbers that are -- that the parties ask for in
·4··rate cases.··So to the extent that --
·5·· · · · · · · ·COMM. ANDERSON:··I agree with you.
·6·· · · · · · · ·CHAIRMAN NELSON:· ·-- the Cities make an
·7··argument that's frivolous and they seek recovery of
·8··attorneys' fees on it, then they also wouldn't be
·9··entitled to get their attorneys' fees.
10·· · · · · · · ·So with that caveat, and the fact that
11··we're going to open a rulemaking on it, I'm okay with
12··moving forward where we -- I agree with you that the
13··financially based incentive compensation, while I would
14··have allowed recovery, I understand what you're saying
15··and I'm willing to go with you.
16·· · · · · · · ·On the transmission equalization expenses,
17··I agree with you on that as well and I think we should
18··allow those expenses.
19·· · · · · · · ·COMM. ANDERSON:··Yeah, I -- I wouldn't
20··reduce the --
21·· · · · · · · ·CHAIRMAN NELSON:··Right.
22·· · · · · · · ·COMM. ANDERSON:··-- by some factor for
23··that.
24·· · · · · · · ·CHAIRMAN NELSON:··Right.
25·· · · · · · · ·COMM. ANDERSON:··And again, I actually
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·1··went back to the original PFD to sort of get a sense,
·2··because I think the judge -- and I give the judges a lot
·3··of deference in this.··They sat through the hearing, and
·4··one of them actually was a judge in the Entergy rate
·5··case.··But I -- the -- I thought they were a little
·6··overstrong in their argument about the transmission
·7··issue in light of going back and actually reading the
·8··original PFD on the issue.
·9·· · · · · · · ·CHAIRMAN NELSON:··Right.
10·· · · · · · · ·COMM. ANDERSON:··It just seemed like it
11··was -- maybe not a closer call, but less -- less clearly
12··settled and more fact based.
13·· · · · · · · ·CHAIRMAN NELSON:··Right.··And in terms of
14··the -- what we would disallow, I'm not really sure about
15··whether I'm comfortable with the issue-specific
16··reduction approach.··I guess I would ask staff if --
17··would it be appropriate at this point to go back and
18··make sure we have in the record what we need from the
19··parties since we've made this decision now on -- if we
20··decided to pursue the issue and decrease it by the costs
21··attributable to that one specific issue, do we have
22··enough in the record to determine what that amount would
23··be?
24·· · · · · · · ·COMM. ANDERSON:··I mean, I -- it looks to
25··me like it would reduce the -- there would be a
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·1··disallowance of -- I mean, there would be an adjustment
·2··to rate base and removal of some O&M expenses.··I think
·3··the actual percentage then would drop from -- I think
·4··the judges recommended a 14 point -- was it 8 -- or some
·5··percentage it would be cut down to -- sort of ball park
·6··less than 7 percent, a haircut, maybe less.··Because I
·7··think the rate -- I think there would be a disallowance
·8··in rate base of about 335,000 and some change, maybe 336
·9··rounded.··And then there's a disallowance of plant in
10··service.
11·· · · · · · · ·CHAIRMAN NELSON:··Well, rather than trying
12··to do this from the bench, would it be okay with you if
13··we ask all the parties who have participated to come
14··back to us with a number on what they think the
15··percentage should be?
16·· · · · · · · ·COMM. ANDERSON:··Okay.··That's fine.
17·· · · · · · · ·CHAIRMAN NELSON:··Or if -- because I see
18··staff is trying to figure out what the answer is as
19··well, our advising staff.··So that would be my
20··preference with that guidance.
21·· · · · · · · ·Stephen, is there a reason we can't bring
22··it back at the next Open Meeting after we get clarity on
23··that issue?
24·· · · · · · · ·MR. JOURNEAY:··No, ma'am, there's not.
25·· · · · · · · ·CHAIRMAN NELSON:··Okay.
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·1·· · · · · · · ·MR. JOURNEAY:··I think -- there's
·2··certainly one number that the judge identifies in the
·3··PFD.··I think where there might be some uncertainty is
·4··dealing with the -- we also, in addition to disallowing
·5··incentive compensation, included an additional
·6··disallowance for the FICA that was associated with that.
·7··And while those numbers are clearly identifiable in the
·8··rate case docket in the ALJ number runs, I don't think
·9··that that particular number is specifically identified.
10·· · · · · · · ·CHAIRMAN NELSON:··Can you talk into your
11··mic?
12·· · · · · · · ·MR. JOURNEAY:··I'm sorry.··It's aggregated
13··in a number shown on a schedule in the Commission's
14··order, because there is a -- on our schedule for taxes
15··other than FIT -- line item for that.··But to break out
16··this particular number, we would have to go look at the
17··record in the -- in the rate case docket.
18·· · · · · · · ·CHAIRMAN NELSON:··Okay.··I think what
19··might be useful then is have the parties get together
20··and try to decide on -- try to come up with a number.
21··And if they can't agree to it, they can make filings and
22··y'all can review those.··Or would it be simpler just for
23··you to go back and come up with the numbers or have
24··staff making a filing?
25·· · · · · · · ·MR. JOURNEAY:··It might be appropriate for
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·1··the Commission to take notice of that part of the rate
·2··case docket record.
·3·· · · · · · · ·CHAIRMAN NELSON:··Okay.
·4·· · · · · · · ·MR. JOURNEAY:··The number runs, run by
·5··staff for the ALJs, because that's where we found the
·6··numbers.
·7·· · · · · · · ·CHAIRMAN NELSON:··Do we need additional
·8··runs?··That's my question.
·9·· · · · · · · ·MR. JOURNEAY:··We believe the numbers are
10··clearly identifiable on those schedules.··And then I
11··think if you -- to go where I think you want to go -- to
12··allow the parties to comment on those numbers.
13·· · · · · · · ·CHAIRMAN NELSON:··I don't want them to
14··comment.··I really want to understand what the number
15··is.··Because if we -- if we don't understand what it is
16··and we don't give them an opportunity to comment now,
17··we're going to get it on motion for rehearing.··So the
18··only thing I want to keep us from doing is making a
19··mistake on the numbers.··I'm not trying -- I'm not
20··giving them an opportunity to reargue the case.
21·· · · · · · · ·MR. JOURNEAY:··No, no, I was just -- to
22··point to the specific numbers --
23·· · · · · · · ·CHAIRMAN NELSON:··Yes.
24·· · · · · · · ·MR. JOURNEAY:· ·-- that we think they are.
25··And I guess maybe we -- in the staff number runs for the
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·1··ALJs that were filed in that docket -- I know -- I don't
·2··have the front page on the data filing, but it's clearly
·3··identified in the AIS.··There is a Schedule 4 presented
·4··in Staff's number runs there, the taxes other than FIT.
·5··Under payroll taxes there's a line item for FICA that
·6··shows a Commission adjustment of $57,923.
·7·· · · · · · · ·Under "Other Taxes" there's an ESI payroll
·8··taxes line item that shows a Commission adjustment of
·9··121,549.··Because the incentive compensation was some
10··direct Entergy Texas employees and some Entergy Services
11··Incorporated allocated expenses to those employees,
12··there's a big chart in the -- dealing with how the
13··incentive compensation was broken out.
14·· · · · · · · ·CHAIRMAN NELSON:··Okay.··Ken, I have an
15··idea.··So let's have our advising staff to go back and
16··look at this number and come back to us.··In the
17··interim, if y'all feel like you need direction from the
18··parties, you can issue a memo asking for them to file
19··something.··Would that be okay with you, Ken?
20·· · · · · · · ·COMM. ANDERSON:··That's fine.
21·· · · · · · · ·MR. JOURNEAY:··Would you like us to file a
22··memo in this docket to identify these numbers and tell
23··them why we think --
24·· · · · · · · ·COMM. ANDERSON:··I think that would be
25··helpful.
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·1·· · · · · · · ·CHAIRMAN NELSON:··Yes.··That would be
·2··useful.
·3·· · · · · · · ·COMM. ANDERSON:··And then the parties can
·4··comment --
·5·· · · · · · · ·MR. JOURNEAY:··-- comment on whether they
·6··think we saw the right numbers or not.
·7·· · · · · · · ·CHAIRMAN NELSON:··That works.··That sounds
·8··great.
·9·· · · · · · · ·COMM. ANDERSON:··And by the way, just to
10··be clear, I think the judge got right the -- what the
11··denominator versus -- really what we're talking about is
12··coming up with the numerator on the formula.
13·· · · · · · · ·MR. JOURNEAY:··Correct.
14·· · · · · · · ·CHAIRMAN NELSON:··Right.··So I agreed with
15··the PFD on everything except for what we discussed.··So
16··I would uphold the PFD, but we'll do that at the next
17··meeting when you come back with those numbers.
18·· · · · · · · ·COMM. ANDERSON:··And I agree about opening
19··a rulemaking project to look at the issue of recovering
20··attorneys' fees broadly and set some criteria around it.
21·· · · · · · · ·MR. JOURNEAY:··We'll try and get this memo
22··out this afternoon.··I think we should be able to, or,
23··worst case, early tomorrow.··And then I would ask, I
24··guess, the parties to file a response by next Wednesday
25··so that we have it in time for your seven-day package
KENNEDY REPORTING SERVICE, INC.
512.474.2233
Page 20
·1··for the 25th Open Meeting.
·2·· · · · · · · ·CHAIRMAN NELSON:··That's fine.··Okay.
·3·· · · · · · · ·COMM. ANDERSON:··And then also let us know
·4··whether we need to reopen the record in some way to take
·5··judicial notice of the evidence in the rate case.
·6·· · · · · · · ·MR. JOURNEAY:··It might be appropriate for
·7··you to take notice of that today before we start running
·8··these -- shooting all these numbers out.
·9·· · · · · · · ·MS. FERRIS:··Your Honor, if I may, I
10··believe that the ALJ -- this is Sara Ferris with the
11··Office of Public Utility Counsel.··I believe that the
12··ALJs in the proceedings did take notice of the record in
13··the rate case.··That was so that the parties could brief
14··using the evidence in that record.
15·· · · · · · · ·CHAIRMAN NELSON:··Okay.
16·· · · · · · · ·COMM. ANDERSON:··Oh, okay.··Well, can you
17··just verify that?··And if we have to do it next Open
18··Meeting, we can.
19·· · · · · · · ·MR. JOURNEAY:··We will look for that and
20··then we'll go ahead and get this memo out then.
21·· · · · · · · ·CHAIRMAN NELSON:··Okay.··Thank you.··So
22··stay tuned.
23··
24··
25··
KENNEDY REPORTING SERVICE, INC.
512.474.2233
SOAR DOCKET NO. XXX-XX-XXXX
PUC DOCKET NO. 40295
APPLICATION OF ENTERGY § BEFORE THE
TEXAS, INC. FOR RATE CASE § PUBLIC UTILITY COMMISSION OF
EXPENSES PERTAINING TO PUC § TEXAS
DOCKET NO. 39896 §
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OF
NATHAN A. BENEDICT
ON BEHALF OF THE
OFFICE OF PUBLIC UTILITY COUNSEL
November 6, 2012
OPUC Exhibit No. 1
SOAH DOCKET NO. XXX-XX-XXXX
PUC DOCKET NO. 40295
DIRECT TESTIMONY
AND WORKPAPERS
OF NATHAN A. BENEDICT
TABLE OF CONTENTS
I. WITNESS IDENTIFICATION AND SCOPE OF TESTIMONY ............................... 3
III. ETl'S RATE CASE EXPENSES ..................................................................................... 5
APPENDIXA .............................................................................................................................. 12
WORK.PAPERS .......................................................................................................................... 16
Direct Testimony and Workpapers of Nathan A. Benedict
On Behalf of the Office of Public Utility Counsel
SOAH Docket No. XXX-XX-XXXX; PUC Docket No. 40295
Page 2 of79
I I. WITNESS IDENTIFICATION AND SCOPE OF TESTIMONY
2 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
3 A. My name is Nathan A. Benedict. My business address is 1701 North Congress Avenue,
4 Suite 9-180, Austin, Texas 7870 I.
5 Q. PLEASE STATE YOUR CURRENT EMPLOYMENT.
6 A. I am employed as Assistant Director of Regulatory Analysis for the Office of Public
7 Utility Counsel ("OPUC").
8 Q. PLEASE STA TE YOUR EDUCATIONAL BACKGROUND.
9 A. I hold a Bachelor of Arts degree in Economics and German from the University of the
10 Pacific, a Master of Arts in Economics from California State University, East Bay, and a
11 Master of Science in Economics from The University of Texas at Austin. My graduate
12 studies included substantial training in statistics and econometrics as well as
13 specialization in the fields of public finance and industrial organization. A summary of
14 my educational background is included in Appendix A.
15 Q. PLEASE STATE YOUR PROFESSIONAL BACKGROUND.
16 A. I have over eleven years of experience in the utility industry. From 1998 to 2005, I
17 worked for Pac-West Telecomm, a Competitive Local Exchange Carrier ("CLEC"). I
18 held various management positions within Pac-West's operations group, including
19 management of the team responsible for provisioning Directory Assistance, E91 l, Local
20 Number Portability, and local loops in tandem with incumbent carriers in Pac-West's
21 service territory. From 2005 to 2006, I consulted for another CLEC, Telepacific, where I
22 designed voice and data networks for small- to medium-sized commercial customers.
Direct Testimony and Workpapers of Nathan A. Benedict
On Behalf of the Office of Public Utility Counsel
SOAH Docket No. XXX-XX-XXXX; PUC Docket No. 40295
Page 3 of79
I Since 2008, I have taught courses in microeconomics and macroeconomics as an adjunct
2 faculty member of Austin Community College. I began my tenure with OPUC in 2008.
3 A summary of my professional background is included in Appendix A.
4 Q. HAVE YOU PREVIOUSLY TESTIFIED REGARDING ELECTRIC UTILITY
5 MATTERS?
6 A. Yes. Appendix A includes a list of the cases in which I have testified.
7 Q. WHAT IS THE SUBJECT OF YOUR TESTIMONY?
8 A. My testimony addresses the amount of rate case expenses requested by Entergy Texas,
9 Inc. ("ETI" or "Company")
10 Q. PLEASE SUMMARIZE YOUR CONCLUSIONS.
11 A.
12 With respect to the overall amount of rate case expenses ETI is
13 allowed to recover, the expenses must be reasonable in order to be recovered, but the
14 Conunission is not required to grant recovery of every reasonable expense. Other
15 considerations, such as the frequency of rate cases, the overall amount of rate case
16 expenses in comparison to the granted rate increase, and the nature of the utility's rate
17 case request should be important components of the Conunission's review. Based on
18 these considerations, I recommend a reduction to ETI's request of between 14.5 and 73.6
19 percent. 1
1
This results in a recommended disallowance ranging from $1,269,123 to $6,441,896.
Direct Testimony and Workpapers of Nathan A. Benedict
On Behalf of the Office of Public Utility Counsel
SOAH Docket No. XXX-XX-XXXX; PUC Docket No. 40295
Page 4 of79
I n.
- - - - -- -- -
2 Q.
3
4 A.
5
6 Q.
7 A.
8
9
10
11
12
13
14
15
- ID. ETl'S RATE CASE EXPENSES
16 Q. WHAT IS THE AMOUNT OF ETl'S REQUESTED RATE CASE EXPENSES?
17 A. ETI has requested recovery of $8,752,576 in rate case expenses related to Docket
18 No. 39896 and incurred through September 30, 2012. 4
2
Docket No. 39896, Schedule P-5 at 41-42.
3
Compliance Tariff ofAEP Texas Central Company Pursuant to Final Order in Docket No. 31433 Severed
from Docket No. 28840, Docket No. 32385, Compliance Rider, Attachment Bat 3.
4
Supplemental Direct Testimony of Michael P. Considine, Exhibit MPC-SD-5 at 1 (October 25, 2012).
Direct Testimony and Workpapers of Nathan A. Benedict
On Behalf of the Office of Public Utility Counsel
SOAH Docket No. XXX-XX-XXXX; PUC Docket No. 40295
Page 5 of79
I Q. ARE THERE ANY OVERARCHING POLICY ISSUES THE COMMISSION
2 SHOULD CONSIDER WHEN REVIEWING RATE CASE EXPENSES?
3 A. Yes. Even when all of a utility's rate case expenses are deemed reasonable, the
4 Commission is not required to grant dollar-for-dollar recovery. PURA Sec. 36.06l(b)(l)
5 gives the Commission discretion in allowing recovery of rate case expenses, stating that
6 the regulatory authority "may allow'' as an expense the reasonable cost of participating in
7 the rate case. From a policy perspective, as the frequency of rate cases increases, it
8 becomes increasingly important to manage the cost of rate cases borne by ratepayers. 5 In
9 this docket, ETI's rate case expenses are substantial in comparison to the revenue
10 increase granted in Docket No. 39896, which is the Company's third base rate case in
11 little more than four years. Furthermore, the Company opted to litigate certain issues for
12 which Commission precedent is long-established and clear. The cost of challenging
13 Commission precedent on these issues forms part of the total rate case expenses ETI has
14 requested to recover from ratepayers.
15 Q. HOW DOES ETl'S RATE CASE EXPENSE REQUEST COMPARE TO THE
16 REVENUE INCREASE GRANTED IN THE RATE CASE AND TO ITS RATE
17 CASE EXPENSE IN PRIOR DOCKETS?
18 A. ETI's rate case resulted in a revenue increase of approximately $27.7 million on an
19 annual basis. 6 ETI's rate case expenses of approximately $8.75 million represent over 30
5
Aside from base rate cases, ET! can also update its EECRF and TCRF on an annual basis, and may soon
have a PCRF mechanism available to it.
6
Docket No. 39896, ETl's Letter to Commissioners Regarding Corrections to Commission's Final Order
in Docket No. 39896.
Direct Testimony and Workpapers of Nathan A. Benedict
On Behalf of the Office of Public Utility Counsel
SOAH Docket No. XXX-XX-XXXX; PUC Docket No. 40295
Page 6 of79
I percent of the actual revenue increase the Company was granted by the CommissioK
2 comparison, ETI's 2007 rate case, Docket No. 34800, resulted in a stipulated revenue
3 increase of $46.7 million and rate case expenses of $2.3 million per year for three years
4 to be recovered through a rider. 8•9 Docket No. 34800 involved two Hearings on the
5 Merits and myriad settlement negotiations. ETI's 2009 rate case, Docket No. 37744,
6 resulted in a stipulated revenue increase of $59 million effective August 5, 20 I 0 and an
7 additional increase of $9 million effective May 2, 2011. The revenue increase included
8 an unspecified amount for rate case expenses to be fully amortized in 20 I 0. 10 Thus, in
9 recent years, ETI' s ratepayers have borne the twin burdens of rate increases occurring
10 more frequently while also paying for the substantial litigation costs associated with the
11 rate increases.
12 Q. WERE SOME OF ETI'S RATE CASE EXPENSES INCURRED TO
13 CHALLENGE SETTLED PRECEDENT?
14 A. Yes. Part of the litigation costs in Docket No. 39896 relates to issues for which
15 Commission precedent is clear. As part of its statutory discretion, the Commission could
16 consider the degree to which ETI has overreached in its rate case when considering the
17 amount of litigation expenses allowed for recovery. I will provide a few examples to
18 illustrate this issue.
7
lJ:le $8.75 urlllion figure does not inelttd:e Cities' rate case e1cf1BHses efa13pr0ximately $1.2 miUioo,-9--
8 The rider appeared on bills during 2009, 2010, and 2011.
9
Application ofEntergy Gui[ States, Inc.for Authority to Change Rates and Reconcile Fuel Costs, Docket
No. 34800, Order at 5, (Findings of Fact Nos. 24 and 27) (March 16, 2009).
0
' Application ofEntergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No.
37744, Order at 5, (Findings of Fact Nos. 16 and 18) (December 13, 20 IO).
Direct Testimony and Workpapers of Nathan A. Benedict
On Behalf of the Office of Public Utility Counsel
SOAH Docket No. XXX-XX-XXXX; PUC Docket No. 40295
Page 7 of79
I ETI's rate filing package included a request to recover financial-based incentive
2 compensation. The ALJs note that all parties to the rate case, including ETI, agree that
3 Commission precedent allows recovery of only one type of incentive-based
4 compensation. While compensation tied to operational goals is recoverable,
5 compensation tied to financial goals is not. 11 ETI, nonetheless, requested recovery of all
6 incentive compensation costs, including those related to financial measures. Consistent
7 with its long-standing precedent, the Commission disallowed $6,196,037 in financially-
8 based incentive compensation. 12
9 A well-established criterion for the inclusion of an expense in rates is that the
10 expense be known and measurable. ETI requested an additional $9 million in
11 transmission equalization expense beyond the test year level. The Company's
12 transmission equalization expenses are affected by changes in transmission investment
13 made by the other Entergy Operating Companies. ETI estimated the transmission
14 projects to be completed by the other Operating Companies through the end of the rate
15 year to compute its adjustment. The ALJs found that because these projects are largely
16 not yet built, and may never be built, use of these projects to make an adjustment to test
17 year transmission equalization expense does not represent a known and measurable
18 change.13 In turn, the Commission denied ETI' s request to add $9 million to its
19 transmission equalization expense. 14
11
Docket No. 39896, Proposal for Decision at 166.
12
Docket No. 39896, Order at 24-25, (Findings ofFact Nos. 127-134) (September 14, 2012).
13
Docket No. 39896, Proposal for Decision at 116.
14
Docket No. 39896, Order at 20, (Findings ofFact Nos. 87 -94) (September 14, 2012).
Direct Testimony and Workpapers of Nathan A. Benedict
On Behalf of the Office of Public Utility Counsel
SOAR Docket No. XXX-XX-XXXX; PUC Docket No. 40295
Page 8 of79
I Finally, instead of including purchased capacity costs in base rates, ETI requested
2 a purchased capacity rider in the rate case despite the fact that the Commission already
3 had a pending rulemaking to determine the structure of such a rider for all generating
4 utilities. Indeed, the Commission ultimately determined that the purchased capacity rider
5 requested by ETI should not be considered in the rate case due to the pending
6 rulemaking. 15
7 While the Commission has the authority to grant the utility recovery of costs
8 reasonably incurred in the litigation of its rate case, it is not required to do so. If there
9 were no room for discretion, the Legislature would not have used the word "may" when
10 giving the Commission the authority to grant recovery of rate case expenses. And
11 without the Commission having discretion, rate case expense proceedings would be mere
12 accounting exercises. A utility's request for recovery of rate case expenses should be
13 considered in the larger context. The frequency of rate cases, the amount of rate case
14 expenses relative to the size of the rate increase, and the type of relief requested by the
15 utility in its rate case should affect the outcome of the rate case expense docket.
16 Q. SHOULD ETI BE ALLOWED TO RECOVER THE FULL AMOUNT OF ITS
17 RATE CASE EXPENSES?
18 A. No. The policy considerations I have discussed warrant a reduction to ETI' s recoverable
19 rate case expenses. In addition, by exercising its discretion to limit rate case expenses,
20 the Commission can encourage settlement of rate cases. Settlement reduces the cost of
21 participation to all parties involved. Additionally, shifting a portion ofrate case expenses
15
Docket No. 39896, Supplemental Preliminary Order at 2 (January 19, 2012).
Direct Testimony and Workpapers of Nathan A. Benedict
On Behalf of the Office of Public Utility Counsel
SOAH Docket No. XXX-XX-XXXX; PUC Docket No. 40295
Page 9 of79
I from ratepayers to shareholders when challenging well-settled principles of ratemaking
2 will encourage a utility to carefully consider the degree to which it requests forms of
3 relief that run afoul of Commission precedent.
4 Q. HOW LARGE OF A REDUCTION TO RECOVERABLE RATE CASE
5 EXPENSES DO YOU RECOMMEND?
6 A. I suggest an upper and lower bound for any reduction the Commission decides to
7 implement. ETI was granted a rate increase of$27.7 million in Docket No. 39896, which
8 is $77.1 million less than the Company's request of $104.8 million. Because the
9 Commission reduced ETI's requested rate increase by approximately 73.6 percent, I
10 believe that it is reasonable to reduce ETI' s recoverable rate expenses by the same
11 percentage. This 73 .6 percent reduction forms the upper bound of my recommendation.
12 The lower bound of my recommendation is formulated by considering the
13 elements of ETl's base rate case that challenged clear Commission precedent. As
14 described earlier in my testimony, ETI requested recovery of financial-based incentive
15 compensation and a projected increase in transmission equalization costs, both of which
16 were denied by the Commission. The Company's request for recovery of financial-based
17 incentive compensation and the pursuit of a change to transmission expense that was
18 neither known nor measurable clearly contradict Commission precedent. It is not
19 reasonable for ratepayers to pay ETI's litigation expenses on these issues. Combined,
20 these issues contributed $15 .2 million to ETI' s requested rate increase of $104 .8 million,
21 and the disallowance associated with these issues reduced ETI's requested increase by
22 14.5 percent. Thus, a reasonable lower bound to the Commission's reduction to ETI's
Direct Testimony and Workpapers ofNathan A. Benedict
On Behalf of the Office of Public Utility Counsel
SOAH Docket No. XXX-XX-XXXX; PUC Docket No. 40295
Page 10of79
1 rate case expenses is 14.5 percent. Of course, this lower bound is based on the issues I
2 have identified and could be adjusted upward based on the testimonies and
3 recommendations of other parties to this docket.
4 Given my recommended band of 14.5 percent to 73.6 percent, it would be
5 reasonable to disallow between $1,269,123 and $6,441,896 of ETI's requested
6 $8,752,576 in rate case expenses.
7 Q. DOES TIDS CONCLUDE YOUR TESTIMONY?
8 A. At this time, yes.
Direct Testimony and Workpapers of Nathan A. Benedict
On Behalf of the Office of Public Utility Counsel
SOAH Docket No. XXX-XX-XXXX; PUC Docket No. 40295
Page 11 of79
APPENDIX A
12
EDUCATIONAL AND EMPLOYMENT HISTORY
NATHAN A. BENEDICT
EDUCATION
M.S., Economics.
Fields: Public Finance
Industrial Organization
The University of Texas at Austin, 2008
M.A., Economics.
California State University, East Bay, 2005
B.A., Economics, German.
University of the Pacific, 1999
EMPLOYMENT HISTORY
Assistant Director, Regulatory Analysis
Office ofPublic Utility Counsel
State of Texas
October 2008 - Present
Adjunct Assistant Professor, Economics
Austin Community College
January 2008 - Present
Teaching Assistant
Introductory Economics
The University of Texas at Austin
August 2007 - May 2008
Research Assistant
Human Investment Research and Education (HIRE) Center
California State University, East Bay
July 2005 - July 2006
Service Engineer
US. Telepacific Corp.
July 2005 - May 2006
13
Teaching Assistant
Introductory Economics
California State University, East Bay
August 2005 - December 2005
Customer Relations Manager
Senior Corporate Trainer
Cross-Functional Assessment Manager
Ordering and Provisioning Manager
Pac-West Telecomm, Inc.
April 1998 - March 2005
Testimony presented before the Texas Public Utility Commission:
Subject
No. 39896
Revenue Requirement; Cost
Application of Entergy Texas, Inc. for Authority to
Allocation; Rate Design
Change Rates and Reconcile Fuel Costs
No. 39366
Application of Entergy Texas, Inc. for Authority to
Allocation of Energy Efficiency
Redetermine Rates for the Energy Efficiency Cost
Performance Bonus
Recovery Factor Tari.ff and Request to Establish a
Revised Energy Efficiency Goal and Cost Caps
No. 38306
Texas-New Mexico Power Company's Request for AMS Communications Network;
Approval of Advance Metering System (AMS) Discretionary Service Charges; Low-
Deployment and AMS Surcharge Income Programs
No. 37744 Product Solicitation Process; Product
Application of Entergy Texas, Inc. for Authority to Pricing; Miscellaneous Electric
Change Rates and Reconcile Fuel Costs Service Charges; Rate Riders
No. 37482
Product Solicitation Process and
Application of Entergy Texas, Inc. for Approval of a
Product Pricing
Power Cost Recovery Factor
No. 36952
Application of CenterPoint Energy Houston Electric,
Computation of Energy Efficiency
LLC to Defer Energy Efficiency Cost Recovery and
Performance Bonus
for Approval of an Energy Efficiency Cost Recovery
Factor
14
No. 36851
Application of the Electric Reliability Council of Project Funding Sources and
Texas, Inc. for Approval of a Revised Nodal Market Surcharge Allocation
Implementation Surcharge
No. 36025
Revenue Requirement; Cost
Application of Texas-New Mexico Power Company
Allocation; Rate Design
for Authority to Change Rates
15
WORKPAPERS
16
,
PROCEEDING TO CONSIDER RATE §
CASE EXPENSES SEVERED FROM §
DOCKET NO. 28840 (APPLICATION OF §
AEPTEXASCENTRALCOMPANYFOR §
AUTHORITY TO CHANGE RATES) §
§
ORDER
'This Order addresses the recoverable rate-case expenses.of AEP Texas Central Company
(AEP Central) and of Cities1 in connection with their participation in Docket No. 28840.2 As set
forth in this Order, the Public Utility Commission of Texas (Commission) determines that AEP
Central's recoverable rate case expenses through June 2005 are $2,938,130 and that Cities'
recoverable rate case expenses are $1,350,149. As discussed herein, the Cities' expenses relating to
witness Sarah Goodfriend have been reduced by one-half as recommended by the State Office of
Administrative Hearings (SOAR) Administrative Law Judges in their Proposal for Decision (PFD)
in Docket No. 28840.3 'This Order finds that $4,288,429 in rate-case expenses incurred by AEP
Central and Cities is reasonable and necessary and authorizes AEP Central to implement a
surcharge over three years to recover this amount.
I. Procedural History
On November 3, 2003, AEP Central filed an application seeking a change in its rates. 'This
application was assigned Docket No. 28840, and the Commission referred the case to SOAH on
November 4, 2003. SOAH issued its initial PFD in Docket No. 28840 on July 1, 2004, which
contained certain findings on rate case expenses. In July and August-2004, the Commission issued
two orders on remand in Docket No 28840 directing SOAH to consider further and provide further
evaluation of certain specified issues, none of which involved rate case expenses. On November
1
Alice, Aransas Pass, Carrizo Springs, Dilley, Donna, Eagle Lake, Freer, Ganado, George West, Ingleside,
Kingsville, LaFeria, Laguna Vista, La Joya, Leakey, Los Fresnos, Lyford, Lytle, McAllen, Mercedes, Mission,
Nordheim, Odem, Pharr, Port Aransas, Portland, Port Lavaca, Poteet, Rancho Viejo, Refugio, Rio Hondo, Rwige, San
Benito, San Juan, Sinton, Uvalde, and Weslaco (collectively, Cities).
2
Application of AEP Texas Central Company for Authority to Change Rates. Docket No. 28840, Order (Aug.
IS, 2005).
3
Docket No. 28840, Proposal for Decision at 121-127, 205 (FOF 210-216), 209 (FOF 256)(Jul. I, 2004).
3:1- 17
DOCKET NO. 31433 ORDER PAGE2
'
16, 2004, SOAH issued its Remand PFD. In addition, the Commission held hearings on certain
matters relating to merger savings and affiliated expenses on March 3, 4, and 7. The Commission
issued its final order in Docket No. 28840 on August 15, 2005. In that order, the Commission
severed the determination of the reasonableness and necessity of rate case expenses to this
proceeding, Docket No. 31433.4 While rate-case expenses were not addressed on the remand
SOAH hearing and the Commission-held hearing, Cities and AEP incurred additional expenses as a
result of these hearings, and submitted updated information on these additional expenses. Based on
the submission, the Commission decided to sever the determination on rate-case expenses to
examine this additional evidence. 5
By Order No. 1 in this proceeding, AEP Central and Cities were directed to file detailed
supporting documentation of their requested rate case expenses. On September 9, 2005, AEP
Central and Cities filed such supporting documentation. On September 16 and October 10, 2005,
AEP Central made supplemental filings that furnished additional supporting documentation with
respect to certain of its requested expenses.
On October 14, 2005, the parties filed statements of position and on October 28, 2005, AEP
Central filed its Motion for Ruling on Disputed Issue and Conditional Request for a Hearing. On
December 12, 2005, the presiding officer issued Order No. 4, which requested clarification
regarding contested issues. On December 22, 2005, the parties filed responses to Order No. 4.
The parties' filings established that there are no contested factual issues in Docket
No. 31433 that have not been fully litigated in Docket No. 28840. To the extent AEP Central had
previously conditionally requested a hearing, that request was withdrawn by AEP Central's
December 22, 2005 filing. The sole disputed issue is the recoverability of one-half of Cities' witness
· Sarah Goodfriend' s expenses, which the SOAH ALJs had recommended be disallowed in their PFD
in Docket No. 28840 issued on July 1, 2004. Since there are no contested factual issues that have
not already been fully litigated, an evidentiary hearing on the merits is not necessary or appropriate.
The disposition of the sole contested issue is discussed in the subsequent" section of this Order.
'Docket No. 28840, Order at 60 (Ordering, S) (Aug. IS, 2005).
' Open Meeting Tr. at 54-62 (July 29, 2005).
18
DOCKET NO. 31433 ORDER PAGE3
II. Recoverability of One-Half of Dr. Goodfriend's Expenses
In Docket No. 28840, AEP Central submitted testimony challenging the quality of a survey
that fonned the basis of testimony submitted by Cities witness, Dr. Sarah Goodfriend. 6 Following a
full evidentiary hearing and briefing on this and other issues, the SOAH ALJs recommended that
one-half of Dr. Goodfriend's expenses be disallowed because they found that the methodology of
the survey she conducted was "seriously flawed." 7
In severing the issue of rate case expenses from Docket No. 28840 to this proceeding, the
Commission intended that the entire evidentiary record in Docket No. 28840 on rate case expenses
as well as the Commission's initial decisions be carried over to this case. Thus, the evidentiary
record on the quality of Dr. Goodfriend' s work underlying her testimony in Docket No. 28840 and
the SOAH ALJs' findings regarding the recoverability of one-half of her expenses are before the
Commission for decision in this proceeding. The purpose of the severance, however, was to
evaluate the detailed supporting documentation on updated rate-case expenses submitted by AEP
Central and Cities.8 This proceeding was not initiated as a forum for Cities to re-litigate Dr.
Goodfriend's expenses.
The Commission had previously found that the ALJs correctly determined that one-half of
Dr. Goodfriend's expenses should be disallowed9 because the survey she conducted ''was seriously
flawed and that conclusions drawn from the data cannot be reasonably supported under current legal
standards." 10 The Commission reaffinnS this determination, and therefore, the Commission adopts
the SOAH ALJs' finding that one-half of Dr. Goodfriend's expenses should be disallowed. In
addition, as there are no other outstanding contested issues related to the rate-case expense
information submitted in Docket No. 28840 or the additional rate-case expense infonnation
6
See Docket No. 28840, Proposal for Decisioo at 121-127, 205 (FOF 212) (Jul. I, 2004).
7
Id at 125.
1
See Open Meeting Tr. at 62 (Jul. 29, 2005).
9
Open Meeting Tr. at 196-198 (January 13, 2005).
10
Docket No. 28840, Proposal for Decision at 125 (Jul. I, 2004).
19
DOCKET NO. 31433 ORDER PAGE4
submitted in this docket, the Commission finds that the rate-case expenses of $2,938,130 for AEP
Central and $1,350,299 for Cities are reasonable and necessary.
III. The SOAH AL.ls' Findings and Conclusions in Docket No. 28840
In the PFD issued on July 1, 2004, in Docket No. 28840, the SOAH ALJs included Finding
of Fact Nos. 210 through 216 and Conclusion of Law No. 58 addressing rate case expenses. The
SOAH ALJs' findings were issued prior t-0 the updating by AEP Central and Cities of their rate case
expenses in their filings described in Finding of Fact No. 15. Thus, in order to reflect the updated
factual evidence filed in Docket No. 31433 and certain other corrections described below, the
Commission modifies the SOAH ALJs' Finding of Fact Nos. 210 through 216 as follows.
Finding of Fact Nos. 22 through 25 of this Order modify the SOAH ALJs' Finding of Fact
No. 210 to reflect the updated amounts of rate case expenses found reasonable and necessary for
AEP Central after reflecting the disallowance recommended by Staff; Finding of Fact No. 27 of
this Order modifies the SOAH ALJs' Finding of Fact No. 211 to reflect the updated amount of
Cities' requested rate case expenses. Finding of Fact Nos. 28 and 29 of this Order modify the
SOAH ALJs' Finding of Fact No. 212 to reflect the updating of Dr. Goodfriend's portion of Cities'
requested rate case expenses. Finding of Fact Nos. 31 and 32 of this Order adopt the SOAH ALJs'
Finding of Fact Nos. 214 and 215. Finding of Fact No. 33 of this Order modifies the SOAH ALJs'
Finding of Fact No. 216 to reflect the amounts found reasonable and necessary by the Commission
based on the updated information in this proceeding and corrects it to reflect that the rate case
expenses will be collected through a three-year surcharge and not through cost of service. Finding
of Fact No. 34 of this Order supplements the SOAH ALJs' Finding of Fact No. 256 to reflect the
updated amounts for AEP Central's and Cities' rate case expenses found reasonable and necessary
by this Order. Finding of Fact No. 35 reflects the Commission's policy decision, in accordance
with its decision in Docket No. 30706,11 that AEP Central not be permitted to recover estimated
appeal costs in this proceeding, but that AEP Central be afforded the opportunity to recover in its
next rate case any reasonable and necessary expenses for Docket Nos. 28840 and 31433 that it
11
Application of CenterPoinJ Energy Houston Electric, UC for a Competition Transition Charge, Docket No.
30706, Order at 28-29, 47 (COL 28) (Jul. 14, 2005).
20
DOCKET NO. 31433 ORDER PAGES
subsequently incurs that exceed the amounts found reasonable and necessary by this Order. Finally,
Conclusion of Law No. 6 in this Order incorporates the SOAH ALJs' Conclusion of Law No. 58.
The Commission adopts the following findings of fact and conclusions oflaw:
IV. Findings of Fact
A. Background and Procedural Matters
1. AEP. Central is an electric utility providing transmission and distribution (T&D) services in
a 44,000 square·mile area of South Texas that includes the portion of Texas from just south
of San Antonio to the Mexican border and from Bay City west to Eagle Pass. AEP Central's
service area is located within the Electric Reliability Council of Texas (ERCOT).
2. On November 3, 2003, AEP Central filed an application with the Commission to change its
T&D rates. The Commission assigned AEP Central' s application to Docket No. 28840.
3. Concurrent with filing its application with the Commission, AEP Central filed a similar
petition and statement of intent with each incorporated city in its certificated service area
that retains jurisdiction over its retail rates. Eighty-six (86) cities denied AEP Central's
petition and statement of intent. AEP Central filed petitions for review of those denials and
filed motions to consolidate those petitions for review into Docket No. 28840.
4. On November 4, 2003, the Commission referred AEP Central's application in Docket
No. 28840 to SOAH to conduct an evidentiary hearing on the merits and issue a PFD.
5. The following parties intervened and participated in the hearing in Docket No. 28840:
Cities; Texas Industrial Energy Consumers (TIEC); CPL Retail Energy (CPL Retail);
Coalition of Commercial Ratepayers (CCR); City of Garland, Alliance for Retail Markets
(ARM); TXU Business Services (TXU); Texas Legal Services Center and Texas
Ratepayers' Organization to Save Energy (TLSCROSE); South Texas Electric Cooperative,
Inc. (STEC); State of Texas; Office of Public Utility Counsel (OPC); and Commission Staff
(Staff).
21
DOCKET NO. 31433 ORDER PAGE6
6. In Docket No. 28840, AEP Central requested approval of a revenue requirement of $519.9
million, based on an historical test year of July 1, 2002, through June 30, 2003. Of that
amount, $426.6 million was for providing retail T&D service (including the portion of the
ERCOT -wide transmission costs) and $93.3 million for providing wholesale transmission
service.
7. The evidentiary hearing on the merits in Docket No. 28840 was held on March 2 through
March 18, 2004.
8. On July 1, 2004, the SOAH ALJs assigned to hear Docket No. 28840 issued their PFD. The
PFD contained certain findings with respect to rate case expenses.
9. The Commission issued orders on July 28 and August 25, 2004, remanding portions of
Docket No. 28840 to SOAH, none of which involved rate case expenses.
10. On November 16, 2004, the SOAH ALJs issued their Remand PFD in Docket No; 28840.
11. On March 3, 4, and 7, 2005, the Commission held hearings on merger savings and affiliate
expenses.
12. On August 15, 2005, the Commission issued its final order in Docket No. 28840. In
Ordering Paragraph 5 of that order, the Commission severed the determination of the
reasonableness and necessity of rate case expenses into this proceeding, Docket No. 31433.
All portions of the evidentiary record in Docket No. 28840 relevant to rate case expenses are
part of the evidentiary record in this Docket No. 31433.
13. On August 26, 2005, the presiding officer issued Order No. 1, which required the parties to
file evidence of rate case expenses and directed AEP Central and Cities to file supporting
"
detailed documentation for their requested rate case expenses. Order No. 1 also made all
parties to Docket No. 28840 parties to this proceeding.
22
DOCKET NO. 31433 ORDER PAGE7
14. On August 29, 2005, Cities requested clarification from the presiding officer regarding the
extent of the supporting documentation the Cities were required to submit under Order
No. I.
15. On August 30, 2005, Order No. 2: Clarification of Order No. 1, was issued informing Cities
that:
The entirety of the rate case expenses will be considered in this proceeding.
To the extent supporting documentation for expenses prior to September
2004 is in the record of Docket No. 28840, Cities may simply provide the
relevant cite to the record. If the supporting documentation for expenses is
not in the Docket No. 28840 record, that information should be submitted in
this proceeding.
16. On September 9, 2005, AEP Central and Cities filed supporting documentation for their
requested rate case expenses, consisting of invoices, timesheets, receipts, etc. On September
16 and October 10, 2005, AEP Central filed supplemental information related to certain of
its requested rate case expenses.
17. On September 19, 2005, the presiding officer established a procedural schedule for this
docket. In accordance with the procedural schedule, statements of position were due on
October 14, 2005, and requests for hearing were due on October 28, 2005.
18. On October 14, 2005, AEP Central, Cities, and Staff filed statements of position. In its
statement of position, Staff questioned certain items of AEP Central' s rate case expenses as
lacking adequate supporting documentation. in its statement of position, AEP Central stated
that the SOAH ALJs had recommended that one~half of Dr. Goodfriend's expenses be
disallowed and noted that Cities' requested rate case expenses included the entire amount
billed by Dr. Goodfriend to Cities, and not one-half of that amount. In its statement of
position, Cities indicated that they did not contest any of AEP Central' s rate case expenses,
but indicated that if Cities' request associated with Dr. Goodfriend' s work was contested,
then Cities would urge that the standard applied to Dr. Goodfriend be applied to AEP
Central' s experts.
23
DOCKET NO. 31433 ORDER PAGES
19. On October 28, 2005, AEP Central filed a motion for ruling on a disputed issue and
conditionally requested a hearing seeking a Commission ruling on whether, by severing rate
case expenses from Docket No. 28840, it intended to reopen for litigation the issue of Dr.
Goodfriend' s expenses which had been fully litigated in Docket No. 28840. AEP Central 's
pleading also included an identification of the portions of the record in Docket No. 28840
that addressed the issue of the quality of Dr. Gooclfriend's work and the recovery of her rate
case expenses.
20. On December 12, 2005, the presiding officer issued Order No. 4, which requested a
clarification regarding a contested issue and directed Staff to file a list of disputed factual .
issues and a list of threshold legal and policy issues that must be addressed before this
proceeding can be resolved, and permitting AEP Central and Cities to make similar filings.
21. On December 22, 2005, AEP Central and Cities filed their responses to Order No. 4. In its
response, AEP Central withdrew its conditional request for a hearing.
22. Based on the filings of the parties set forth in Finding of Fact Nos. 16, 18, 19, and 21, the
Commission finds that no factual matters that have not already been fully litigated in Docket
No. 28840 are at issue or disputed. The only disputed issue in this proceeding involves the
recoverability of one-half of Cities' witness Gooclfriend's expenses, which has been
subjected to a full contested case evidentiary hearing, briefing, and the issuance by the
SOAH ALJs of a PFD in Docket No. 28840.
B. AEP Central's Rate Case Emenses
23. Based on its filing of September 9, 2005, as supplemented by its filings of September 16 and
October 10, 2005, AEP Central sought recovery of $2,962, 734 in recoverable rate case
expenses for Docket No. 28840 through June 2005.
24. In its statement of position filed on October 14, 2005, Staff ·questioned whether $24,604 of
AEP Central's requested rate case expenses were supported by adequate underlying
documentation and recommended disallowance of these expenses.
24
DOCKET NO. 31433 ORDER PAGE9
25. In its filing of October 28, 2005, AEP Central indicated that it did not contest Staff's
recommendation to disallow $24,604 of AEP Central's requested rate case expenses.
26. AEP Central's reasonable and necessary rate case expenses for Docket No. 28840 as of June
2005 are $2,938,130.
C. Cities' Rate Case Emenses
27. In its filing of September 9, 2005, Cities requested rate case expenses for Docket No. 28840
of $1,391,925. This amount consisted of $1,166,925 in expenses actually incurred through
July 2005 and $225,000 in estintated expenses including appeals.
28. Cities' actual expenses of $1,166,925 through July 2005 included $83,253 billed by Cities'
witness Sarah Goodfriend.
29. The Commission adopts the SOAH ALJs' finding regarding disallowance of one-half of Dr.
Goodfriend' s expenses from Docket No. 28840 because of the inadequacies in the survey
she performed. The record indicates that Dr. Goodfriend has billed the Cities $83,253;
therefore a disallowance of one-half of her fees is $41,626.
30. Based on Findings of Fact Nos. 27 through 29, Cities' recoverable rate case expenses are
$1,350,299.
31. AEP Central 's proposal to disallow Cities' witness Starnes expenses is not appropriate
because the principal rate design issues raised by Cities benefit other rate payers.
32. Cities' rate case expenses are system costs that should be home by all ratepayers because
other ratepayers benefit from the Cities' participation.
D. Rate Case Expense Surcharge
33. Based on Finding of Fact Nos. 26 and 30, the aggregate amount of rate case expenses found
reasonable and necessary for AEP Central and Cities are $4,288,429.
25
DOCKET NO. 31433 ORDER PAGE IO
34. It is appropriate for AEP Central to surcharge the aggregate rate case expenses found
reasonable and necessary in Finding of Fact No. 33 to be collected from all customers over
three years.
E. Subsequent Rate Case Expenses
35. To the extent AEP Central incurs rate case expenses foi: Docket Nos. 28840 and 31433 after
June 2005, it is reasonable for it to recover such expenses in its next rate clise to the extent it
demonstrates that such additional expenses are reasonable and necessary. Also, to the extent
that Cities incur rate case expenses for Docket Nos. 28840 and 31433 after July 2005 that
cause Cities' aggregate rate case expenses to exceed the amount found recoverable by this
Order, it is reasonable for AEP Central to recover such expenses in its next rate case to the
extent found reasonable and necessary.
V. Conclusions of Law
1. AEP Central is an electric utility as defined by §§ 31.002 of the Public Utility Regulatory
Act, TEX. UTIL. CODE.ANN.§§ 11.001-66.017 (Vernon 1998 & Supp. 2005) (PURA) and is
therefore subject to the Commission's jurisdiction under PURA §§ 32.001, 33.051, and
36.102.
2. AEP Central is a T&D utility as defined in PURA § 31.002(19).
3. SOAH had jurisdiction over all matters relating to the conduct of the hearing in Docket No.
28840, including the preparation ofa Proposal for Decision pursuant to PURA§ 14.053 and
TEX. Gov'T CODE ANN.§ 2003.049(b).
4. AEP Central met its burden of proof regarding the amount of its rate case expenses for
Docket No. 28840 through June 2005 found reasonable and necessary in Finding of Fact No.
26.
26
DOCKET NO. 31433 ORDER PAGEll
5. With the exception of the Cities' rate case expenses disallowed in Finding of Fact No. 29,
Cities met their burden of proof that their rate case expenses for Docket No. 28840 are
reasonable and necessary.
6. Cities are entitled to reimbursement for their rate case expenses as customers, as well as for
being regulatory authorities.
7. The evidentiary record in Docket No. 28840 on rate case expenses, including the portion
related to the quality of work performed by Dr. Goodfriend underlying her testimony
submitted in Docket No. 28840 identified in AEP Central's pleading described in Finding of
Fact No. 19, is part of the evidentiary record in this case together with the additional
supporting documentation filed by AEP Central and Cities in this proceeding as discussed in
Finding of Fact No. 16.
8. No contested issues of fact beyond those that were fully litigated, argued, and heard by the
SOAH ALJs in Docket No. 28840 have been raised in this proceeding; therefore, there is no
need for any further evidentiary hearing on the merits on recoverable rate case expenses in
addition to those already held in Docket No. 28840.
9. When the issue of the quality of the work underlying Dr. Gooclfriend's testimony in Docket
No. 28840 was litigated before and the issue of the recoverability of her rate case expenses
was briefed to the SOAH ALJs, Cities had the opportunity to challenge the quality of AEP
Central's ex~' substantive work and the recovery of their rate case expenses under the
standard applied by the SOAH ALJs to Dr. Gooclfriend's expenses. Cities failed to take
advantage of that opportunity and no additional evidentiary hearing on the merits is
appropriate in this proceeding as to that matter.
VI. Ordering Paragraphs
In accordance with these findings of fact and conclusions of law, the Commission issues the
following Order:
27
DOCKET NO. 31433 ORDER PAGE 12
1. The additional supporting documentation filed by AEP Central and Cities on
September 9, 2005, and by AEP Central on September 16 and October 10, 2005, as
discussed in Finding of Fact No. 16 above, is admitted into the evidentiary record of this
Docket No. 31433.
2. To the extent provided in this order, the requests by AEP Central and Cities for
determination of their reasonable and necessary rate case expenses for Docket No. 28840 are
granted.
3. As set forth in Finding of Fact No. 34, AEP Central is authorized to surcharge, over a three·
year period, the aggregate rate case expenses for Docket No. 28840 found reasonable and
necessary in Finding of Fact No. 33.
4. AEP Central shall file tariff sheets consistent with this Order (compliance tarifi) no later
than 20 days after receipt of this Order. The Compliance tariff, and all filings related to it,
shall be filed in Tariff Control Number 32385 and shall be styled: Compliance Tariff of
AEP Texas Central Company Pursuant to Final Order in Docket No. 31433 Severed from
Docket No. 28840. The Filing shall include a transmittal letter stating that the tariffs
attached are in compliance with this Order, giving the docket number, date of this Order, a
list of tariff sheets filed, and any other necessary information. The timetable for review of
the compliance tariff shall be established by the Commission's ALJ assigned to the tariff. In
the event any sheets are modified or rejected, AEP Central shall file proposed revisions to
those sheets in accordance with the Commission's ALJ. All subsequent filings in
connection with the compliance tariff (i.e., requests for extensions, textulll corrections,
revisions) shall be filed in the Tariff Control Number provided above, and styled as set forth
above. After issuance of the final order, no further filings other than those pertaining to a
motion for rehearing shall be made in this docket. .
5. As set forth in Finding of Fact No. 35, AEP Central may seek to recover in its next rate case
expenses in connection with Docket Nos. 28840 and 31433 that it incurs after June 2005 and
Cities' rate case expenses incU!Ted in connection with Docket No. 28840 and 31433 that
28
DOCKET NO. 31433 ORDER PAGE13
exceed the amounts authorized to be recovered herein, to the extent such additional expenses
are found reasonable and necessary.
6. All other motions, requests for entry of specific findings of fact and conclusions of law, and
any other requests for general or specific relief, if not expressly granted herein, are denied.
SIGNED AT AUSTIN, TEXAS the ~ <( day of /J1~e,I_ 2006.
PUBLIC UTILITY COMMISSION OF TEXAS
ARSLEY, CO IONER
/~~~./L_
BARR ~=RMAN, COMMISSIONER
q:lcadm\on!enlfinaJ\31000\31433fu.doc
29
TARIFF CONTROL NO. 32385
PUBLIC UTILITY COMMISSION OF TEXAS
COMPLIANCE TARIFF OF AEP TEXAS CENTRAL COMPANY
PURSUANT TO FINAL ORDER IN DOCKET NO. 31433
SEVERED FROM DOCKET NO. 28840
MARCH 14, 2006
TABLE OF CONTENTS
SECTION FILENAME PAGE
Transmittal letter Letter - re Compliance RCE tariff.doc 2
Attachment A Rate Case Surcharg Rider,doc 3
Attachment B Rate Case ExP Rider Final Retail.xis 4-7
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March 14, 2006
AEP Texas Central Company
400 WasJ 15Jh StroeJ, SuiJe 1500
Austin, lX 78701
James R. Galloway ·
Central Records
Public Utility Commission of Texas
170 I N. Congress
Austin, Texas 78711
Re: Tariff Control No. 32385 ·Compliance Tariff ofAEP Texas Central
Company Pursuant to Final Order in Docket 31433 Severedfrom Docket
No. 28840
Dear Mr. Galloway:
Enclosed is the Rider RCS - Rate Case Surcharge tariff sheet for Retail Delivery
Service of AEP Texas Central Company (TCC) filed herewith in compliance with the
Final Order in Docket No. 31433, Proceeding To Consider Rate Case Expenses Severed
From Docket No. 28840 (Application of AEP Texas Central Company For Authority To
Change Rates issued on March 3, 2006. The Rider RCS - Rate Case Surcharge tariff
sheet is the only tariff that is the subject of this filing and is enclosed as Attachment A,
and the worksheets supporting the tariff sheet are enclosed as Attachment B.
TCC proposes that the attached rate schedules be effective for bills rendered on
and after March 30, 2006, which is the first billing cycle for April 2006. TCC requests
that the Administrative Law Judge (ALJ) assigned. to this Tariff Control Number
establish a procedural schedule allowing for that effective date. TCC requests that the
tariffs be effective for billings on and after the effective date of the tariff to avoid
potential implementation issues for TCC and the Retail Electric Providers.
As set forth in Attachment B, in addition to the Retail Delivery Service surcharge
set forth in Rider RCS, TCC will also collect the wholesale jurisdictional allocated
portion of the Docket No. 31433 rate case expenses from Wholesale Transmission
customers served under TCC's Open Access Transmission Tariff (OATT).
If you have any questions, please do not hesitate to contact me at 5124814543.
Thank you for your consideration in this matter.
Sincerely,
~~~
Regulatory Case Management
cc: All parties ofrecord in Docket No. 28840.
Encl.
2
31
AEP TEXAS CENTRAL COMPANY Attachment A
TARJFF FOR ELECTRJC DELIVERY SERVICE
Applicable: Entire System
Chapter: 6 Section: 6.1.1
Section Title: Delivery System Charges
Revision: Original Effective Date: March 30, 2006
6.1.1.14.5 Rider RCS - Rate Case Surcharge
AVAILABILITY:
Rider RCS is desigued to recover Commission approved rate case expenses associated
with PUCT Docket No. 28840. 1 Rider RCS is applicable to electric delivery service from
the Company during the periods this schedule is in effect, and will be billed along with
the other delivery service charges. Charges associated with Rider RCS will be
determined in accordance with the applicable fee listed below. This schedule will be in
effect from the first billing cycle of April 2006 and will end with the last billing cycle of
March2009.
MONTHLY RATE OTHER THAN FOR TRANSMISSION VOLTAGE SERVICE:
The monthly charge shall be determined by multiplying the appropriate Rider RCS Fee in
the table below by the current month's billing kWh.
Rate Schedule Fee
Residential Service $0.000059 per kWh
Secondary Service Less than or Equal to 10 kW $0.000119 per kWh
Secondary Service Greater than I 0 kW $0.000047 per kWh
Primary Service $0.000026 per kWh
Lighting Service $0.000119 per kWh
MONTHLY RATE FOR TRANSMISSION VOLTAGE SERVICE:
The RCS for the Transmission Service Class shall be collected on a revenue basis by
applying the factor below to Transmission and Distribution base rate revenue. Base rate
revenue is defined as the monthly sum of the distribution system charges, metering
charge, customer service charge, transmission system use charges, and Rider TCRF
charges.
Rate Schedule Base Revenue Factor
Transmission Service 0.00242
NOTICE:
This Rate Schedule is subject to the Company's Tariff and Applicable Legal Authority.
1
The Rate Case Expense allocated to Retail Customers is 64.63% of the total approved rate case expenses
in Docket No. 31433 (severed ftom Docket No. 28840). The Rate Case Expense allocated to Wholesale
Transmission Customers is 35.37% of the total approved rate case expense in Docket No. 31433.
140
3
32
Attachment B
Page 1 of 4
Allocation of Rate Case Expenses
Total Approved Rate Case Expenses (1) $4,288,279
Wholesale Transmission Rate Base Allocation Factor (2) 35.37%
Distribution Rate Base Allocation Factor (2) 64.63%
Wholesale Transmission Total Revenue Requirement $1,516,933.52
Distribution Total Revenue Requirement $2,771,495.48
3-Year Recovery Annual Revenue Requirement
Wholesale Transmission $505,644.51
Distribution $923,831.83
Wholesale Transmission Rate Case Surcharge Factor Development
Wholesale Transmission Annual Revenue Requirement $505,645
Test Year ERGOT 4CP kW 53,520,537
per average 4CP per year $0.00945
monthly rate case expense surcharge for wholesale
transmission service per 4CP kW (3) $0.00079
Notes:
1 Final Order Docket No. 31433 Total Rate Case Expenses
AEP TCC recoverable rate case expenses $2,938,130
Cifies' recoverable rate case expenses $1,350, 149
Total Docket No. 28840 rate case expenses $4.288,279
2 Jurisdictional allocation based on rate base.
Schedule 2 - Final Order dated August 15, 2005
Wholesale Transmission Rate Base 471,655,044 35.37%
Distribution Rate Base 861,731,781
~~~'"-"-,~~~~~~~
64.63%
1,333,386,825 100.00%
3 In addition to the TCOS wholesale transmission access fee, TCC TSP shall bill a
monthly rate of $0.00079 per kW of coincident peak demand for three years
after the effective date of the rate case expense surcharge rider.
4
33
LINE DESCRIPTION T&D Revenue Rate Case
1 Allocator Expense Allocation kWh Surcharge Revenue Difference
2
3 Annual Rate Case Expense Revenue Requirement $923,832
4
5 Residential 52.32% $483,306 8,230,446,543 $0.000059 $485,596 $2,290
6
7 Secondary 5 ·1 0 kW 3.42% $31,565 475,856,859
8 Lighting 5.92% $54,662 249,521,076
9 Total Secondary 5 10 kW 9.33% $86,227 725,377,935 $0.000119 $86,320 $93
10
11 Secondary> 10 kW Non-I DR 26.82% $247,760 5,243,542,742
12 Secondary> 10 kW IDR 0.90% $8,342 184,389,689
13 Total Secondary> 10 kW 27.72% $256, 103 5,427,932,431 $0.000047 $255, 113 ($990)
14
15 Primary Non-IDR 1.02% $9,424 330,585,571
16 Primary IDR 5.94% $54,832 2 116,659,683
17 Total Primary 6.96% $64,256 2,447,245,254 $0.000026 $63,628 ($628)
18
19
20 The rate case expenses to be collected from the Transmission Class shall be collected on a revenue basis by applying the factor
21 shown below to the total of the distribution service, transmission service, customer service, meter service, and TCRF revenues.
22
23 T&D Revenue Rate Case Proposed % of T&D
24 Allocator Expense Allocation T&D Revenue Revenue
25 Transmission 3.67% $33,940 $13,996,621 0.00242
26 Transmission Proposed T&D Revenue $13 996,621 0.00242 $33,872 ($68)
27
28 Total Retail 100.00% $923,832 $924,529
29
30 Rate Design Difference $698
31 Rate Design Percent Difference 0.08%
32 >-
"d ii
33 Notes: ~ g.
34 The Transmission Class rate case expense % of revenue is based on the percent of Transmission Class rate case N~
35 expense allocation I proposed T&D revenue. The resulting percentage is applied to the total distribution and transmission revenue. s, a
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DUGGINS WREN MANN & ROMERO, LLP
POST OFFlCE BOX J 149
AUSTIN, TEXAS 78767
600 CONGRESS, SUITE 1900
AUSTIN, TEXAS 78701
TELEPHONE (512) 744-9.500
TELEFAX (61i) 74+-9399
September 28, 2012
Honorable Donna L. Nelson, Chairman
Honorable Kenneth W. Anderson, Jr.
Honorable Rolando Pablos
Public Utility Commission of Texas
1701 N. Congress Ave. ·:.
Austin, Texas 7870 I
Re: Docket No. 40742, Compliance Tariff Pursuant to Final Order in Docket No. 38986
(Application ofEntergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs,
and Obtain Deferred Accounting Treatment)
Docket o. 39896; OAH Docket No. XXX-XX-XXXX; Application of Entergy Texas, Inc.
for Authorz to Change Rates, Reconcile Fuel Costs, and Obtain Deferred Accounting
Treatment
Dear Commissioners:
Entergy Texas, Inc. (ETI) has reviewed the corrections to the Commission's final order in
Docket No. 39896 proposed in the motion for rehearing of the Commission Staff. ETI agrees
that these technical corrections are necessary so that the order will be consistent with the Staff
number runs and with the Commission decisions that result in the $27 .7 million revenue increase
approved in this case. ETI further understands that these corrections are not opposed by any
party.
The date for the filing of compliance tariffs by the Company, under the Commission's
current order, is October 4, 2012. To support implementation of new rates in as timely a fashion
as possible (particularly given that the new rates relate back to service rendered on and after June
30, 2012), to support synchronizing the rate increase with the credit being implemented in ETI
Docket No. 40542, 1 and in light of the absence of opposition to the Staffs proposed changes, it
is ETl's intent to file its compliance tariffs on October 4th consistent with the most current Staff
number run. This number runs produces the $27.7 million revenue increase approved by the
Commission, and reflects the ministerial corrections proposed in the Staffs recent motion for
1 Application of Entergy Texas, Inc. for Authority to Implement New Rough Production Cost Equalization
Adjustment (RPCEA) Rate.
37
DUGGINS WREN MANN & ROMERO, LLP
September 28, 2012
Page2
rehearing (but not yet reflected in the Commission's order). If the Commission makes any
changes to its rulings in response to motions for rehearing that affect the approved revenue
requirement or rates, ETI will address those changes in the tariff compliance process at that time.
Resp
cc: Parties of record
l
38
PUC DOCKET NO. 34800
SOAH DOCKET NO. XXX-XX-XXXX
APPLICATION OF ENTERGY §
GULF STATES, INC. FOR §
AUTHORITY TO CHANGE RATES §
AND TO RECONCILE FUEL §
COSTS §
ORDER
1
This order addresses the application of Entergy Gulf States, Inc. (EGSI) for
authority to change rates and reconcile fuel costs. The docket was processed in accordance
with applicable statutes and Public Utility Commission of Texas rules. EGSI,
Commission Staff, the Office of Public Utility Counsel (OPC), the Community
Associations of the Woodlands (CATW), the Entergy Texas, Inc. Service Area Cities'
Steering Committee (Cities), the State of Texas, Texas Industrial Energy Consumers
(TIEC), Texas Legal Services Center (TLSC), Texas Ratepayers' Organization to Save
Energy (Texas ROSE), Wal-Mart Stores Texas, LLC , through their duly authorized
representatives (Wal-Mart) (collectively, signatories) filed a stipulation and settlement
agreement that resolves all of the issues in this proceeding. The Kroger Company and TX
Energy, LLC did not sign the stipulation and do not oppose it. Consistent with the
stipulation, EGSI' s application is approved.
The Commission adopts the following findings of fact and conclusions of law:
I. Findings of Fact
Procedural History
I. On September 26, 2007, EGSI filed an application for approval of: (I) base rate
tariffs and riders designed to collect a total non-fuel revenue requirement for the
' On December 31, 2007, EGS! jurisdictionally separated pursuant to ~ 39.452(e) of 1he Public U1ility
Regulatory Act (PURA), TEX. UTIL. CODE ANN. Title 2 and Entergy Texas, Inc. (ET!) succeeded to EGSl's certificate of
39
PUC Docket No. 34800 Order Page 2of15
SOAH Docket No. XXX-XX-XXXX
Texas retail jurisdiction of $605 million; (2) a set of proposed tariff schedules
presented in the Electric Utility Rate Filing Package for Generating Utilities (RFP)
accompanying EGSI's application; (3) a request for final reconciliation of EGSl's
fuel and purchased power costs for the reconciliation period from January I, 2006
to March 31, 2007, as well as deferred costs from prior proceedings; and (4) certain
waivers to the instructions in RFP Schedule V accompanying EGSI' s application.
2. The 12-month test year used in EGSl's application ended on March 31, 2007.
3. EGSI provided notice by publication for four consecutive weeks before the
effective date of the proposed rate change in newspapers having general circulation
in each county of EGSI's Texas service territory. EGSI also mailed notice of its
proposed rate change to all of its customers. Additionally, EGSI timely served
notice of its statement of intent to change rates on all municipalities retaining
original jurisdiction over its rates and services.
4. The following parties were granted intervenor status in this docket: OPC, Alliance
for Retail Markets (ARM), CATW, Cities, Kroger Company, State, TIEC, TLSC,
Texas ROSE, TX Energy, LLC, and Wal-Mart. 2 Commission Staff was also a
participant in this docket.
5. On October I, 2007, the Commission referred this case to the State Office of
Administrative Hearings (SOAH) for processing.
6. EGSI appealed the rate decisions adopted by the Cities of Chester, Woodville,
Ames, Dayton, Devers, Liberty, New Waverly, Riverside, Trinity, Bedias,
Bremond, Caldwell, Calvert, Franklin, Madisonville, Somerville, Patton Village,
Cut and Shoot, Willis, Plum Grove, Shepherd, Oak Ridge North, Normangee,
Daisetta, Hardin, Corrigan, Groveton, Anderson, Kosse, North Cleveland,
Woodloch, Midway, Panorama Village, Taylor Landing, Rose Hill Acres, China,
Hearne, Bevil Oaks, Colmesneil, Kountz, Nome, Lumberton, and Todd Mission.
convenience and necessity for its Texas retail jurisdiction. For continuity and ease of reference. EGSI, Comm'ission
Staff, and intervenors have continued to make rett:Tcnce to EGSI for purposes of pleadings in this docket.
2
OPC, ARM, Cities, Kroger Company, Stale, and TIEC were granted party Slatus on October 22, 2007. See
Prehearing Conference Tr. at 6.
40
PUC Docket No. 34800 Order Page 3of15
SOAH Docket No. XXX-XX-XXXX
7. As provided for in Order Nos. 3, 9, 12, 14, and 23, the SOAH administrative law
judges (ALJs) consolidated EGSI's appeals of the rate decisions adopted by the
cities in Finding of Fact No. 6.
8. Cities participated in this case representing the Cities of Beaumont, Bridge City,
Conroe, Groves, Houston, Huntsville, Navasota, Nederland, Orange, Pine Forest,
Pinehurst, Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake,
Vidor, and West Orange. These municipalities have adopted rates consistent with
the stipulation discussed below.
9. The Commission established in its Order on Appeal of Order No. 8 an effective
date for EGSI's proposed rate change of September 26, 2008.
I 0. On April 8, 2008, the State filed a motion for partial summary decision regarding
the continued applicability of the 20% base rate discount for state institutions of
higher education under § 36.351 of the Public Utility Regulatory Act, TEX. UTIL.
CODE ANN.§§ l l.OOl-66.016 (Vernon 2007 & Supp. 2008)(PURA).
11. On July 16, 2008, the SOAH ALJs issued a proposal for decision (PFD)
recommending that the Commission grant the State's April 18, 2008 motion for
partial summary decision.
12. On August 15, 2008, the Commission entered an order adopting the PFD on the
State's motion for partial summary decision.
13. The Commission entered an order on November 4, 2008, extending the effective
date ofEGSI's proposed rate change until November 27, 2008.
14. Commission Staff, State, and TIEC filed a non-unanimous stipulation (NUS) on
May 19, 2008. EGSI and certain other parties filed a separate NUS on May 20, ·
2008. 3 The EGSI NUS was opposed by Commission Staff, State, and TIEC. A
hearing was held on both NUSs on June 23 through July 2, 2008.
15. At Open Meetings on October 23 and November 5, 2008, the Commission
considered a PFD from the SOAH ALJs which recommended resolution of the rate
41
PUC Docket No. 34800 Order Page4of15
SOAH Docket No. XXX-XX-XXXX
case through adoption of the EGSI NUS. On November 7, 2008, the Commission
issued its order on remand rejecting the PFD and remanding the docket to SOAH
for a hearing on the merits ofEGSI's original application.
16. During the November 5, 2008 Open Meeting, EGSI agreed to extend the statutory
jurisdictional deadline in this docket to March 2, 2009. EGSI subsequently agreed
to extend the statutory jurisdictional deadline to March 16, 2009. 4
17. The SOAH ALJs granted ARM's motion to withdraw as an intervenor on
December 2, 2008, pursuant to Order No. 49.
18. The hearing on the merits on remand took place on December 3 and 4, 2008, and
December 8 through December 12, 2008. The hearing was recessed on
December 12, 2008, in order to allow the parties to work on concluding a
settlement.
19. On December 16, 2008, the signatories submitted a settlement term sheet to reflect
their agreement in principle resolving all outstanding issues regarding EGSI's
application, including those issues raised by the Commission in its November 7,
2008 order on remand.
20. On December 16, 2008, the signatories submitted an agreed motion to implement
interim rates.
21. On December 19, 2008, the SOAH ALJs filed Order No. 52, granting interim
approval of rates consistent with the settlement term sheet, effective with bills
rendered on and after January 28, 2009, for usage on and after December 19, 2008.
22. On February 5, 2009, the signatories submitted a stipulation resolving all
outstanding issues in this docket.
23. On February IO, 2009, the SOAH ALJs filed Order No. 56, returning this docket to
the Commission.
3
The EGSJ NUS was subsequently amended on June 27, 2008.
4
EGSJ letter filed February 18. 2009.
42
PUC Docket No. 34800 Order Page 5of15
SOAH Docket No. XXX-XX-XXXX
Description o(the Stipulation and Settlement Agreement
24. The signatories agree that EGSI will institute an overall increase in base rate
revenues of$46.7 million.
25. The signatories agree to a reasonable return on equity for EGSI of I 0.00%.
26. The signatories agree that the cost of service underlying the base-rate revenue
increase does not include any unreasonable or unjust expenses.
27. The signatories agree that EGSI will implement a rate-case-expense rider to recover
$2.3 million per year for three years. The rate-case expenses will be allocated to
customer classes based on total base-rate revenues. The rates established under the
rate-case expense rider will be determined based on energy consumption in
kilowatt-hours (kWh), except for the Large Industrial Power Service (LIPS)
customer class, whose rates will be set on a kilowatt (kW) basis.
28. The Signatories agree to leave the mechanisms for recovery of EGSI's municipal
franchise-fee riders unchanged as a result of this docket.
29. The Signatories agree that EGSI's proposed Market Value Energy Rider (MVER)
will not be offered as a result of this docket.
30. The signatories agree that the Incremental Purchased Capacity Recovery Rider
(IPCR) will expire contemporaneously with the implementation of rates approved
in Order No. 52.
31. The signatories agree that the base-rate revenue increase, the rate-case expense
rider and the municipal franchise-fee riders addressed in the stipulation became
effective for bills rendered on and after January 28, 2009 for usage on and after
December 19, 2008, as approved in Order No. 52.
32. The signatories reached the following specific agreements regarding rate design as
a part of the overall resolution of this docket:
a. Supplemental Short Term Service (SSTS). Rate Schedule SSTS will
terminate six months after a final, appealable order approving the
stipulation is issued by the Commission in this docket. Beginning with the
43
PUC Docket No. 34800 Order Page 6of15
SOAH Docket No. XXX-XX-XXXX
base rates implemented as a result of this stipulation, EGSI will bill SSTS
usage as follows: (SSTS charges+ LIPS charges)/2.
b. Interruptible Service (IS). Rate Schedule IS will be modified as follows:
i. 30-minute notice service is eliminated;
ii. The credit for 5-minute notice service is reduced to $3.75/kW-
month;
m. The credit for no-notice service is reduced to $4.88/kW-month;
1v. The credits shall be applied to the· LIPS and LIPS-Time of Use
(TOU) tariffs (current High Load Factor Service (HLFS) and Large Power
Service (LPS) customers will be transferred to LIPS); and
v. Rate Schedule IS remains closed to new business.
c. Competitive Generation Service. EGSl's competitive generation-service
proposal shall not be withdrawn, but shall be severed from this docket and
addrt><~ed in a separate docket wherein the Commission will (a) exercise its
authority to approve, reject, or modify EGSI's proposal; and (b) address
, any costs unrecovered as a result of the implementation of the
d ., ·>neons Electric Service Charges. No change shall be made to
Miscellaneous Electric Service Charges.
e. Lighting Class Rates. Lighting-class rates for all lighting fixtures shall be
designed in a manner so that each fixture is charged a uniform base-rate
percentage increase as established for the entire lighting class.
f. Additional Facilities Charge (AFC). Rate Schedule AFC, governing
additional-facilities charge, will be designed to result in a reduction to
1.49%, with the resulting revenue reduction allocated among those
customer classes with AFC revenue based on the percentage of AFC
revenues in each customer class.
44
PUC Docket No. 34800 Order Page7 oflS
SOAH Docket No. XXX-XX-XXXX
g. Economic as Available Power Service/Standby Maintenance Service.
No substantive changes shall be made as a result of this docket to: (a) Rate
Schedule EAPS, governing Economic-as-Available Power Service; or (b)
Rate Schedule SMS, governing Standby Maintenance Service.
h. Interconnection Terms and Conditions. No changes shall be made as a
result of this docket to EGSI's terms and conditions regarding costs for
interconnection of customers.
i. Electric Extension Policy. No changes shall be made as a result of this
docket to EGSl's electric extension policy.
j. Large Interruptible Power Service. The signatories stipulate that the
contract demand ratchet provisions in Rate Schedule LIPS will be retained;
provided, however, that the billing demand provision contained in
Paragraph V of Rate Schedule SSTS will no longer apply to customers
taking service under Rate Schedule LIPS after Rate Schedule SSTS
terminates.
33. The signatories agree to the class-cost allocation set forth in Attachment A to the
stipulation and further agree that this allocation is reasonable.
34. The signatories agree to a River Bend nuclear generating station 20-year life
extension adjustment to EGSl's calculation of nuclear depreciation and
decommissioning costs effective January 1, 2009.
35. The signatories agree that EGSI will reduce depreciation expense related to EGSl's
steam production plants by the amount of $2,731,478 on a total Texas retail basis
effective January 1, 2009.
36. The signatories agree that EGSl will present a new depreciation study as part of its
next base-rate case, or by January 5, 2010, whichever is earlier.
37. The signatories agree that the base-rate increase, rate riders, and associated rate
design and class-cost allocation agreed to in the stipulation are reasonable and are
45
PUC Docket No. 34800 Order Page 8of15
SOAH Docket No. XXX-XX-XXXX
reflected in the rate schedules approved by Order No. 52 and revised by errata
filings on December 22, 2008, January 27, 2009, and March 5, 2009.
38. The signatories agree that EGSI will fund its Public Benefit Fund at an annualized
amount of $2 million.
39. In order to include a greater portion of the eligible population in the Public Benefit
Fund program, EGSI agrees to use its best efforts to contract for and implement an
automatic enrollment program. EGSl's automatic enrollment program will be
modeled upon the matching procedures used by other Texas utilities to identify
eligible customers and will be implemented within 30 days of the Commission's
filing of the final order in this case.
40. The signatories agree that EGSl will amend its low-income energy-efficiency
program on a trial basis as specified in the stipulation.
41. The signatories agree that the amendment ofEGSl's low-income energy-efficiency
program does not increase base rates to recover uncollected expenses associated
with revenues billed under EGSI's energy-efficiency rider approved in Docket
No. 35626.5
42. The signatories agree to a fuel disallowance of $4.5 million, booked in the month
of a final Commission order approving the application, consistent with the
stipulation.
43. The signatories agree to adopt Commission Staff's position on the following
resolution of fuel-related matters set out in Commission Staff's pre-filed direct
testimony: (a) recovery of sulfur dioxide (S02) and nitrous oxide (NO,) emissions
revenues recorded in Account 411.8 and expenses recorded in Account 509 will be
allowed as eligible fuel expense going forward until further order of the
.
Commission realigning such costs; (b) special circumstances should be granted to
treat the costs of natural-gas call options incurred during the reconciliation period
' Application of Entergy Texas. Inc. for Approval of an Energy Efficiency Cost Recovery Factor
(EECRF) Pursuantto PURA § 39. 905(b) and P. U. C. Subst. R. 25. /8/ (f). Docket No. 35626. Order (Aug. 14,
2008).
46
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PUC Docket No. 34800 Order Page 9of15
SOAH Docket No. XXX-XX-XXXX
as eligible fuel expense; ( c) good cause exists to sever and defer the River Bend
performance-based ratemaking (PBR) calculation for the final seven months of the
reconciliation period to EGSI's next fuel reconciliation proceeding; and (d) the
River Bend PBR plan should terminate in light of EGSI's jurisdictional separation.
Evidence Supporting the Stipulation and Agreement
44. Considered in light of (a) the pre-filed testimony by the parties entered into
evidence, and (b) the additional evidence and testimony presented by the parties
during the course of the hearing on the merits on EGSI's application, the stipulation
is the result of compromise from each party, and these efforts, as well as the overall
result of the stipulation viewed in light of the record evidence as a whole, support
the reasonableness and benefits of the terms of the stipulation.
45. The evidence addressed in finding of fact 44 demonstrates that the rates, terms, and
conditions resulting from the stipulation are just and reasonable and consistent with
the public interest when the merits of the issues contested by Commission Staff and
intervenors are considered.
46. The stipulated revenue requirement does not include any amounts for financial-
based incentive compensation.
47. To the extent that affiliate costs are included in the stipulated revenue requirement
and fuel expense, they are reasonable and necessary for each class of affiliate costs
presented in EGSl's application.
48. To the extent that affiliate costs are included in the stipulated revenue requirement
and fuel expense, the price charged to EGSI is not higher than the prices charged by
the supplying affiliate for the same item or class of items to its other affiliates or
divisions, or a non-affiliated person within the same market area or having the
same market conditions.
49. The Texas retail revenue requirement in the stipulation does not include any of the
following expenses, whether allocated or direct-billed to EGSI: legislative
advocacy expenses; entertainment; charitable contributions; advertising expense to
promote the increased consumption of electricity or to promote the image of the
47
PUC Docket No. 34800 Order Page 10of15
SOAH Docket No. XXX-XX-XXXX
electric utility industry; advertising products marketed by other affiliates; civil
penalties or fines; any other expenses listed in PURA §§ 36.061, 36.062, and
36.063; payments made to cover costs of an accident, equipment failure, or
negligence at a utility facility owned by a person or governmental body not selling
power inside the State of Texas (except those made under an insurance or risk-
sharing arrangement executed before the date of loss); the costs for processing a
refund or credit under PURA § 36.110; any profit or loss that results from the sale
of merchandise not integral to providing utility service; construction work in
progress in rate base; or plant held for future use in rate base.
50. EGSI's current supplemental short-term service, Schedule SSTS, should be
terminated within six months after the filing of a final, appealable Commission
order in this docket, as provided for in the stipulation.
51. It is reasonable to modify EGSI's current interruptible service, Schedule IS, in
accordance with the terms and conditions of the stipulation.
52. It is reasonable in light of the compromise reached in the stipulation for no
substantive modifications to be made to EGSI's economic as-available power
service, Schedule EAPS, or standby maintenance service, Schedule SMS.
53. The depreciation and decommissioning adjustments for nuclear production assets
agreed to in the stipulation and consistent with Louisiana rate treatment are
reasonable.
54. The depreciation adjustments to EGSI's steam production assets agreed to in the
stipulation are reasonable.
55. The increase in storm cost accruals provided for in the stipulation is reasonable.
56. The low-income programs provided for in the stipulation are reasonable.
57. EGSI's energy-efficiency costs are recovered through a rider approved by the
Commission in Docket No. 35626.
58. The PBR plan for the River Bend nuclear generating station contemplates an
annual calculation of penalties and rewards. Good cause exists to sever and defer
48
PUC Docket No. 34800 Order Page 11of15
SOAH Docket No. XXX-XX-XXXX
the PBR calculation for the final seven months of the reconciliation period to
EGSl's next fuel reconciliation proceeding.
59. It is reasonable to terminate the application of the PBR plan to the River Bend
operations on and after January 1, 2008 when Entergy Texas, Inc. no longer has an
ownership interest in River Bend.
60. EGSI is entitled to a special circumstances exception for the cost of the natural-gas
call options because they resulted in increased reliability of supply and reduced fuel
expense.
61. The class allocation methodologies described in the stipulation are reasonable.
62. The total level of invested capital in the Texas retail revenue requirement is
reasonable.
63. The EGSI stipulation proposes to collect the existing incremental franchise fees of
the Cities of Beaumont, Port Arthur, and Conroe as a municipal franchise-fee rider.
The Commission has reviewed its finding in paragraph 11.E of its remand order of
November 7, 2008 and determines that the existing incremental franchise fees were
the result of franchise agreements adopted subsequent to the passage of PURA
§ 39.456.
II. Conclusions of Law
1. EGSI is a public utility as that term is defined in PURA § 11.004( 1) and an electric
utility as that term is defined in PURA§ 31.002(6).
2. The Commission exercises regulatory authority over EGSl and jurisdiction over the
subject matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101,
33.002, 33.051, 36.001-36.111, 36.203, 39.452, and 39.455.
3. SOAH had jurisdiction over matters related to the conduct of the hearing and the
preparation of a proposal for decision in this docket, pursuant to PURA § 14.053
and TEX. GoV'T CODE ANN. § 2003.049.
49
PUC Docket No. 34800 Order Page 12 oflS
SOAH Docket No. XXX-XX-XXXX
4. This docket was processed in accordance with the requirements of PURA and the
6
Texas Administrative Procedure Act.
5. EGSI provided notice of its application in compliance with PURA§ 36.103, P.U.C.
PROC. R. 22.Sl(a), and P.U.C. SUBST. R. 25.235(b)(l)-(3).
6. This docket contains no remaining contested issues of fact or law.
7. The stipulation, taken as a whole, is a just and reasonable resolution of all the
issues it addresses, results in just and reasonable rates, terms and conditions, is
supported by a preponderance of the credible evidence in the record, is consistent
with the relevant provisions of PURA, and is consistent with the public interest.
8. EGSI has properly accounted for the amount of fuel and IPCR-related revenues
collected pursuant to the fuel factor and Rider IPCR during the reconciliation
period.
9 The revenue requirement, cost allocation, revenue distribution, and rate design
implementing the stipulation result in rates that are just and reasonable, comply
•· · · .ul! ratemaking provisions in PURA, and are not unreasonably discriminatory,
prefer ·-:tial, v ~ial.
'" Sever" , ... ,"r;Sl's proposed competitive generation service into a separate
·ket >L ' it" · ..~addressed separately is reasonable.
EGS! ., .;ru1 'cd to a special circumstances exception under P.U.C. SUBST. R.
~5.236(a)(6) for the cost of natural gas call options.
12. Consistent with the stipulation, good cause exists to treat EGSI's emissions
revenues and expenses referenced in finding of fact 43 as eligible fuel expense on a
going-forward basis until further order of the Commission realigning such costs.
13. Based on the evidence in this docket, the overall total invested capital through the
end of the test year meets the requirement in PURA § 36.053(a) that electric utility
rates be based on the original cost, less depreciation, of property used by and useful
to the utility in providing service.
6
TEX. GOV'T. CODE ANN. Chapter 2001 (Vernon 2000 and Supp. 2007).
50
PUC Docket No. 34800 Order Page 13 of15
SOAH Docket No. XXX-XX-XXXX
14. The Commission has reviewed its finding in paragraph 11.E of its remand order of
November 7, 2008 and determines that because the existing incremental franchise
fees were the result of franchise agreements subsequent to the passage of PURA
§ 39.456, they qualify as new franchise agreements and are therefore in compliance
with PURA§ 39.456 when recovered as a municipal franchise-fee rider.
15. The final resolution of the instant docket does not impose any conditions,
obligations, or limitations on EGSI's right to file a base-rate proceeding and obtain
rate relief in accordance with PURA.
16. Consistent with the stipulation, EGSI has met its burden of proof in demonstrating
that it is entitled to the agreed upon level of Texas retail base-rate and rider
revenue.
17. Consistent with the stipulation and PURA, EGSI has met its burden of proof in
demonstrating that the rates are just and reasonable.
III. Ordering Paragraphs
In accordance with these findings of fact and conclusions oflaw, the Commission
issues the following orders:
I. Consistent with the stipulation, EGSl's application for authority to (a) change its
rates; (b) reconcile its fuel and purchased power costs for the Reconciliation Period
from January 1, 2006 to March 31, 2007, as well as deferred costs from prior
proceedings; and (c) for other related relief is approved.
2. Consistent with the stipulation, the rates, terms, and conditions described in this
order are approved.
3. Consistent with the stipulation, the tariffs and riders approved on an interim basis
by Order No. 52 and revised by errata on December 22, 2008, January 27, 2009,
and March 5, 2009, are approved.
51
PUC Docket No. 34800 Order Page 14 of lS
SOAH Docket No. XXX-XX-XXXX
4. Consistent with the stipulation, EGSI shall implement the low-income programs
described in this order.
5. Consistent with the stipulation, EGSl's Competitive Generation Services tariff is
severed from this docket and shall be addressed in Application of Entergy Texas,
6.
Inc.for Approval ofCompetitive Generation Services Tariff, Docket No. 36713.
Consistent with the stipulation, EGSl's storm-cost accruals shall be increased by $2
I
million for a total accrual of $3.65 million annually beginning January I, 2009,
which amount will be incorporated in revenues recovered through base rates.
7. Consistent with the stipulation, EGSI shall terminate rate schedule SSTS and Rider
IPCR.
'
8. Consistent with the stipulation, EGSI shall adjust depreciation
decommissioning expense related to the River Bend nuclear generating station and
depreciation expense related to EGSI's steam production assets.
and
I
9. Consistent with the stipulation, EGSI shall submit a new depreciation study.
10. Consistent with the stipulation, the Rider IPCR and fuel costs, including coal-
related costs deferred from prior proceedings are reconciled and approved through
March 31, 2007.
11. EGSI shall adjust its fuel over/under recovery balance consistent with the findings
in this order.
12. The entry of this order consistent with the stipulation does not indicate the
Commission's endorsement of any principle or methodology that may underlie the
stipulation. Neither should entry of this order be regarded as precedent as to the
appropriateness of any principle or methodology underlying the stipulation.
13. All other motions, requests for entry of specific findings of fact, conclusions of
law, and ordering paragraphs, and any other requests for general or specific relief,
if not expressly granted in this order, are hereby denied.
52
PUC Docket No. 34800 Order Page 15of15
SOAH Docket No. 4 73-08-0334
SIGNED AT AUSTIN, TEXAS the _ _ dayofMarch 2009
PUBLIC UTILITY COMMISSION OF TEXAS
DONNA L. NELSON, COMMISSIONER
q.\cadm\ordcrs\tinal\34000\34800fo2.doc
53
"'1 ~
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PUC DOCKET NO. 37744 t..
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SOAH DOCKET NO. 473-10-1962- · ., 1
I J I...• c::~'J
APPLICATION OF ENTERGY TEXAS, § PUBLIC UTILITY COMMISSiON
INC. FOR AUTHORITY TO CHANGE §
RATES AND RECONCILE FUEL § OF TEXAS
COSTS §
ORDER
This Order addresses the application of Entergy Texas, Inc. (ET!) for authority to change
rates and reconcile fuel costs. ET!, Commission Staff, the Office of Public Utility Counsel
(OPUC), the Steering Committee of Cities Served by ET! (Cities), 1 Texas Industrial Energy
Consumers (TIEC), The Kroger Company (Kroger), and Wal-Mart Stores Texas, LLC and
Sam's East, Inc. (collectively Wai-Mart), through their duly authorized representatives entered
into and filed a stipulation and settlement agreement that resolves all of the issues in this
proceeding except the issues related to ETl's proposal for competitive generation service.
Cottonwood Energy, L.P. and the State of Texas agencies and institutions of higher education
(State Agencies) did not join but do not oppose the stipulation.
The Commission severed the competitive generation service issues into Docket
No. 38951 2 inOrderNo.14.
The Commission adopts the following findings of fact and conclusions oflaw:
1
Steering Committee of Cities is comprised of the Cities of Anahuac, Beawnont, Bridge City, Cleveland,
Conroe, Groves, Houston, Huntsville, Montgomery, Navasota. Nederland, Oak Ridge North, Orange, Pine Forest,
Pinehurst, Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West
Orange.
2
Application of Entergy Texas. Inc.for Approval of Competitive Generation Service Tariff (Issues Severed
From Docket No. 37744), Docket No. 38951.
PUC Docket No. 37744 Order Page 2 of 15
SOAH Docket No. XXX-XX-XXXX
I. Findings of Fact
Procedural History
I. On December 30, 2009, ET! filed an application requesting approval of (1) base rate
tariffs and riders designed to collect an overall revenue requirement of $1,758.4 million,
which includes a total non-fuel retail revenue requirement of $838.3 million (base rate
revenues of $486 million plus revenue from riders of $352.3 million); (2) a set of
proposed tariff schedules presented in the Electric Utility Rate Filing Package for
Generating Utilities (RFP) accompanying ETl's application; (3) a request for finiil
reconciliation of ET!' s fuel and purchased power costs for the reconciliation period from
April 1, 2007 to June 30, 2009; and (4) certain waivers to the instructions in RFP
Schedule V accompanying ETI's application.
2. The 12-month test year employed in ETl's filing ended on June 30, 2009.
3. ET! provided notice by publication for four consecutive weeks before the effective date
of the proposed rate change in newspapers having general circulation in each county of
ET!' s Texas service territory. ETI also mailed notice of its proposed rate change to all of
its customers. Additionally, ET! timely served notice of its statement of intent to change
rates on all municipalities retaining original jurisdiction over its rates and services. ET!
also published one-time supplemental notice by publication in newspapers and by bill
insert.
4. The following parties were granted intervenor status in this docket: OPUC, Cities,
Cottonwood, Kroger, State Agencies, TIEC, and Wal-Mart. Commission Staff was also a
participant in this docket.
5. On January 4, 2010, the Commission referred this case to the State Office of
Administrative Hearings (SOAH) for processing.
6. On February 19, 2010, the ALls issued Order No. 3, which approved an agreement
between ET!, Staff, Cities, State Agencies, OPUC, TIEC, Kroger, and Wal-Mart, to
( 1) establish an interim rate increase of $17 .5 million annually above ET!' s then-existing
base rates commencing with service rendered on and after May 1, 2010 subject to
true-up and refund for service rendered prior to September 13, 2010 to the extent final
55
PUC Docket No. 37744 Order Page3of 15
SOAH Docket No. XXX-XX-XXXX
overall rates established by the Commission amounted to less than a $17.5 million rate
increase; (2) extend the jurisdictional deadline by which the Commission must issue a
final order on the Company's rate request from July 5, 2010 to November l, 2010;
(3) establish a September 13, 2010 effective date for rates such that, notwithstanding the
extension of the jurisdictional deadline, the final overall rates established by the
Commission would relate back to service rendered on and after September 13, 201 O;
(4) require ET! to publish supplemental notice, once in newspapers and by a bill insert,
setting forth the effect of its proposed rate change in terms of the percentage increase in
non-fuel revenues; and ( 5) establish a procedural schedule and discovery deadlines for
this proceeding. Order No. 3 also granted Mr. Kurt Boehm's motion for admission
pro hac vice as counsel for Kroger and ETI's February 3 and February II, 2010 petitions
for review of cities' ordinances and motions to consolidate with respect to the rate
decisions adopted by the Cities of Ames, Anderson, Bedias, Bevil Oaks, Bremond,
Caldwell, Calvert, Chester, China, Colmesneil, Corrigan, Cut and Shoot, Daisetta,
Dayton, Devers, Franklin, Groveton, Hardin, Hearne, Iola, Kosse, Kountze, Liberty,
Lumberton, Madisonville, Midway, New Waverly, Normangee, Nome, Patton Village,
Plum Grove, Riverside, Rose Hill Acres, Somerville, Taylor Landing, Todd Mission,
Trinity, and Woodville.
7. On June 14, 2010, the ALls issued Order No. 6 granting Staff's June l, 2010 motion and
severing rate case expense issues to Docket No. 38346.3 Through Order No. 6, the AUs
also granted ETI's March 12, April 29, and May 17 petitions for review and motions to
consolidate with respect to the rate decisions adopted by the Cities of Anahuac,
Beaumont, Bridge City, Cleveland, Conroe, Groves, Houston, Huntsville, Montgomery,
Navasota, Nederland, Oak Ridge North, Orange, Panorama Village, Pine Forest,
Pinehurst, Port Arthur, Port Neches, Roman Forest, Rose City, Shenandoah, Shepard,
Silsbee, Sour Lake, Splendora, Vidor, West Orange, Willis, Woodbranch Village, and
Woodloch.
3
Application of Entergy Texas, Inc. for Rate Case Expenses Severed from PUC Docket No. 37744, Docket
No.38346.
56
PUC Docket No. 37744 Order Page4of15
SOAH Docket No. XXX-XX-XXXX
8. The hearing on the merits commenced on July 13, 2010 and was immediately recessed in
order to facilitate settlement negotiations. The hearing was again convened on
July 15, 2010, at which time the signatories announced their intent to continue settlement
discussions to resolve all issues related to the Company's application with the exception
of those related to ETl's proposal for competitive generation service (CGS) and
associated riders.
9. On August 6, 2010, the signatories submitted the stipulation resolving all outstanding
issues regarding the Company's application with the exception of those related to ET!' s
CGS proposal. Under the stipulation, ET! will be allowed to implement base rate tariffs
and riders designed to collect an overall revenue requirement of$1,614.9 million,4 which
includes a total non-fuel retail revenue requirement of $694.9 million (base rate revenues
of $599 million plus revenue from riders of $95.9 million). The signatories also
submitted, on August 6, 20 I 0, an agreed motion to revise interim rates and to consolidate
the severed rat~case expense docket. The interim rates requested in the agreed motion
mirrored the final rates proposed for Commission approval in the stipulation. The agreed
motion further requested that the ALls consolidate with the instant proceeding Docket
No. 38346, related to severed Docket No. 37744 rate case expense issues, and admit the
parties' pre-filed exhibits into evidence.
10. On July 16 and July 20, 2010, the AUs held the hearing on the merits with respect to
ETl's CGS proposal.
11. On August 9, 2010, the AUs issued Order No. 12, granting approval of revised interim
rates for usage on and after August 15, 2010.
12. On October 5, 20 I 0, the ALls issued a proposal for decision regarding issues related to
ETl's CGS proposal.
13. On October 5, 2010, the AUs issued Order No. 13, ordering the consolidation of Docket
No. 38346, related to severed rat~case expense issues, into the instant proceeding,
4
This figure includes fuel at test year prices. If current fuel prices are substituted for test year fuel prices,
the overall revenue requirement figure would be $1,504.0 million.
57
PUC Docket No. 37744 Order Page 5of15
SOAH Docket No. XXX-XX-XXXX
admitting evidence, and returning this docket to the Commission consistent with the
agreed motion filed on August 6, 20 I 0.
14. The Commission considered this Docket at the November 10, 2010 and
December I, 2010 open meetings.
15. On November 30, 20 I 0 ET! filed an unopposed motion to sever the competitive CGS
issues from the settled issues in this docket. The Commission granted the motion at the
December I, 2010 open meeting and the Commission's decision was memorialized in
Order No. 14 issued on December 3, 2010. The CGS issues were severed into Docket
No. 38951 in Order No. 14.
Description of the stipulation and Settlement Agreement
16. The signatories to the settlement stipulated that ET! should be allowed to implement an
initial overall increase in base-rate revenues of $59 million for usage on and after
August 15, 20 I 0. The signatories further stipulated that they would request approval of
interim rates by the AU s presiding or by the Commission, as necessary, to ensure timely
implementation of this initial rate increase. The signatories further stipulated that ET!
should be allowed to implement an additional overall increase in base-rate revenues of
$9 million on an annualized basis effective for bills rendered on and after May 2, 2011,
the first billing cycle for the revenue month of May.
17. The signatories agreed that ETI's authorized return on equity shall be 10.125% and its
weighted average cost of capital shall be 8.5209%.
18. The signatories stipulated that the amount of rate increase authorized under finding of
fact 16 includes rate-case expenses and contemplates their full amortization in 2010, and
that this amount constitutes the full and final recovery of all rate-case expenses relating to
Docket No. 37744.
19. The signatories stipulated to the amount of transmission and distribution invested capital
by function as of June 30, 2009 as set out in attachment I to the stipulation.
58
PUC Docket No. 37744 Order Page6of15
SOAH Docket No. 473-1"" 1962
20. The signatories stipulated that the Company's proposed purchased-power recovery rider
will not be approved in this docket, and purchased capacity costs will be included in
base rates.
21. The signatories stipulated that the Company's proposed transmission cost recovery factor
(TCRF) will not be approved in this docket. The signatories stipulated to the baseline
values as shown in attachment 2 to the stipulation to be used in the Company's request, if
any, for a TCRF in a separate proceeding.
22. The signatories agreed that ETI's proposed cost-of-service adjustment rider and formula
rate plan will not be approved in this docket.
23. The signatories stipulated that the Company's proposed renewable-energy-credit rider
will not be approved in this docket, and the Company's renewable-energy-credit costs
shall be recovered in base rates. The signatories further stipulated that a transmission
customer that opts out pursuant to P.U.C. SUBST. R. 25.1730) shall receive a credit that
offsets the amount of renewable-energy-credit costs that are recovered in base rates from
the transmission customer.
24. The signatories agreed that ETI's proposed remote-communications-link rider should be
approved as filed by the Company.
25. The signatories agreed that ETI's proposed market-valued-energy-reduction service rider
will not be approved in this docket.
26. The signatories reached the following specific agreements regarding rate design as a part
of the overall resolution of this docket:
a. Rate Schedule IS. Rate Schedule IS will be opened to new business. In the
Company's next base-rate case, the amount of interruptible credits recoverable
from Texas retail customers shall be limited to an increase of $1 million more
than the amount requested in this docket (or a total of $6.8 million); provided,
however, that in the next rate case, the Company may request an exception to this
limitation upon a showing that the test-year credit amount in excess of the
$6.8 million cap is both cost effective and necessary to meet the Company's
generation reserve margin requirement. The signatories further agreed that the
59
PUC Docket No. 37744 Order Page 7of15
SOAH Docket No. XXX-XX-XXXX
Company will not offer additional interruptible service if the availability of total
interruptible service supplied by the Company under all interruptible service
riders exceeds 5% of the projected aggregate Company peak demand unless the
additional level of interruptible service offered in excess of the 5% cap is both
cost effective and necessary to meet the Company's generation reserve margin
requirement. To the extent that the credit amount or participation level exceeds
the limitations described in this paragraph and the Company includes test-year
credits over the $6.8 million credit-amount cap or additional participation in
excess of the 5% participation-level cap in its next rate case, the Company shall
have the burden to prove whether those test-year credits or participation levels
meet the standards established in this paragraph for inclusion in the test year. The
standards in this paragraph are in addition to any requirements in PURA for
inclusion of costs in rates. The signatories further agreed to the Schedule IS
revisions shown on attachment 3 to the stipulation.
b. Rate Schedule !HE. The signatories agreed that no change shall be made to rate
schedule !HE in this docket.
c. Lighting Class Rates. The signatories stipulated that the language under the
paragraph relating to rate group C in rate schedule SHL will be revised to reflect
that, where the Company agrees to install facilities other than its standard street
light fixture and lamp as provided under Rate Group A, a lump sum payment will
be required, based upon the installed cost of all facilities excluding the cost of the
standard street light fixture and lamp, and the customer will be billed under rate
group A.
e. Electric Extension Policy. The signatories agreed to the line-extension terms and
conditions as reflected in attachment 4 to the stipulation.
f. Life-of-Contract Demand Ratchet. The signatories agreed that the
life-of-contract demand ratchet provision in rate schedules Large Industrial Power
Service, Large Industrial Power Service-Time of Day, General Service, General
Service-Time of Day, Large General Service, and Large General Service-Time of
60
PUC Docket No. 37744 Order Page8 oflS
SOAH Docket No. XXX-XX-XXXX
Day shall be excluded from rate schedules in ETI's next rate case. The
signatories further stipulated that the foregoing rate schedules will be revised so
that the life-of-contract demand ratchet provision shall not be applicable to new
customers and shall not exceed the level in effect on August 15, 2010 for existing
customers.
g. Residential Customer Charge. The signatories agreed that the residential
customer charge shall be increased to $5.00.
h. Non-Sufficient Funds Charge. The signatories agreed that the non-sufficient
funds charge shall be increased to $15.00.
27. The signatories agreed to the class cost allocation set forth in attachment 5 to
the stipulation.
28. The signatories stipulated that the appropriate allocation between ETl's wholesale and
retail jurisdictions of baseline values and costs to be included in a TCRF is to be
addressed in the proceeding, if any, in which ET! seeks approval of a TCRF.
29. The signatories stipulated that no party waives its right to address in any subsequent
proceeding the appropriate treatment for Texas retail ratemaking purposes of power sales
between ETI and Entergy Gulf States Louisiana, L.L.C.
30. The signatories reached the following specific agreements regarding fuel-related issues as
part of the overall resolution of this docket:
a. Agreed Fuel Disallowance. The Company stipulated to a fuel disallowance of
$3 .25 million not associated with any particular issue raised by the signatories.
The disallowance will be allocated pro rata with interest over each month of the
reconciliation period and reflected in the refund in Docket No. 38403.5 The
signatories stipulated that the Company's fuel costs shall be finally reconciled for
the reconciliation period of April 1, 2007 through June 30, 2009.
b. Rider lPCR. The signatories agreed that ETI's eligible Rider IPCR costs fur the
5
Application of Entergy Texas, Inc. to Implement an Interim Fuel Refund, Docket No. 38403, Order
(Sept 16. 2010).
61
PUC Docket No. 37744 Order Page 9 of15
SOAH Docket No. XXX-XX-XXXX
period April 1, 2007 through the date the rider terminated shall be finally
reconciled with a disallowance of $300,000. The signatories further agreed that
the under-recovered balance of Rider IPCR costs shall be booked as fuel expense
in the month in which the Commission issues an order adopting the stipulation;
provided, however, that the under-recovered balance shall be allocated to
customer classes using A&E4CP.
c. Rough Production Cost Equalization (RFCE) Payments. The signatories agreed
that ET! will credit an additional $18.6 million to Texas fuel-factor customers,
which the· signatories stipulated represents the remaining portion of RPCE
payments ETI received in 2007 that were at issue in Docket No. 35269.6 The
RPCE credit shall be allocated to rate classes based on loss-adjusted kilowatt
hours at plant for calendar year 2006. For customers in the Large Industrial
Power Service rate class, the credit will be refunded based on the customer's
actual kWh usage during the billing months of January 2006 through
December 2006. Upon issuance of a final order approving the stipulation, the
RPCEs shall be credited to customers as a separate one-month bill credit in the
same form as the RFCEA Rider last approved in Docket No. 38098.7 ET! agreed
that it will terminate all appeals related to Docket No. 35269.
31. The signatories agreed that ET! will continue its accrual of storm-cost reserves at the
level of $3 .65 million annually and that this amount shall be subsumed in the base-rate
revenue increase described in finding of fact 16 above.
32. The signatories agreed that ET! shall maintain River Bend depreciation rates at current
levels, i.e., based on a 60-year life. River Bend decommissioning costs will be set at
$2,019,000 annually, which is based upon a labor-factor escalation rate of 1.67%, an
energy-factor escalation rate of 0.25%, and a waste-burial-factor-escalation rate of
6
Compliance Filing ofEntergy Texas, Inc. Regarding Jurisdictional Allocation of2007 System Agreement
Payments, Docket No. 35269, Order (Jan. 7, 2009).
7
Application of Entergy Texas, Inc. for Authorily to Implement New RPCEA Rate, Docket No. 38098,
Order (July I, 2010).
62
PUC Docket No. 37744 Order Page 10of15
SOAH Docket No. XXX-XX-XXXX
I. 71 %, resulting in an overall escalation rate of 3.62%, and net investment yields as
follows:
Nuclear-Decommissioning-Trust Projected Returns
Tax-Qualified Non-Tax-Qualified
Investments Investment
2010 5.475% 5.057%
2011 5.837% 5.236%
2012 6.306% 5.567%
2013 6.304% 5.607%
2014 6.481% 5.896%
2015 6.493% 5.909%
2016 6.412% 5.826%
2017 6.412% 5.830%
2018 6.364% 5.790%
2019 6.316% 5.748%
2020 6.268% 5.712%
2021 6.220% 5.670%
2022 2.503% 5.458%
2023 5.817% 5.055%
2024 5.382% 4.628%
2025 5.036% 4.516%
2026-2034 4.920% 4.409%
33. The signatories stipulated that the Company's depreciation rates for non-River Bend
production plant, transmission, distribution, and general plant will remain at current
levels and the Company will maintain its accounting records on a prospective basis for
purposes of depreciation accrual, depreciation reserve, retirements, additions, salvage,
and cost of removal by FERC account.
Consistencv of the Agreement with PURA and the Commission Requirements
34. Considered in light of ( 1) the pre-filed testimony by the parties entered into evidence and
(2) the additional evidence and testimony admitted during the course of the hearing on
the merits on the Company's application, the stipulation is the result of compromise from
each signatory, and these efforts, as well as the overall result of the stipulation viewed in
light of the record evidence as a whole, support the reasonableness and benefits of the
terms of the stipulation.
63
PUC Docket No. 37744 Order Page 11 of lS
SOAH Docket No. XXX-XX-XXXX
35. The evidence addressed in finding of fact 34 demonstrates that the rates, terms, and
conditions resulting from the stipulation are just and reasonable and consistent with the
public interest.
36. The total level of the Texas retail revenue requirement contemplated by the stipulation
will allow ET! the opportunity to earn a reasonable return over and above its reasonable
and necessary operating expense.
37. The stipulated revenue requirement is consistent with applicable provisions of PURA
chapter 36 and the Commission's rules.
38. To the extent that affiliate costs are included in the stipulated revenue requirement and
fuel expense, they are reasonable and necessary for each class of affiliate costs presented
in ETl's application.
39. To the extent that affiliate costs are included in the stipulated revenue requirement and
fuel expense, the price charged to ETI is not higher than the prices charged by the
supplying affiliate for the same item or class of items to its other affiliates or divisions, or
a non-affiliated person within the same market area or having the same market
conditions.
40. The retail revenue requirement in the stipulation does not include any expenses
prohibited from recovery under PURA.
41. A return on equity of 10.125% and a weighted average cost of capital of 8.5209% for ET!
should be adopted consistent with the stipulation.
42. The agreed rate-design provisions and terms and conditions of service included in the
stipulation are just and reasonable.
43. The treatment of rate-case expenses described in the stipulation is reasonable.
44. The Company's proposed remote-communications-link rider as filed by the Company
is reasonable.
45. The depreciation rates agreed to in the stipulation are just and reasonable.
64
PUC Docket No. 37744 Order Page 12 of lS
SOAH Docket No. XXX-XX-XXXX
46. The recovery of $2,019,000 annually for decommissioning costs of nuclear production
assets based on the factors agreed to in the stipulation is reasonable.
47. A $3.65 million annual storm cost accrual is reasonable.
48. The class allocation methodologies described in the stipulation are just and reasonable.
49. The fuel and IPCR-related provisions of the stipulation are reasonable.
II. Conclusions of Law
I. ET! is a public utility as that term is defined in PURA§ 11.004(1) and an electric utility
as that term is defined in PURA § 31.002(6).
2. The Commission exercises regulatory authority over ET! and jurisdiction over the subject
matter of this application pursuant to PURA§§ 14.001, 32.001, 32.101, 33.002, 33.051,
36.001-.111, 36.203, 39.452, and 39.455.
3. SOAH has jurisdiction over matters related to the conduct of the hearing and the
preparation of a proposal for decision in this docket, pursuant to PURA § 14.053 and
TEX. Gov'T CODE ANN. § 2003.049.
4. This docket was processed in accordance with the requirements of PURA, the Texas
Administrative Procedure Act, 8 and Commission rules.
5. ET! provided notice of its application in compliance with PURA§ 36.103, P.U.C. PROC.
R. 22.5l(a), and P.U.C. SUBST. R. 25.235(b)(l)-(3).
6. This docket contains no remaining contested issues of fact or law.
7. The stipulation, taken as a whole, is a just and reasonable resolution of all issues it
addresses; results in just and reasonable rates, terms, and conditions; is supported by a
preponderance of the credible evidence in the record; is consistent with the relevant
provisions of PURA; and is consistent with the public interest.
8. ET! has properly accounted for the amount of fuel and IPCR-related revenues collected
pursuant to the fuel factor and Rider IPCR.
8
TEX. GOV'TCODEANN. Chapter 2001(Vernon2007 and Supp. 2009).
65
PUC Docket No. 37744 Order Page 13 oflS
SOAH Docket No. XXX-XX-XXXX
9. The revenue requirement, cost allocation, revenue distribution, and rate design
implementing the stipulation result in rates that are just and reasonable, comply with the
ratemaking provisions in PURA, and are not unreasonably discriminatory, preferential, or
prejudicial.
I 0. Based on the evidence in this docket, the overall total invested capital through the end of
the test year meets the requirement in PURA § 36.053(a) that electric utility rates be
based on the original cost, less depreciation, of property used by and useful to the utility
in providing service.
11. ET! has met its burden of proof in demonstrating that it is entitled to the level of retail
base rate and rider revenue set out in the stipulation.
12. ET! has met its burden of proof in demonstrating that the rates resulting from the
stipulation are just and reasonable, and consistent with PURA.
III. Ordering Paragraphs
I. ETI's application seeking authority to change its rates; reconcile its fuel and purchased
power costs for the Reconciliation Period from April I, 2007 to June 30, 2009; and fur
other related relief is approved consistent with the above findings of fact and conclusions
oflaw.
2. Rates, terms, and conditions consistent with the stipulation are approved.
3. The tariffs and riders consistent with the stipulation are approved fur the initial and
second step rate increases.
4. ETI's request for waivers ofRFP instructions (RFP Schedule V) is granted.
5. ETI shall adjust decommissioning expense related to the River Bend Nuclear Generating
Station consistent with the terms of this Order.
6. Neither the stipulation and settlement agreement nor this Order constitutes the
Commission's agreement .with, or consent to, the manner in which ET!, or any entity
affiliated with ET!, has interacted with any decommissioning trust to which ET! or its
ratepayers have made contributions or provided funds. Furthermore, this Order in no
66
PUC Docket No. 37744 Order Page 14 oflS
SOAH Docket No. XXX-XX-XXXX
way constitutes a waiver or release of any conduct, whether or not such conduct occurred
before the date of this Order, that may constitute a violation of any provision of state law,
including, without limitation, the rules and regulations of this Commission relating to
nuclear decommissioning trust funds; or prevents the Staff of the Commission from
opening an investigation and taking enforcement action relating to violations of such
rules and regulations.
7. Nothing contained in this Order constitutes the consent or approval, explicit or implied,
of any modification, amendment or clarification of any power purchase agreement
between ETI and any other Entergy entity relating to the River Bend Station. Without
limiting the foregoing, nothing contained in this Order shall constitute the consent or
approval of any modification, amendment, or clarification of any power purchase
agreement between ETI and any other Entergy entity relating to the River Bend Station,
which is made to address any concerns raised by the NRC in its Request for Additional
Information regarding the River Bend Station dated March 11, 20 I 0.
8. The Rider IPCR costs and eligible fuel costs requested by ET! are, consistent with this
Order, reconciled through June 30, 2009, and are approved consistent with the
stipulation.
9. ET! shall adjust its fuel over/under recovery balance consistent with the findings in this
Order.
I 0. ET! shall file an RPCEA Rider consistent with the above findings of fact and conclusions
of law to be effective with the first billing cycle of the billing month immediately
following the effective date of this Order..
11. Because the final approved ~tes are equal to or higher than the interim rates adopted in
Order No. 3, no refund of the interim rates authorized by Order No. 3 is necessary.
12. The interim rates approved in Order No. 12 are herby approved for the initial step rate
increase contemplated by the stipulation, and ET! shall implement the second step rates
for bills rendered on and after May 2, 2011, the first billing cycle for the revenue month
of May.
67
PUC Docket No. 37744 Order Page 15 oflS
SOAH Docket No. XXX-XX-XXXX
13. Within 30 days of the date of this Order, ET! shall file a clean copy of all of the tariffS
and schedules approved in this docket and a clean copy of the attachments to the
stipulation.
14. The entry of this Order consistent with the stipulation does not indicate the Commission's
endorsement of any principle or method that may underlie the stipulation. Neither should
entry of this Order be regarded as a precedent as to the appropriateness of any principle
or methodology underlying the stipulation.
15. All other motions, requests for entry of specific findings of fact, conclusions of law, and
ordering paragraphs, and any other requests for general or specific relief, if not expressly
granted in this order, are hereby denied.
SIGNED AT AUSTIN, TEXAS the \ 6\-h day of December 2010
PUBLIC UTILITY COMMISSION OF TEXAS
DONNA L. NELSON, COMMISSIONER
q:\cadm\orders\final\37000\37744fo.docx
68
SOAH DOCKET NO. XXX-XX-XXXX
PUC DOCKET NO. 39896
APPLICATION OF ENTERGY TEXAS, § PUBLIC UTILITY COMMISSION
lNC. FOR AUTHORITY TO CHANGE § S \ b
Counsel
Ending Sequence No.
5SI'~-
Question No.: OPUC 1-3 Part No.: Addendum:
Question:
If your answer to OPUC's RF! No. 1-1 is no, please provide data and other
information to show that the amount being recovered as an affiliate expense related to
project code F3PPWET308 in Docket No. 39896 has not also been requested for
recovery in this proceeding as a rate case expense.
Response:
See the response to OPUC 1-1.
40295 SS15
75
ENTERGY TEXAS, INC.
PUBLIC UTILITY COMMISSION OF TEXAS
SOAH DOCKET NO. XXX-XX-XXXX
PUC DOCKET NO. 39896 -2011 ET! Rate Case
Response of: Entergy Texas, Inc. Prepared By: J. Stephen Dingle
to the Third Set of Data Requests Sponsoring Witness: Patrick J. Cicio
of Requesting Party: Office of Public Utility Beginning Sequence No.
Counsel
Ending Sequence No.
Question No.: OPUC 3-17 Part No.: Addendum:
Question:
a. Please explain why ET! will continue to incur expenses for negotiations
related to the Calpine purchased power agreement after the test year.
b. Explain in detail the Calpine PPA negotiation expenses that will be expected
to be incurred in 2012 and 2013.
c. Provide documentation supporting your response.
Response:
a. The costs "'corded in Project Code F3PPWET308 include costs associated with
obtaining regulatory approval for the Calpine Contract, which processes extend
beyond the test year. The Company expects to incur similar expenses in the
future on an ongoing basis.
b. These will be costs associated with responding to issues arising within the
pending rate case in Texas, as well as participating in LPSC Docket No. U-3032 J.
c. See the Project Summary for Project Code F3PPWET308 in Exhibit SBT-E.
39896 SS466
76
ENTERGY TEXAS, INC.
PUBLIC UTILITY COMMISSION OF TEXAS
SOAH DOCKET NO. XXX-XX-XXXX
PUC DOCKET NO. 39896 - 2011 ETI Rate Case
Response of: Entergy Texas, Inc. Prepared By; J. Stephen Dingle/Joe
Bennett
to the Ninth Set of Data Requests Sponsoring Witness; Patrick J.
Cicio/Michael P. Considine
of Requesting Party: Office of Public Utility Beginning Sequence No.SS '154-
Counsel
Ending Sequence No. S$1:s.f-
Question No.: OPUC 9-6 Part No.: Addendum:
Question:
a. Regarding ETI's response to OPC RF! No. 3-17, is ETI implying that any
rate case expenses related to the Calpine Contract in Docket No. 39896
(e.g. RF! responses, legal fees) will be charged to F3PPWET308? Please
explain your response.
b. Are there any other instances where Docket No. 39896 expenses are being
charged to multiple projects? If so, please identify all costs and the
associated project numbers.
Response:
a. No rate case expenses were charged to that project code, although costs
for that project code were included in ETI's costs.
b. All costs pertaining to Docket No. 39896 should be recorded in Project
Code F5PPETXO 11.
177
39896
ENTERGY TEXAS, INC. 2011 TX Rate Caso
Page 1168
PROJECT SUMMARY
ESI
Project Code Description B!ll!ng Method
SPO Calpine PPNProject Houslo OIRECTTX
F3PPWET308
Test Year Affiliate Billings to ET!:
Account Total Exclusions Pro Forma Adjusted
234000 - AJP - Affiliate 0 0 0 0
403100 - Oepreciation Exp-Serv Co AUoc 7.241 0 0 7,241
4031AM-Oeprec Exp biUed from Serv Co 5,168 0 0 5,168
408110 - Employment Taxes 11,679 0 412 12,091
426500 - other Oeductions 0 0 0 0
500000 - Oper Supervision & Engineerin 1,548 0 37 1,585
506000 - Misc Steam Power Expenses 2,931 0 70 3,001
920000 - Adm & General Salaries 209,513 0 4,361 213,874
921000 - Office Supplies And Expenses 2,035 0 0 2,035
923000 - Outside seiViOOs EmPiOYed--
-- ~--1-10.951 C--·----
0
----- 0
-·--···--
110,951
--·------------------
926000 - Employee Pension & Benefits
.. ---···--··-· -------·
82,844
~·
0
---
-555
-·----
82,288
930200 - Miscellaneous General Expense -2,271 0 0 -2,271
Total 431,639 0 4.324 435,963
--------·-- - ----·· ------ --~---··-· '-·----'---.-- -------
Detail Bv Class·
Class Total Exclusions Pro Forma Adjusted
ENERGY ANO FUEL MANAGEMENT 94,945 0 1,996· 96,941
FEOERAL PRG AFFAIRS 1,206 0 -1,206 0
FOSSIL PLANT OPERATIONS 7,037 0 139 7,176
TREASURY OPERATIONS 12,539 0 245 12,764
HUMAN RESOURCES 37,837 0 .£7 37,770
LEGAL SERVICES 255,552 0 2,916 258,470
OTHER EXPENSES 3,722 0 171 3,893
FINANCIAL SERVICES 6,195 0 124 6,319
OEPRECIATION 12,409 0 0 12,409
TAX SERVICES 197 0 4 201
Total i 431,639 0 4,324 435,963
Scope of Work
Statement of Purpose:
The overall purpose of this project is to capture and manage costs associated wi1h the Power Purchase Agreement {PPA} from
Calpine Corporation for Entergy Texas. Inc. (ETJ}.
Primary Aclivilies:
The primary activity associated 'Nilh lhis project is lhe negotiations of the Jong-term PPA for the delivery of electric capacity,
energy and olher associated electric products from the CarviUe Facility for ETJ.
Primary ProducJs or Oetiverables:
The primary products or deliverables of lhis project are an executed and approved Jong-term PPA 'Nilh Calpine Corporation for
the delivery of electric capacity, energy and other associated electric products from the CarviUe facility to meet ETJ"s short and
Jong-term capacity needs.
Justification of Billing Melhod:
The costs associated with lhe project wiU include the inlernal and third-party costs associated 'Nilh the PPA"s negotiations,
Amounts may nol add or tie lo other schedules due lo rounding. Project Code F3PPWET308
178
78
ENTERGY TEXAS, INC. 2011 TX Rate Case
Page1169
PROJECT SUMMARY
ESI
Project Code Description Billing Method
SPO CaJpine ?PA/Project Housto OJRECTTX
F3PPWET308
development, review and intemaJ/reguJatory approval process. These costs may Jead to the execu)ion of a Jong-term PPA with
Calpine Corporation for the delivery of eJectric capacity, energy and other associated eJectric products from the CarvWe FacUity
Jhat wouJd benefit ETJ and shouJd therefore be charged onJy Jo ETJ via bUling method DJRECTTX.
Amounts may not add or tie Jo other scheduJes due Jo rounding. Project Code F3PPWET308
179 79
PUC DOCKET NO. 40295
SOAH DOCKET NO. XXX-XX-XXXX
APPLICATION OF F,NTERGY §
TEXAS, INC. FOR RATE CASE §
EXPENSES PERTAINING TO PUC § OF TEXAS
DOCKET NO. 39896 §
ORDER
This Order addresses the rate-case expenses pertaining to Docket No. 39896, 1 Entergy
Texas, Inc. 's last rate case. Entergy requested $8.8 million in rate-case expenses associated with
Docket No. 39896-$7.6 million for Entergy's own rate-case expenses and $1.2 million for
Cities' rate-case expenses. The proposal for decision in this docket was issued on February 19,
2013. In the proposal for decision, the ALJ recommended allowing Cities' rate-case expenses
incurred through August 31, 2012, plus up to $75,800 in rate-case expenses as they are incurred
alter August 31, 2012. The ALJ also recommended that Entergy's rate-case expenses be reduced
to account for Entergy taking certain positions in the rate case regarding financially-based
incentive compensation and transmission equalization expenses. The Commission considered
the proposal for decision at the April 11 and April 25, 2013 open meetings. The Commission
adopts in part and reverses in part the proposal for decision, including findings of fact and
conclusions of law.
I. Estimated Rate-Case Expenses
The Commission reverses the proposal for decision regarding Cities' $75,800 in
estimated rate-case expenses to be incurred after August 31, 2012. 2 In Docket No. 37772, the
Commission found that approving estimated rate-case expenses for two different parties
representing Cities is not in the public interest and disallowed their recovery in the rate-case
expense surcharge, but did not prohibit the Cities from seeking recovery of actual rate-case
1
lpplicalirm o( Enter.l{y Texas. Inc. fId. at 32-34.
6
Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 28840, Proposal
for Decision at 92-97, Findings of Fact Nos. 164-170, Order at 35 (Aug. 15, 2005); Application of AEP Texas
Central Company for Aulhority to Change Rates, Docket No. 33309, Proposal for Decision at 116-121, Finding of
Fact No. 82, Order on Rehearing at 12 (March 4, 2008); Application cf Oncor Electric Delivery Company, LLC, for
Alllhority to Change Rates, Docket No. 35717, Proposal for Decision at 96-100, Finding of Fact No. 93, Order on
Rehearing at 22 (Nov. 30, 2009); and Application of CenterPoint Electric Delivery Company. llC, for Authority to
Change Rates, Docket No. 38339, Proposal for Decision at 66-67, Findings of Fact Nos. 81-83, Order on Rehearing
at 22 (June 23, 2011).
7
Docket No. 39896, Order on Rehearing at 5-6, 7-8 (Nov. 2, 2012).
PUC Dorket No. 402<)5 Order P:1ge J of8
SOAH Oocket No. XXX-XX-XXXX
case expense request, reduced hy $208,494 in disallowances made by the ALJ 8 and atlinned by
the Commission. The Commission further reduces this amount by an additional $522.244.66,
which is the amount of rate-case expenses related to tinancially-base683 S.W.2d 783, 786 (Tex. App.-Austin 1985, no pet.).
37
ETI Ex. 7 (Considine Rebuttal) at Attachment MPC-R-1.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 13
PUC DOCKET NO. 40295
d. Miscellaneous Internal Rate Case Expenses
Under the heading of"Intemal Rate Case Expenses (Non-Payroll)," ETI seeks recovery of a
number of categories of expenses. State Agencies challenge the following four categories:
• "business meals/entertainment" in the amount of $3,852;
• "other employee expenses" in the amount of$3,423;
• "employee mtgs/functions" in the amount of $7,762; and
• "utility bills" in the amount of$2,518. 38
According to State Agencies, the justification for these charges has not been explained, nor are they
reasonable and necessary. No other party challenged these expenses.
ETI responds by explaining, in great detail, where the supporting documentation can be
found, within the company's exhibits, to justify each of the expenses. 39 Without repeating that
discussion here, the ALJ is convinced that the evidence in the record supports the conclusion that the
expenses are reasonable and should be recovered by ETI.
e. Costs Associated with the Calpine-Carville PPA
In a "Recommendation" filed prior to the hearing in this matter, OPUC argued that the
Commission should disallow the recovery of any rate case expenses associated with the regulatory
approval of the Calpine-Carville Purchased Power Agreement (the Calpine-Carville PPA). In
Docket 39896, ETI sought, and obtained, regulatory approval of the Calpine-Carville PPA.
The affiliate expenses related to the contract were assigned to Project F3PPWET308. The
Project F3PPWET308 costs were approved for recovery in Docket 39896. 40 As a result, OPUC
38
ETI Ex. 7 (Considine Rebuttal) at Attachment MPC-R-1; see also State Agencies Init. Br. at 21.
39
ETI Reply Br. at 23-24.
40
Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred
Accounting Treatment, Docket 39896, Proposal for Decision at 236 (July 6, 2012).
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 14
PUC DOCKET NO. 40295
contends that ETI has already recovered its expenses associated with the Calpine-Carville PPA and,
if it were allowed to recovery those expenses again, it would be receiving a double recovery. 41
OPUC did not identify a specific dollar amount that it believes should be disallowed. Moreover,
OPUC did not discuss this issue in any of its post-hearing briefing. In their post-hearing briefing,
State Agencies "concurred" with OPUC's recommendation, but provided no discussion of the
issue. 42
ETI did discuss this issue in its post-hearing briefing. The company points out, correctly, that
the Commission has already specifically rejected OPUC's double recovery argument. In
Docket 39896, OPUC argued that the costs ETI sought related to the Calpine-Carville PPA should
have been denied in that docket because they were, among other things, rate case expenses. The
Commission specifically disagreed and allowed recovery of the costs in that docket. 43 In other
words, because the Commission has already concluded that ETI did not recover any rate case
expenses associated with the Calpine-Carville PPA in Docket 39896, the company will not be
receiving a double recovery if it recovers such expenses in this docket.
Further, as explained by ETI witness Considine, costs were charged to Project F3PPWET308
(the internal project code for the Calpine-Carville PPA development costs) as the contract was being
developed. Those costs were recovered in Docket 39896. On the other hand, costs were charged to
Project F5PPETX011 (the internal project code for the rate case in Docket 39896) as testimony or
other hearing-related work was performed for Docket 39896. According to ETI, it is only the latter
costs, associated with Project F5PPETX01 l, that are being sought here. As a result, no double
recovery will occur. 44 The ALJ concludes that ETI has the better argument on this issue, and
41
Application of Entergy Texas, Inc. for Rate Case Expenses Pertaining to PUC Docket No. 39896, Docket 40295,
OPUC's Recommendation and Request for Hearing at 2-3 (November 6, 2012).
42
State Agencies Reply Br. at 20.
43
Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred
Accounting Treatment, Docket 39896, Proposal for Decision at 236 (July 6, 2012).
44
ETI Ex. 7 (Considine Rebuttal) at 7-9.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 15
PUC DOCKET NO. 40295
recommends that ETI be allowed to recover its rate case expenses associated with the
Calpine-Carville PP A.
f. Specific Items That State Agencies Contend Cast Doubt on ETl's
Overall Scrutiny of Its Expenses
State Agencies performed what they described as a number of "spot check" reviews ofETI' s
costs and identified several errors or items that they contend should be disallowed. Moreover, State
Agencies contend that it is not only these specific items which should be disallowed. Rather, they
argue that the flaws they have identified should cast doubt on the overall adequacy of the internal
review process utilized by ETI in quantifying its rate case expenses. According to State Agencies,
"[i]dentification of these questionable costs underscores the need for conservative, rather than
liberal, standards for allowing rate case expenses. "45 Similarly, State Agencies argue that these items
demonstrate ETI's "lack of diligence in exercising basic economic restraint."46
Staff agrees that State Agencies' examination of these issues "call[s] into question the
thoroughness ofETI's review of its rate case expenses."47 Staff further points out that, because the
testimony of ETI witness Considine (who was the company's prime witness supporting the
reasonableness of its internal rate case expenses) contained "mistakes that he was engaged to
identify," his testimony "is oflimited value."48 In its Reply Brief, Staff reiterates: "Staff shares the
concerns raised by State Agencies regarding the adequacy of ETI's review of its rate case
expenses."49 Similarly, OPUC agrees that State Agencies' examples illustrate that, as to rate case
expenses, ETI did not act as a prudent gatekeeper. 50
45
State Agencies Init. Br. at 7.
46
State Agencies Reply Br. at 9.
47
Stafflnit. Br. at 12.
48
Stafflnit. Br. at 12.
49
Staff Reply Br. at 9.
50
OPUC Init. Br. at 1.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 16
PUC DOCKET NO. 40295
(1) External Legal Fees
ETI seeks to recover roughly $2.4 million in legal fees paid to the Duggins Wren law firm. 51
State Agencies argue that this amount should be reduced. ETI witness Stephen Morris was hired to
review ETI' s external legal expenses and testify about the reasonableness of those expenses. 52 State
Agencies question the objectivity, quality, and extent of Mr. Morris' review. For example, State
Agencies point out that, rather than being retained by ETI, he was retained by Duggins Wren, the
firm whose fees he was to review. 53 Staff agrees that this arrangement "likely undermined
Mr. Morris' objectivity." 54
State Agencies also contend that, based upon his invoices, Mr. Morris spent only a ''minimal"
amount of time reviewing Duggins Wren's bills. 55 Yet, by State Agencies' own reckoning,
Mr. Morris and his associate spent roughly 21 hours reviewing Duggins Wren bills. 56 Mr. Morris
testified as to the reasonableness of the hourly rates charged by Duggins Wren. State Agencies
argue, however, that Mr. Morris' focus was too narrow and he should have, instead, been critical of
the fact that too many Duggins Wren attorneys, twelve, were involved in the case. 57 State Agencies
are also critical of the fact that Mr. Morris apparently did not scrutinize Duggins Wren's bills for
duplicative legal work. For example, State Agencies point out that on April 25, 2012, a day from the
hearing in Docket 39896, five Duggins Wren attorneys billed a total of 26.3 hours for a hearing day
that lasted less than seven hours and in which in-house ETI lawyers defended many of the witnesses.
On the next day, April 26, six Duggins Wren attorneys billed a total of24.4 hours for a hearing day
58
that lasted less than eight hours and in which only three Duggins Wren attorneys participated. State
51
ETI Ex. 7 (Considine Rebuttal) at Attachment MPC-R-1.
52
ETI Ex. 8 (Morris Direct) at 2.
53
State Agencies Init. Br. at 10.
54
Staff Reply Br. at 9.
55
State Agencies Init. Br. at 10.
56
State Agencies Init. Br. at 12.
57
State Agencies Init. Br. at 9.
58
State Agencies Init. Br. at 13.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 17
PUC DOCKET NO. 40295
Agencies contend that "a reduction is in order" for the Duggins Wren costs, but do not suggest what
size the reduction should be.
ETI responds by defending the reasonableness of the Duggins Wren costs. For one thing, ETI
points out that the $2.4 million in legal fees paid to Duggins Wren includes fees and expenses for
five consultants billed through Duggins Wren without mark-up. 59 Additionally, ETI explains that the
huge scope of the hearing necessitated substantial legal work. ETI presented 39 witnesses who
discussed hundreds of categories of costs. ETI points out that while it used the services of
12 attorneys, they were opposed by 15 attorneys: four for Staff; three for TIEC; three for Cities; and
one each for State Agencies, OPUC, U.S. Department of Energy, Kroger, and Wal-Mart. 60
The ALJ is unswayed by State Agencies' arguments. Given the size and complexity of
Docket 39896, the legal costs involved do not appear to be inordinate. Mr. Morris testified, credibly,
that the fees and expenses charged by Duggins Wren were reasonable and necessary. The ALJ does
not recommend any reduction of the fees in response to State Agencies' arguments.
(2) Meals and Snacks
State Agencies identified 19 entries in Duggins Wren invoices whereby the firm charged ETI
for meals or snacks. According to State Agencies, most of these purchases occurred during business
hours and involved only law firm personnel. ETI personnel were only occasionally involved in these
purchases. Almost all of the charges were for meals or snacks delivered to Duggins Wren's offices.
The purchases total $2,723.54. 61 State Agencies contend that these costs were not necessary for
participation in Docket 39896 and should be disallowed.
59
ETI Reply Br. at 19; ETI Ex. 6 (Considine Supp.) at 8.
60
ETI Reply Br. at 19.
61
State Agencies Init. Br. at 14-15.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 18
PUC DOCKET NO. 40295
Moreover, State Agencies point out that Duggins Wren is applying a different standard to
itself than it applies to its own contractors. Pursuant to the contract by which Duggins Wren hired
Mr. Morris, meals while he or his staff are located at his office are not reimbursable. 62 Thus, State
Agencies conclude that Duggins Wren should be held to the same standard when passing on rate case
expenses for office meals, beverages, and snacks. 63
ETI responds by pointing out that the charges were not done routinely, but only when
necessary to enable personnel "to work over lunch and dinner to meet certain deadlines ... and as an
alternative to purchasing reimbursable meals at restaurants when out-of-town members of the rate
case team worked in Austin."64 ETI describes the expenses as a reasonable part of prosecuting a
laborious rate case. The ALJ agrees and does not recommend any disallowance of these costs.
(3) Courier and Taxi Services
State Agencies identified 20 dates in Duggins Wren invoices whereby the firm charged ETI
for courier, taxi, or Federal Express charges for delivery of documents that State Agencies argue
could have been delivered electronically. The charges total $1,004.52. 65 State Agencies contend
that these costs were not necessary for participation in Docket 39896 and should be disallowed.
State Agencies again point out that Duggins Wren is applying a different standard to itself than it
applies to its own contractors. The contract by which Duggins Wren hired Mr. Morris states that
"advances in technology, specifically transmission of information and documentation by e-mail,
scanning, ... etc. have made routine ... delivery of hard copy documents less critical and, in many
62
State Agencies Ex. 15 at. 3.
63
State Agencies Init. Br. at 14.
64
ETI Reply Br. at 20.
65
State Agencies Init. Br. at 16-17.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 19
PUC DOCKET NO. 40295
cases, unnecessary. " 66 Thus, State Agencies conclude that Duggins Wren should be held to the same
standard when passing on rate case expenses for document delivery. 67
ETI responds by explaining the context of many of the charges. For example, two of the
three cab fares were for a paralegal to attend and transport voluminous documents to the hearing, and
the third was to transport the same paralegal to the Commission for legal research. 68 As to the
courier and FedEx charges, ETI points out that Commission rules require some types of documents
to be physically delivered for filing, and that the use of couriers and FedEx is sometimes entirely
appropriate. ETI argues that it was "completely reasonable" for ETI to have incurred roughly $1,000
in courier and FedEx charges over the course of a rate case of the size and scope of Docket 39896.
The ALJ agrees and recommends no disallowance of these charges.
(4) Meals Over $25
ETI asserts that its intent was to exclude from its rate case expenses any meals above $25 per
69
person. State Agencies have, however, identified at least six meals above $25 that were
erroneously included as a part of ETI's rate case expenses. 70 ETI admits that at least some of these
charges were included in error. 71 ETI disputes, however, the notion that these errors should call into
question the overall reliability of its rate case expenses.
The ALJ agrees with ETI. This was a large case with a large number of expenses. The
relatively few errors with respect to meals uncovered by State Agencies do not lead the ALJ to doubt
the overall accuracy ofETI's accounting. Nevertheless, by the ALJ's reckoning, the total amount
66
State Agencies Ex. 15 at 4.
67
State Agencies Init. Br. at 16.
68
ETI Reply Br. at 20.
69
State Agencies Ex. 5.
70
State Agencies Exs. 1, 12; State Agencies Reply Br. at Atts. 3, 6.
71
Tr. at 40.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE20
PUC DOCKET NO. 40295
that should be disallowed for meals over $25 (i.e., the amount by which the meals exceeded
$25/meal) is $281.04.
(5) Clothing and Laundry Service
State Agencies identified, as part of ETI's requested rate case expenses, a $10.44 invoice
from a Duggins Wren attorney for the purchase of a shirt and socks "due to unexpected extended
stay." 72 Similarly, OPUC contests a $40.33 laundry charge incurred by the same attorney for the
same reason. 73 ETI witness Considine generally agreed that clothing charges by attorneys working
on the rate case should not be passed through to ratepayers as a rate case expense. 74
ETI argues that the expenses were reasonable because they were brought about by an
unplanned, but necessary, extension of the attorney's business trip. 75 Mr. Morris testified that such
expenses can be considered reasonable. 76 Nevertheless, ETI has agreed to no longer request
reimbursement for the $10.44 clothing charge. Because laundry has to be done regardless of where
one finds oneself, the ALJ recommends that the $40.33 laundry charge likewise be disallowed.
(6) Airfare and Lodging
State Agencies identify several charges for airfare by ETI employees or consultants that were
in the $500 to $650 range. State Agencies fault ETI for not controlling costs by securing discount, or
at least more economical, fares. 77 Similarly, State Agencies complain that, too often, ETI employees
or consultants "went 'first class' on accommodations," incurring charges of more than $200 per night
72
State Agencies Ex. 17 at 20.
73
OPUC Init. Br. at 1-2.
74
Tr. at 43.
75
ETI Reply Br. at 22.
76
Tr. at 67-68.
77
State Agencies Reply Br. at 11-12.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE21
PUC DOCKET NO. 40295
and, on occasion, $300 per night. State Agencies also complain of inadequate documentation of
lodging charges, pointing to a $4 79 .55 lodging charge without any underlying receipts. 78 ETI makes
no response to these complaints.
The ALJ acknowledges that these complaints raise a legitimate concern. It is human nature
to be more carefree with "other people's money'' than with one's own. The complaints raised by
State Agencies suggest that ETI may have been more lax with its spending because it believed that
airfare and lodging expenses would ultimately be borne by its ratepayers. Nevertheless, other than
for the $4 79 .5 5 lodging charge, State Agencies' complaints are too vague and unproven to justify any
specific disallowance recommendations by the ALJ. For example, although it might not always cost
$600 to get from Point A to Point B, such a fare might be unavoidable under certain circumstances.
Without evidence in the record demonstrating that ETI paid $600 for an airfare when a cheaper fare
was available, the ALJ cannot conclude that the fare was unreasonable. The same logic applies to
the lodging complaints. Accordingly, the ALJ recommends no large disallowances related to airfare
and lodging charges, but does recommend disallowing the $479.55 lodging charge that 1s
unsupported by receipts.
2. Challenges to Specific ETI Rate Case Expenses That are Difficult to Quantify
a. Financially-Based Incentive Compensation
One of the hotly contested issues in Docket 39896 concerned ETI's request to recover,
through its rates, incentive compensation paid to its employees that was tied to the company's
financial goals (financially-based incentive compensation). In Docket 39896, all parties, including
ETI, agreed that Commission precedent mandated that financially-based incentive compensation is
not recoverable. Nevertheless, in its application, ETI asked the Commission to reconsider its
precedents on this issue. ETI contended that the reason why cost recovery had been denied for
financially-based incentive compensation in prior rates cases was that, in those prior cases, there was
78
State Agencies Reply Br. at 13-14.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE22
PUC DOCKET NO. 40295
a lack of evidence showing sufficient benefits to ratepayers. ETI asserted that it assembled evidence
not previously considered by the Commission showing the benefits to ratepayers of using financial
measures in incentive compensation programs.
All of the other parties in Docket 39896 opposed ETI's efforts to recover the costs of its
financially-based incentive compensation, uniformly agreeing that the Commission has a well-
established and straightforward policy that incentive compensation tied to financial goals is not
recoverable. In the PFD in Docket 39896, the ALJs concluded that ETI should not be entitled to
recover its financially-based incentive compensation costs:
Simply put, the ALJs conclude that ETI has failed to establish a sufficient
justification for overturning the well-established Commission policy that financially
based incentive compensation is not recoverable. 79
The Commission agreed and ordered that $6, 196,03 7 plus associated FICA taxes (representing ETI' s
financially-based incentive compensation payments) should be removed from ETI's Operating and
Maintenance (O&M) expenses, and $335,752.96 (representing ETI's capitalized incentive
compensation that was financially-based) should be excluded from ETI's rate base. 80
In this docket, Staff, State Agencies, and OPUC contend that ETI should not be entitled to
recover any rate case expenses it incurred in attempting to recover its financially-based incentive
costs in Docket 39896. For example, Staff argues that, by challenging "overwhelming Commission
precedent," ETI did not act reasonably when it incurred expenses litigating for recovery of its
financially-based incentive costs. 81 Staff contends that the Commission has such an ''unequivocal"
history of denying recovery for financially-based incentive payments that "ETI should have known
79
Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred
Accounting Treatment, Docket 39896, Proposal for Decision at 236 (July 6, 2012).
80
Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred
Accounting Treatment, Docket 39896, Order on Rehearing at 17-18, 24-25 (November 1, 2012)
81
Staff Reply Br. at 5; see also Stafflnit. Br. at 7-10.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE23
PUC DOCKET NO. 40295
that litigating a position opposed to [it] was not a reasonable use of resources." 82 State Agencies
point out that Docket 39896 was merely the latest of three recent cases in which ETI sought, but
failed to obtain, authority to charge ratepayers for its financially-based incentive costs (the others
being Dockets 34800 and 37744). 83
ETI defends its decision to seek to recover financially-based incentive costs in Docket 39896
by contending that the issue of the compensability of such costs is undergoing "continuing
clarification" at the Commission. 84 Moreover, ETI suggests that, in open meetings,
"Commissioners" have expressed some concern with the Commission's precedents on this issue and
suggested recovery might be allowed in a "properly organized and evidenced" case. 85 Finally, ETI
points to a recent SOAH order in an on-going SWEPCO rate case in which the ALJs denied State
Agencies' attempt to have stricken testimony proffered by SWEPCO regarding financially-based
incentive compensation. 86
The ALJ agrees with Staff, State Agencies, and OPUC. It was obvious throughout the
hearing in Docket 39896 that ETI was taking an aggressive position and making a "long-shot"
argument in seeking recovery for its financially-based incentive compensation. 87 In its briefing in the
present case, ETI cites to a number of cases in which, over the years, other utilities have requested
recovery of financially-based incentive compensation. These examples, however, hurt ETI's cause
more than they help it because all of the requests were unanimously denied by the Commission. This
hardly suggests that the issue is undergoing "continuing clarification." Likewise, ETI's suggestion
that "Commissioners" have expressed some concern with the Commission precedent overstates and
distorts the facts. The statements relied upon by ETI came from a single Commissioner,
82
Stafflnit. Br. at 8.
83
State Agencies Init. Br. at 7-8.
84
ETI Init. Br. at 7.
85
ETI Init. Br. at 7; ETI Ex. 12 (Morris Rebuttal) at 5-6.
86
Application of Southwestern Electric Power Company for Authority to Change Rates and Reconcile Fuel Costs,
Docket No. 40443, SOAR Order No. 17 (Dec. 13, 2012).
87
The ALJ in the present case was also one of the presiding ALJs in Docket 39896.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE24
PUC DOCKET NO. 40295
Mr. Anderson, not multiple C9mmissioners. Moreover, in that statement, Commissioner Anderson
only obliquely implied that he might prefer to allow recovery for financially-based incentive costs,
but he agreed that Commission precedent mandates otherwise, and the Commission voted
unanimously to disallow such costs in the case before them. Additionally, Commissioner Anderson
has stated that, if the Commission were to ever discontinue "such a long and accepted precedent," it
should do so through "rulemaking" rather than "do it in a particular case." 88
Finally, ETI's reliance on the recent SOAH order in the SWEPCO case is similarly
misplaced. In that order, the ALJs effectively held that SWEPCO was not legally precluded from
seeking recovery for its financially-based incentive compensation. It is one thing to acknowledge
that a utility has a legal right to pursue a long-shot theory. It is another thing entirely, however, to
hold that the ratepayers must pay the costs of the utility's pursuit of that long-shot.
Simply put, the ALJ concludes that ETI did not act reasonably when it incurred expenses
litigating for recovery of its financially-based incentive costs in the face of clear and consistent
precedent to the contrary on the issue. As such, the ALJ recommends that ETI' s expenses be cut by
some amount to account for this issue. The problem then becomes how to quantify the size of the
disallowance. A few of ETI' s expenses relating to the pursuit of its financially-based incentive
compensation are clear. ETI utilized the services of Dr. Jay Hartzell as an expert witness on this
issue. In total, ETI paid Dr. Hartzell at least $12,825 in consulting fees, plus $13 ,680 in legal fees
related to the preparation of his testimony. 89 This, however, does not capture ETI's entire cost of
litigating the issue of financially-based incentive compensation. Substantial costs were incurred, for
example, in discussing the issue at the hearing and in post-hearing briefing. These additional
amounts are not in the record. In Section IV.C.3 of this PFD, below, the ALJ discusses various
possible approaches for reducing the amount of rate case expenses recovered by ETI to account for
the financially-based incentive compensation issue.
88
Staff Reply Br. at 6; OPUC Ex. 3; Open Meeting Tr. at 190 (July 30, 2009).
89
ETI Ex. 10 (Morris Supp. Direct) at 15-16; State Agencies Ex. 3.
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b. Transmission Equalization (MSS-2) Expenses
Another of the hotly contested issues in Docket 39896 concerned ETI's request to recover,
through its rates, roughly $9 million more for transmission equalization payments than it actually
paid in the Test Year. ETI is one of several "Entergy Operating Companies" that shares usage of an
Entergy transmission grid. Payments for use of the grid (the transmission equalization payments) are
made among the Entergy Operating Companies based upon a highly complex formula set out in the
"MSS-2" agreement.
In the Test Year at issue in Docket 39896, ETI made transmission equalization payments
totaling roughly $1. 7 million. Rather than seeking to recover only $1. 7 million, however, ETI sought
to recover roughly $10. 7 million, which it claimed represented its anticipated transmission
equalization payments in the Rate Year. ETI claimed the additional $9 million was based on the
company's estimates of transmission construction projects that were expected to have been
completed by or during the Rate Year.
All other parties in Docket 39896 opposed ETI's effort to recover more than its Test Year
expenses. The ALJs concluded that ETI failed to meet its burden to prove that its proposed Rate
Year MSS-2 costs were known and measurable. 90 The Commission agreed and ordered that only
ETI's Test Year costs should be counted. 91 The Commission described ETI's projection ofits Rate
Year expenses as ''uncertain and speculative."92
In this docket, Staff, OPUC, and State Agencies contend that ETI should not be entitled to
recover any rate case expenses it incurred in attempting to recover the additional $9 million in
90
Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred
Accounting Treatment, Docket 39896, Proposal for Decision at 116 (July 6, 2012).
91
Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred
Accounting Treatment, Docket 39896, Order on Rehearing at 20-21, FOFs 87-94 (November 1, 2012).
92
Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred
Accounting Treatment, Docket 39896, Order on Rehearing at 20, FOF 90 (November 1, 2012).
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 26
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projected transmission equalization payments. 93 As explained by Staff: "It was clearly unreasonable
for ETI to have sought recovery for [its projected Rate Year costs] due to the exceedingly speculative
nature of those costs, and therefore a disallowance to its requested rate case expense amount should
be imposed." 94 OPUC witness Nathan Benedict testified that, by seeking the additional $9 million,
ETI was, in effect, challenging the precedent that post-Test Year adjustments must be known and
95
measurable.
ETI responds by first disputing the notion that it was "challenging precedent" by seeking the
additional $9 million.
ETI did not incur rate case expenses in pursuit of a position contrary to the well-
established 'known and measurable' standard for PTYAs [post Test Year
adjustments]. Rather, the Commission disagreed that the evidence put forth by ETI
met that standard. This is a very important distinction. Finding that evidence put
forth by a utility did not meet an established standard does not equate to a finding that
the utility unreasonably contested the applicability of such standard. 96
ETI further points out that the evidence in the record supported its contention that its actual post-Test
97
Year transmission equalization payments were on an upward trend.
The ALJ recommends that ETI's rate case expenses associated with its pursuit of the
additional $9 million for post-Test Year transmission equalization payments be disallowed. The ALJ
acknowledges the distinction made by ETI: It sought not to challenge the "known and measurable"
precedent, but merely failed to meet the standard. In this regard, ETI' s position as to transmission
equalization payments was perhaps less controversial than its position as to financially-based
incentive compensation. Nevertheless, ETI took another "long-shot" position as to its transmission
equalization payments. Its claim was based on future transmission construction projects that might
93
OPUC Init. Br. at 9-10, 12; Stafflnit. Br. at 13; State Agencies Reply Br. at 17.
94
Stafflnit. Br. at 13.
95
OPUC Ex. 1 (Benedict Direct) at 7-8.
96
ETI Init. Br. at 8 (emphasis in original, footnotes omitted).
97
ETI Reply Br. at 16.
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never be undertaken and that were found by the Commission to have been speculative. Accordingly,
the ALJ concludes that ETI did not act reasonably when it litigated the issue, and recommends that
ETI' s expenses related to this issue not be passed on to the ratepayers.
Having concluded that these rate case expenses should not be paid by the ratepayers, the
problem again becomes how to quantify the expenses. ETI did not structure its rate case expenses in
such a manner as to make it possible to determine how much of the expenses were incurred in
pursuing the additional $9 million in transmission equalization payments. 98 In Section IV.C.3 of this
PFD, below, the ALJ discusses various possible approaches for reducing the amount of rate case
expenses recovered by ETI to account for the transmission equalization payments issue.
c. Purchased Power Capacity Rider
In Docket 39896, ETI initially requested a Purchased Power Capacity Rider (PPCR), instead
of including purchased capacity costs in base rates. The Commission, however, rejected the PPCR
request in a Supplemental Preliminary Order on the grounds that the Commission already had a
then-pending rulemaking effort underway to determine the structure of such a rider for all generating
utilities. 99
In this docket, Staff, OPUC, and State Agencies argue that ETI should not be entitled to
recover any rate case expenses it incurred in attempting to secure a PPCR because it was too
100
speculative in light of the pending rulemaking effort.
ETI responds by contending that the mere fact that there was a rulemaking effort underway
with respect to PPCRs did not mean that ETI was somehow precluded from seeking a PPCR through
its application. Moreover, ETI notes that, in briefing during Docket 39896, Staff, State Agencies,
98
Tr. at 45-46.
99
Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred
Accounting Treatment, Docket 39896, Supplemental Preliminary Order at 2 (Jan. 9, 2012).
100
OPUC Init. Br. at 10; Stafflnit. Br. at 14 and Reply Br. at 8-9; State Agencies Reply Br. at 17.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 28
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and TIEC all took the position that there was no legal impediment to ETI's seeking a PPCR in the
rate case. 101
The ALJ agrees with ETI and does not recommend any disallowances in relation to the PPCR
request. The fact that there was a pending proposed rule at the time ETI asked for the rider should
not be viewed as precluding ETI' s request. Indeed, the very uncertainty inherent in the rulemaking
process suggested that the accepted practices with regard to purchased capacity costs were in a state
of flux and, therefore, it was reasonable for ETI to pursue the rider.
3. Proportional Reduction
In addition to the above challenges to specific items of expense incurred by ETI, a number of
parties raised more generic concerns about the company's rate case expenses. State Agencies
expressed concern that, as a general matter, rate case expenses in cases before the Commission
appear to be "getting out of hand." 102 Staff "firmly agrees" with this concern. 103 State Agencies
worry that utilities have no incentive to minimize the number of rate case proceedings or the
efficiency of rate case presentation because they assume their costs will simply be passed on to
ratepayers. 104 State Agencies urge the Commission to allocate rate case expenses in such a way that
incentivizes utilities to more productively and efficiently use their time in rate cases. 105 OPUC
agrees that the standard for evaluating the amount of rate cases expenses to be reimbursed ought to
be structured so as to give a utility pause before deciding to pursue overly aggressive or novel
arguments. 106
101
ETI Reply Br. at 16-17.
102
State Agencies Init. Br. at 1-2.
103
Staff Reply Br. at 13.
104
State Agencies Init. Br. at 1-2.
105
State Agencies Init. Br. at 5.
106
OPUC Init. Br. at 8.
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Along these same lines, Staff and OPUC expressed concern about the frequency of ETI rate
cases over recent years. Docket 39896 was the third ETI rate case in four years. Each case resulted
in a rate increase and an obligation for the ratepayers to pay ETI's rate case expenses. 107 Staff and
OPUC also expressed concern about the overall size of the rate case expenses in relation to the
outcome of the underlying rate case. Total rate case expenses ($8.8 million) equal roughly one-third
of the total approved rate increase ($27. 7 million). 108 Staff, State Agencies, and OPUC all expressed
the concern that ETI did not provide good stewardship in incurring rate case expenses. 109
In order to address these concerns, the parties have suggested a number of methodologies for
reducing the rate case expenses.
• The 50/50 approach. State Agencies advocate two approaches for reducing the level
of recovery of rate case expenses. State Agencies' primary recommendation is that
ratepayers be charged for only 50% of total rate case expenses. State Agencies argue
that this approach would recognize that shareholders, who reap benefits from a rate
increase, ought to also share in the cost of obtaining that rate increase. 110
• The Results-Obtained Approach. Alternatively, State Agencies advocate allowing
ETI to recover only 26.4% of its rate case expenses, which is the ratio between the
rate increase obtained in Docket 39896 ($27.7 million) and the increase sought by
ETI ($104.8 million). In other words, because ETI obtained only 26.4% of the rate
increase it sought, State Agencies contend that ETI similarly ought to be reimbursed
for only 26.4% of its rate case expenses. 111 OPUC also advocates this approach. 112
• The Issue-Specific Reduction Approach. Alternatively, OPUC and Staff advocate
an approach whereby ETI's recovery of rate case expenses is reduced by the ratio
between the amounts unsuccessfully sought by ETI for financially-based incentive
payments and transmission equalization payments and the rate increase sought by
ETI. ETI unsuccessfully sought financially-based incentive payments of $6.5
107
Stafflnit. Br. at 3; OPUC Init. Br. at 2-3, 7-8.
108
Stafflnit. Br. at 4; OPUC Init. Br. at 7.
109
See, e.g., Staff Reply Br. at 13.
110
State Agencies Init. Br. at 3,
111
State Agencies Init. Br. at 3, 22.
112
OPUC Init. Br. at 11.
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million, and transmission equalization payments of $9 million, for a total of
$15.5 million. ETI sought a total rate increase of $104.8 million. Under this
approach, $15.5 million would be divided by $104.8 million to arrive at a reduction
factor of 14.8%. Thus, ETI's rate case expenses would be reduced by 14.8%. 113
Not surprisingly, ETI vigorously opposes all of these approaches.
The ALJ agrees with the general concerns raised by Staff, State Agencies, and OPUC, and
believes that a substantial cut to ETI' s rate case expenses is warranted. Before evaluating the merits
of the various approaches, however, it is helpful to revisit the applicable law relative to rate case
expenses.
As noted previously, pursuant to PURA Section 36.061 (b ), the Commission "may" allow a
utility to recover its "reasonable costs of participating in a [ratemaking proceeding] not to exceed the
amount approved" by the Commission. This verbiage indicates that the Commission can approve
some amount that is less than the reasonable costs. Section 36.061(b) vests the Commission with
"broad discretion" to determine the amount ofrate cases expenses that should be recovered, 114 and its
determination can be set aside only if it acts without reference to guiding rules or principles. 115
There is precedent, albeit from a different agency, suggesting that it is within the agency's discretion
to find overall rate case expenses to be unreasonable even if the underlying individual cost items are
found to be reasonable.11 6 Because Section 36.06l(b) states that rate case expenses "may" be
recovered, OPUC contends (and the ALJ agrees) that the Commission is not required to grant
113
OPUC Init. Br. at 12; Staff Reply Br. at 3. OPUC identifies the reduction factor as 14.5%. However, the ALJ
believes this is in error. OPUC witness Benedict testified that the financially-based incentive payments were $6.2 million
and the transmission equalization payments were $9 million, for a total of $15.2 million. Tr. at 85-86. By dividing
$15.2 million by $104.8 million, one arrives at a reduction factor of 14.5%. However, the Commission disallowed
$6.2 million in financially-based incentive compensation, plus $336,000 ofETI's capitalized financially-based incentive
compensation, for a total of$6.5 million in disallowances related to financially-based incentive payments. Application of
Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred Accounting Treatment,
Docket 39896, Order on Rehearing at 17-18, 24-25 (November 1, 2012).
114
City ofEl Paso v. Public Util. Comm 'n, 916 S.W.2d 515, 522 (Tex. App.-Austin 1995, writ dism'd by agr.).
115
City ofAmarillo v. Railroad Comm 'n of Texas, 894 S.W.2d 491, 495 (Tex. App.-Austin 1995, writ den.).
116
City ofPort Neches v. Railroad Comm'n of Texas, 212 S.W.3d 565, 581 (Tex. App.-Austin 2006, no pet.)
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE31
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recovery of every reasonable expense and can take into account other considerations. As explained
by OPUC, "[w ]ithout this discretion, rate case expense proceedings would be rendered into mere
accounting exercises. " 117 A number of factors--such as the time and labor required; the nature of the
case; the size of the interest at stake; and the benefits to the client--have been deemed relevant to
determining the reasonableness of rate case expenses. 118 Moreover, the parties agree that
Rule 1.04(b) of the Texas Disciplinary Rules of Professional Conduct also provides a number of
factors that can be considered when determining reasonableness ofrate case expenses. 119
With these basic parameters in mind, the ALJ turns to evaluating the three approaches
outlined above. The ALJ begins by rejecting the 50/50 Approach. ETI and Staff argue that the
approach is contrary to Commission precedent. 120 The ALJ agrees. Given that there are clear
Commission precedents rejecting this approach, the ALJ recommends that it be rejected here.
The ALJ also recommends rejection of the Results-Obtained Approach, while acknowledging
that it has some strong arguments in its favor. ETI argues that the approach is counter to
Commission precedent. 121 However, according to Staff, the approach has been neither adopted nor
rejected by the Commission. In other words, it is an issue of first impression. 122 OPUC and State
Agencies support the use of this approach. It is unclear whether Staff explicitly supports this
approach. However, Staff describes it as an "appealing" methodology "because it would provide a
utility an incentive not to overreach in its rate increase request." 123 Moreover, Staff argues that the
methodology is akin to the performance-based standards regarding generation plant performance that
117
OPUC Init. Br. at 11.
118
City ofEl Paso, 916 S.W.2d at 522.
119
ETI Ex. 8 (Morris Direct) at 18-19.
120
Staff Init. Br. at 1O; ETI Init. Br. at 19-20.
121
ETI Init. Br. at 14.
122
Stafflnit. Br. at 10.
123
Stafflnit. Br. at 12.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE32
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the Commission has approved in the past. For these reasons, Staff concludes that the Commission
124
has the legal authority to apply the Results-Obtained Approach in this case.
ETI complains, however, that it is a punitive and hindsight-driven approach to cost recovery,
rather than basing cost recovery on whether a utility acted reasonably at the time it incurred such
costs. 125 This is the primary reason why the ALJ recommends against the Results-Obtained
Approach. Because it is an issue of first impression, ETI had no prior notice that its rate case
expenses might be subject to such a standard. The ALJ simply believes it would be unacceptably
draconian to slash ETI's rate case expenses by 73.6% based upon a standard that ETI could not have
known, beforehand, would be applied to it.
The ALJ recommends adoption of the Issue-Specific Reduction Approach in this case. Staff,
OPUC, and State Agencies all support its use. ETI argues that use of the approach is
unprecedented. 126 Staff counters (and the ALJ agrees) that, far from being unprecedented, the
approach is entirely consistent with Commission precedent because the disallowance is a result of
specific, unreasonable actions by ETI. 127
ETI argues that the Issue-Specific Reduction Approach is improper because there is no
evidence that the 14.8% reduction equals the amount of expenses it incurred pursuing financially-
based incentive costs and transmission equalization payments. 128 Staff counters (and the ALJ agrees)
that ETI bore the burden of proving its reasonable expenses, and that burden necessarily requires that
it separate out any unreasonable expenses. Having failed to do so with respect to financially-based
124
Staff Init. Br. at 11.
125
ETI Init. Br. at 17.
126
ETI Init. Br. at 19.
127
Stafflnit. Br. at 14.
128
ETI Init. Br. at 18.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE33
PUC DOCKET NO. 40295
incentives and transmission equalization payments, it is reasonable for the Commission to use the
Issue-Specific Reduction Approach as a proxy for calculating those expenses. 129
There is also a point of disagreement as to the proper application of the Issue-Specific
Reduction Approach. ETI argues that the proponents of the approach are using the wrong
denominator in its formulation. Rather than dividing $15.5 million by $104.8 million (the size of the
rate increase sought by ETI), ETI asserts that $15.5 million ought to be divided by $2.1 billion (the
size of all ofETI's costs). ETI explains that, in Docket 39896, it was obligated to prove all of its
costs, not just the amount of the increase it sought. Under such a formula, the reduction factor would
be less than 1%. 130 As pointed out by Staff and OPUC, 131 ETI's reasoning is flawed. The entire
purpose of this proceeding was for ETI to obtain a rate increase, not to preserve its preexisting rates.
Indeed, the petition is styled "Application ... for Authority to Change Rates .... " 132 There would
have been no need for a rate case if ETI merely sought approval of the same level of revenue
approved in the last rate case. Because a revenue increase was the driving factor for this case, the
amount of revenue increase requested is the appropriate benchmark to compare against
disallowances.
Having concluded that the Issue-Specific Reduction Approach should be utilized in this case,
the ALJ now discusses the application of the formula to the rate case expenses. As explained in the
second paragraph of Section IV.C of this PFD, in order to take into account the $75,800 of estimated
expenses for Cities, the ALJ recommends increasing ETI's overall rate case expenses request to
$8,828,345. From that amount, the ALJ subtracts the specific disallowances discussed in
Section IV.C.l of this PFD:
129
Stafflnit. Br. at 15.
130
ETI Init. Br. at 18.
131
Staff Reply Br. at 12; OPUC Reply Br. at 4-5.
132
Emphasis added.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE34
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• $207,683 for depreciation;
• $281 meals over $25;
• $10 for clothing;
• $40 for laundry service; and
• $480 lodging .
This leaves a balance of $8,619,851. When that balance is reduced by 14.8%, the remainder is
$7,344,113. It is this amount of rate case expenses that the ALJ recommends ETI be allowed to
recover.
D. Recovery Method
1. Rate Case Expense Allocation and the Recovery Mechanism
ETI proposes to allocate the approved rate case expenses among its retail classes using a
revenue allocator based upon ETI's proforma Test Year revenues. Staff proposes, instead, that the
allocation be based on each retail rate classes' s revenue requirement as approved by the Commission.
Staff argues that its approach would be more consistent with recent Commission precedent. 133
Staffs specific recommendation is as follows:
[T]hat ETI' s Schedule RCE-2 rates be set in the compliance phase of this
proceeding by multiplying the approved total amount by Staffs recommended
class allocator and dividing the resulting class share both by ETI's proposed
three-year amortization period and also by ETI's proposed class billing
determinants. 134
133
Stafflnit. Br. at 17; Staff Ex. 1 (Murphy Direct) at 4-5.
134
Staff Ex. 1 (Murphy Direct) at 5.
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PUC DOCKET NO. 40295
Staff further recommends that ETI be required to track its collections on Rider RCE and
terminate billing in the month in which the approved amount has been billed. 135 ETI does not object
to Staffs approach to allocation, so long as the Commission's final order includes standard language
allowing the company to seek recovery of any additional rate case expenses incurred after September
30, 2012, in its subsequent rate case. 136 Staff does not object to this request by ETI. 137 No other
party objects to this approach, and the ALJ can find no reason to do so either.
2. ETl's Request to Earn a Return on the Unpaid Balance of Rate Case
Expenses
ETI asks that it be allowed to recover its rate case expenses over three years, and that it be
allowed to recover a return on the unpaid balance of the expenses during that time. 138 No party
objects to the three-year duration, but Staff opposes ETI's request to earn interest on its rate case
expenses, contending that the Commission has consistently refused the recovery of a return on
unamortized rate case expenses. 139 State Agencies agree with Staff. 140
ETI responds by arguing that it is simply seeking to recover a necessary component of a cost
that is amortized over a period of time. According to ETI, the request for a return on the unpaid
balance merely represents the time value of money and the cost of the company's lost opportunity to
use the funds elsewhere. 141 ETI cites to several Commission precedents in which a utility was
allowed to recover interest on various cost-of-service items, including Docket 39896, in which ETI
was allowed to earn a return on the unamortized balance of its Hurricane Rita Regulatory Asset over
135
Staff Ex. 1 (Murphy Direct) at 5.
136
ETI Ex. 7 (Considine Rebuttal) at 5.
137
Stafflnit. Br. at 18.
138
ETI Ex. 5 (Considine Rebuttal) at 7.
139
Staffs Init. Br., pp. 5-6.
140
State Agencies' Reply Br., pp. 3, 16.
141
ETI's Reply Br., pp. 23-24.
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PUC DOCKET NO. 40295
five years. 142 ETI does not, however, cite to any Commission precedent specifically authorizing a
return on unpaid rate case expenses.
Staff has the better argument. In Docket 30706, CenterPoint Energy Houston Electric
(CenterPoint) sought to recover its rate case expenses over three years with a return on the unpaid
balance. The Commission rejected CenterPoint's request for a return, explicitly noting its "practice
of not permitting utilities to receive interest on unpaid rate-case expenses." 143 Consistent with this
clear Commission precedent, the ALJ recommends that ETI's request to recover a return on the
unpaid balance of its rate case expenses during the three-year payoff period be denied.
V. CONCLUSION
The ALJ recommends that the Commission implement the findings of the ALJ set forth in the
discussion above by adopting the following proposed findings of fact and conclusions oflaw in the
Commission's final order.
VI. PROPOSED FINDINGS OF FACT, CONCLUSIONS OF LAW, AND
ORDERING PARAGRAPHS
A. Findings of Fact
1. Entergy Texas, Inc. (ETI or the Company) is an investor-owned electric utility with a retail
service area located in southeastern Texas.
2. On November 28, 2011, ETI filed an application (the ETI Application) requesting, among
other things, approval of a proposed increase in annual base rate revenues of approximately
$111.8 million over adjusted test year revenues, and a new rider for recovery of costs related
to purchased power capacity.
142
Docket 39896, Proposal for Decision at 17-23; see also, Petition ofTexas-New Mexico Power Company for Approval
ofRegulatory Asset Treatment ofExpenses Related to System Benefit Fund Payments, Docket No. 26942, Order at 4
(Findings of Fact 26-29)(Aug. 22, 2003).
143
Application ofCenterPoint Energy Houston Electric, LLCfor a Competition Transition Charge, Docket No. 30706,
Order at 32 (Jul. 14, 2005).
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PUC DOCKET NO. 40295
3. On November 29, 2011, the Public Utility Commission of Texas (Commission or PUC)
referred the ETI Application to the State Office of Administrative Hearings (SOAR) for a
hearing and the matter was assigned docket number 39896 (Docket 39896).
4. On April 4, 2012, in Docket 39896, the ALJs issued SOAR Order No. 13 severing rate case
expense issues into a new docket, the case at issue here, Application ofEntergy Texas, Inc.
for Rate Case Expenses Severed from PUC Docket No. 39896, Docket No. 40295.
5. The hearing on the merits in Docket 39896 was held in April-May 2012.
6. The Proposal for Decision (PFD) in Docket 39896 was issued July 6, 2012.
7. The Commission issued its final order in Docket 39896 on November 2, 2012.
8. The hearing on the merits in the present docket, Docket 40295, was held on November 28,
2012. The record closed on December 21, 2012, following the filing of post-hearing briefs.
9. The following parties were granted intervenor status in this docket: Office of Public Utility
Counsel (OPUC); the cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Dayton,
Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange,
Pine Forest, Rose City, Pinehurst, Port Arthur, Port Neches, Shenandoah, Silsbee, Sour Lake,
Splendora, Vidor, and West Orange (Cities); State Agencies (State Agencies); and Texas
Industrial Energy Consumers (TIEC). The staff (Staff) of the Commission was also a
participant in this docket.
10. In Docket 39896, ETI adjusted its request for a proposed increase in annual base rate
revenues to approximately $104.8 million over adjusted Test Year revenues.
11. In the PFD in Docket 39896, the ALJs recommended an overall rate increase of
$28.3 million.
12. In its final order in Docket 39896, the Commission largely followed the recommendations
contained in the PFD, but reduced ETI's overall rate increase to $27.7 million.
13. In this docket, ETI seeks to recover $8.8 million in rate case expenses associated with
Docket 39896.
14. Of that total, $7 .6 million was incurred by ETI and $1.2 million was incurred by Cities.
15. Cities proved that, through August 31, 2012, they reasonably incurred rate case expenses of
$1,125,768.61 in Docket 39896 and this docket.
16. Cities reasonably estimated that their total rate case expenses in Docket 39896 and this
docket after August 31, 2012 will total $75,800.
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PUC DOCKET NO. 40295
17. The amount of rate case expenses sought by ETI ($8.8 million) is high, both in absolute
terms, and in relation to the rate increase ultimately obtained by ETI in Docket 39896
($27.7 million).
18. Rate case expenses for ETI in the amount of $7,344,113 are reasonable and necessary and
should be allowed as a cost or expense by the Company. This amount is calculated by
reducing the requested amount by the amounts listed and for the reasons stated below:
a. $207 ,683 in depreciation of office equipment owned by Entergy Services, Inc. (ESI)
(an affiliated company of ETI) and used by ESI employees for their work in
Docket 39896 is not reasonable and is properly disallowed.
b. $281 for meals over $25 was erroneously sought by ETI, is not reasonable, and is
properly disallowed.
c. $10 for clothing purchased by an attorney for ETI is not reasonable and is properly
disallowed.
d. $40 for laundry charges by an attorney for ETI is not reasonable and is properly
disallowed.
e. $480 for a lodging charge unsupported by receipts is not reasonable and is properly
disallowed.
f. $1,27 5, 738 attributable to unreasonable and overly aggressive arguments pursued by
ETI in Docket 39896 related to financially-based incentive compensation and
transmission equalization payments is properly disallowed.
B. Conclusions of Law
1. ETI is a "public utility'' as that term is defined in the Public Utility Regulatory Act (PURA)
§ 11.004(1) and an "electric utility" as that term is defined in PURA § 31.002(6).
2. The Commission exercises regulatory authority over ETI and jurisdiction over the subject
matter of this application pursuant to PURA §§ 32.001, 32.101, 33.002, 33.051, and
36.101-111.
3. SOAR has jurisdiction over matters related to the conduct of the hearing and the preparation
of a proposal for decision in this docket, pursuant to PURA § 14.053 and Tex. Gov't Code
§ 2003.049.
4. This docket was processed in accordance with the requirements of PURA and the Texas
Administrative Procedure Act, Tex. Gov't Code Chapter 2001.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE39
PUC DOCKET NO. 40295
5. Pursuant to PURA § 33.051, the Commission has jurisdiction over an appeal from a
municipality's rate proceeding.
6. Cities bore the burden to prove that the rate case expenses they incurred were reasonable.
PURA§ 33.023.
7. Cities are entitled to reimbursement by ETI for:
a. rate case expenses of $1,125,768.61 incurred in Docket 39896 and this docket
through August 31, 2012; and
b. actual expenses incurred by Cities in Docket 39896 and this docket after August 31,
2012, including any appeals, up to a maximum possible amount of$75,800.
8. ETI bore the burden of proving that the rate case expenses it incurred in Docket 39896 were
reasonable. PURA§ 36.06l(b).
9. ETI proved the reasonableness of its rate case expenses in the amount of $7,344.113, and
is entitled to claim that amount as a cost.
C. Proposed Ordering Paragraphs
In accordance with these findings of fact and conclusions oflaw, the Commission issues the
following orders:
1. The Proposal for Decision prepared by the SOAH ALJ s is adopted to the extent consistent
with this Order.
2. All other motions, requests for entry of specific findings of fact and conclusions oflaw, and
any other requests for general or specific relief, if not expressly granted, are denied.
3. Cities' and ETI's requests to recover rate case expenses are granted to the extent consistent
with this Order.
SIGNED February 19, 2013.
~B~TER
ADMINISTRATIVE LAW JUDGE
STATE OFFICE OF ADMINISTRATIVE HEARINGS
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PUC DOCKET NO. 40443 : V> , P/j
SOAH DOCKET NO. XXX-XX-XXXX '"''--:c ll:.',." . /:Jg
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APPLICATION OF SOUTHWESTERN § PUBLIC UTILITY COMMISSION
ELECTRIC POWER COMPANY FOR §
AUTHORITY TO CHANGE RATES § OF TEXAS
AND RECONCILE FUEL COSTS §
ORDER ON REHEARING
This Order addresses the application filed on July 27, 2012 by Southwestern Electric
Power Company (SWEPCO) for authority to change its rates and reconcile its fuel costs. The
primary contested issue regarding the proposed increase involves the portion of SWEPCO's
share of the costs of the Turk coal plant in Hempstead, Arkansas that are allocated to Texas.
SWEPCO's application sought a total-company revenue requirement of $1.033 billion,
exclusive of fuel revenues. The requested Texas retail revenue requirement exclusive of fuel
revenues was $329 million, which reflected an increase in annual Texas retail revenues of $83.37
million over its adjusted test-year revenues. 1 The increase primarily consists of the inclusion of
the newly constructed Turk coal plant and Stall gas plant. For the fuel reconciliation period from
April 1, 2009 through December 31, 2011, SWEPCO sought to reconcile a cumulative fuel
under-recovery balance of $3,936,492, including interest, and proposed no surcharge.
SWEPCO's reconciliation included proposed revisions to Dolet Hills Lignite Company
benchmark price.
The State Office of Administrative Hearings' administrative law judges (ALJs) issued a
proposal for decision on May 20, 2013. The ALJs' recommended approval of the application,
with certain adjustments. Regarding the Turk plant, the ALJs recommended the disallowance of
all Turk costs over approximately $934 million as being imprudently incurred in continuing
construction after June 2010. The ALJs further recommended that approximately $260 million
be allowed for the estimated costs to retrofit the Welsh Unit 2 coal plant that SWEPCO should
have undertaken instead of completing the Turk plant. However, the ALJs recommended in the
1
Rebuttal Testimony of Jennifer L. Jackson, SWEPCO Ex. 88, JLJ-1 R at 2.
00000001
PUC Docket No. 40443 Order on Rehearing Page 13 of 59
SOAR Docket No. XXX-XX-XXXX
J. Fuel Reconciliation
SWEPCO requested a good cause exception to recover consumables and allowances as
fuel on a going-forward basis. The Commission is persuaded by the arguments of Commission
Staff regarding this issue and rejects the AUs' recommendation to disallow the request.
Accordingly, finding of fact 322 is modified and conclusion of law 47 is modified.
K. Miscellaneous
Corrections to the findings of fact and conclusions of law are necessary to appropriately
reflect the Commission's determinations regarding the following issues.
First, the findings regarding the unique aspects of SWEPCO' s overall compensation
program do not accurately reflect the AUs' recommendation that the Commission adopts.
Therefore, the Commission modifies finding of fact 147 to clarify that the portion of SWEPCO's
annual and long-term incentive payments that are capitalized and that are financially-based are
excluded from SWEPCO's rate base because the benefits of such payments inure most
immediately and predominantly to SWEPCO's shareholders, rather than its electric customers.
Also, an error in finding of fact 220 is corrected to reflect that, of SWEPCO's annual incentive
compensation of $10,728,117, $3,523,732 is disallowed as financial goals. These same findings
are clarified to reflect that the part of the long-term incentive compensation program that
includes performance units is disallowed as being based on financial measures, and the part that
includes restricted stock units is allowed - $3,130,757 is disallowed from the $5,175,829 in
long-term incentive compensation.
Further, in accordance with other corrections noted by the AUs in their July 2, 2013
letter, the amount of credit line fees is corrected in finding of fact 186. The Commission also
modified finding of fact 242 to reflect its clarification that the test-year expenses for injuries and
damages exceeds the average of the expense in the three previous years, and the amount should
be disallowed completely and not amortized.
Also, the ordering provisions reflect the AUs clarification that SWEPCO should provide
a calculation in its compliance filing to include 12 months' weather normalized residential sales
based on a 10-year normal to reflect the AUs' recommendation adopted by the Commission.
000000013
PUC Docket No. 40443 Order on Rehearing Page38 of59
SOAH Docket No. XXX-XX-XXXX
General Plant
207. Asbestos removal in 1996 and the sale of an office building in 2004 should be removed
from the removal cost and salvage data for FERC Account 390-General Plant for
1984-2011 upon which the net salvage rate for the account should be based. The net
salvage rate of negative 3% resulting from this modification is reasonable and reduces
SWEPCO's initially requested depreciation expense by $97,594 on a total Company basis
and $32,938 on a Texas jurisdictional basis.
Depreciation Reserve
208. The use of the remaining life depreciation method to recover differences between
theoretical and actual depreciation reserves is the most appropriate method.
209. It is reasonable for SWEPCO to calculate depreciation reserve allocations on a
straight-line basis over the remaining, expected useful life of the item or facility.
Payroll
210. SWEPCO made two adjustments to its test-year payroll. The Company updated payroll
costs by annualizing the base payroll to the salary rates in effect at the end of the test year
and by recognizing the effect of the merit and general increases that were awarded in
2012.
211. Because these payroll increases were awarded in 2012, they represent appropriate known
and measurable adjustments to test-year expenses.
212. SWEPCO double-counted the Turk plant payroll by including Turk plant employees in
the pro Jonna payroll O&M as well as in the post-test-year adjustment.
213. SWEPCO's labor costs should be disallowed by the sum of $197,688 and $50,932, or
$248,620.
Incentive Compensation
214. SWEPCO sought to recover in rate base a total amount of $10,728,117 paid as annual
incentive compensation to its employees and $5,175,829 paid for long-term incentive
compensation.
000000038
PUC Docket No. 40443 Order on Rehearing Page39 of 59
SOAH Docket No. XXX-XX-XXXX
215. The PUC permits a utility to recover in its base rate incentives that are designed to
achieve "operational measures" and that are necessary and reasonable to provide utility
services, but not incentive programs that are designed to achieve "financial measures."
216. Operational measures are those designed to encourage a utility's employees to meet goals
and standards relating to the efficient operation of the utility, a benefit to shareholders
and ratepayers alike.
217. Financial measures are those designed to encourage employees to achieve financial
targets, a benefit primarily to shareholders.
218. SWEPCO's "Regulatory," "Strategic," and "Margin Generating" annual incentive goals
relate to financial measures.
219. SWEPCO's long term incentive awards in the form of performance units relate to
financial measures.
220. Of SWEPCO's annual incentive compensation of $10,728,117, $3,523,732 should be
disallowed as financial goals. Of SWEPCO's long-term compensation, all but
$2,045,072 of the total should be disallowed as financial goals.
Executive Perquisites
221. The $16,350 related to executive perquisites should not be included in rates because they
provide no benefit to ratepayers and are not reasonable or necessary for the provision of
electric service.
Relocation
222. SWEPCO's proposed relocation expense, in the amount of $574,588, is reasonable and
necessary.
Pensions
223. It is reasonable to base pension expense in SWEPCO's cost of service upon the cost of
$8,306,420 on a total Company basis calculated in the 2012 actuarial report prepared in
accordance with FAS 87.
000000039
,
PROCEEDING TO CONSIDER RATE §
CASE EXPENSES SEVERED FROM §
DOCKET NO. 28840 (APPLICATION OF §
AEPTEXASCENTRALCOMPANYFOR §
AUTHORITY TO CHANGE RATES) §
§
ORDER
This Order addresses the recoverable rate-case expenses of AEP Texas Central Company
(AEP Central) and of Cities 1 in connection with their participation in Docket No. 28840.2 As set
forth in this Order, the Public Utility Commission of Texas (Commission) determines that AEP
Central's recoverable rate case expenses through June 2005 are $2,938,130 and that Cities'
recoverable rate case expenses are $1,350,149. As discussed herein, the Cities' expenses relating to
witness Sarah Goodfriend have been reduced by one-half as recommended by the State Office of
Administrative Hearings (SOAH) Administrative Law Judges in their Proposal for Decision (PFD)
in Docket No. 28840. 3 This Order finds that $4,288,429 in rate-case expenses incurred by AEP
Central and Cities is reasonable and necessary and authorizes AEP Central to implement a
surcharge over three years to recover this amount.
I. Procedural History
On November 3, 2003, AEP Central filed an application seeking a change in its rates. This
application was assigned Docket No. 28840, and the Commission referred the case to SOAH on
November 4, 2003. SOAH issued its initial PFD in Docket No. 28840 on July 1, 2004, which
contained certain findings on rate case expenses. In July and August 2004, the Commission issued
two orders on remand in Docket No 28840 directing SOAH to consider further and provide further
evaluation of certain specified issues, none of which involved rate case expenses. On November
1
Alice, Aransas Pass, Carrizo Springs, Dilley, Donna, Eagle Lake, Freer, Ganado, George West, Ingleside,
Kingsville, LaFeria, Laguna Vista, La Joya, Leakey, Los Fresnos, Lyford, Lytle, McAllen, Mercedes, Mission,
Nordheim, Odem, Pharr, Port Aransas, Portland, Port Lavaca, Poteet, Rancho Viejo, Refugio, Rio Hondo, Runge, San
Benito, San Juan, Sinton, Uvalde, and Weslaco (collectively, Cities).
2
Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 28840, Order (Aug.
15, 2005).
3
Docket No. 28840, Proposal for Decision at 121-127, 205 (FOF 210-216), 209 (FOF 256) (Jul. l, 2004).
DOCKET NO. 31433 ORDER PAGE2
16, 2004, SOAR issued its Remand PFD. In addition, the Commission held hearings on certain
matters relating to merger savings and affiliated expenses on March 3, 4, and 7. The Commission
issued its final order in Docket No. 28840 on August 15, 2005. In that order, the Commission
severed the determination of the reasonableness and necessity of rate case expenses to this
proceeding, Docket No. 31433. 4 While rate-case expenses were not addressed on the remand
SOAR hearing and the Commission-held hearing, Cities and AEP incurred additional expenses as a
result of these hearings, and submitted updated information on these additional expenses. Based on
the submission, the Commission decided to sever the determination on rate-case expenses to
examine this additional evidence. 5
By Order No. 1 in this proceeding, AEP Central and Cities were directed to file detailed
supporting documentation of their requested rate case expenses. On September 9, 2005, AEP
Central and Cities filed such supporting documentation. On September 16 and October 10, 2005,
AEP Central made supplemental filings that furnished additional supporting documentation with
respect to certain of its requested expenses.
On October 14, 2005, the parties filed statements of position and on October 28, 2005, AEP
Central filed its Motion for Ruling on Disputed Issue and Conditional Request for a Hearing. On
December 12, 2005, the presiding officer issued Order No. 4, which requested clarification
regarding contested issues. On December 22, 2005, the parties filed responses to Order No. 4.
The parties' filings established that there are no contested factual issues in Docket
No. 31433 that have not been fully litigated in Docket No. 28840. To the extent AEP Central had
previously conditionally requested a hearing, that request was withdrawn by AEP Central' s
December 22, 2005 filing. The sole disputed issue is the recoverability of one-half of Cities' witness
Sarah Goodfriend's expenses, which the SOAH ALJs had recommended be disallowed in their PFD
in Docket No. 28840 issued on July 1, 2004. Since there are no contested factual issues that have
not already been fully litigated, an evidentiary hearing on the merits is not necessary or appropriate.
The disposition of the sole contested issue is discussed in the subsequent section of this Order.
4
Docket No. 28840, Order at 60 (Ordering 1f 5) (Aug. 15, 2005).
5
Open Meeting Tr. at 54-62 (July 29, 2005).
DOCKET NO. 31433 ORDER PAGE3
II. Recoverability of One-Half of Dr. Goodfriend's Expenses
In Docket No. 28840, AEP Central submitted testimony challenging the quality of a survey
that fonned the basis of testimony submitted by Cities witness, Dr. Sarah Goodfriend. 6 Following a
full evidentiary hearing and briefmg on this and other issues, the SOAH ALJs recommended that
one-half of Dr. Goodfriend's expenses be disallowed because they found that the methodology of
the survey she conducted was ''seriously flawed." 7
In severing the issue of rate case expenses from Docket No. 28840 to this proceeding, the
Commission intended that the entire evidentiary record in Docket No. 28840 on rate case expenses
as well as the Commission's initial decisions be carried over to this case. Thus, the evidentiary
record on the quality of Dr. Goodfriend's work underlying her testimony in Docket No. 28840 and
the SOAH ALJs' findings regarding the recoverability of one-half of her expenses are before the
Commission for decision in this proceeding. The purpose of the severance, however, was to
evaluate the detailed supporting documentation on updated rate-case expenses submitted by AEP
Central and Cities.8 This proceeding was not initiated as a forum for Cities to re-litigate Dr.
Goodfriend's expenses.
The Commission had previously found that the ALJs correctly detennined that one-half of
Dr. Goodfriend's expenses should be disallowed9 because the survey she conducted "was seriously
flawed and that conclusions drawn from the data cannot be reasonably supported under current legal
10
standards." The Commission reaffinns this determination, and therefore, the Commission adopts
the SOAH ALJs' finding that one-half of Dr. Goodfriend's expenses should be disallowed. In
addition, as there are no other outstanding contested issues related to the rate-case expense
infonnation submitted in Docket No. 28840 or the additional rate-case expense infonnation
6
See Docket No. 28840, Proposal for Decision at 121-127, 205 (FOF 212) (Jul. 1, 2004).
7
Id at 125.
8
See Open Meeting Tr. at 62 (Jul. 29, 2005).
9
Open Meeting Tr. at 196-198 (January 13, 2005).
10
Docket No. 28840, Proposal for Decision at 125 (Jul. I, 2004).
DOCKET NO. 31433 ORDER PAGE4
submitted in this docket, the Commission finds that the rate-case expenses of $2,938,130 for AEP
Central and $1,350,299 for Cities are reasonable and necessary.
III. The SOAH ALJs' Findings and Conclusions in Docket No. 28840
In the PFD issued on July 1, 2004, in Docket No. 28840, the SOAH ALJs included Finding
of Fact Nos. 210 through 216 and Conclusion of Law No. 58 addressing rate case expenses. The
SOAH ALJs' findings were issued prior to the updating by AEP Central and Cities of their rate case
expenses in their filings described in Finding of Fact No. 15. Thus, in order to reflect the updated
factual evidence filed in Docket No. 31433 and certain other corrections described below, the
Commission modifies the SOAH ALJs' Finding of Fact Nos. 210 through 216 as follows.
Finding of Fact Nos. 22 through 25 of this Order modify the SOAH ALJs' Finding of Fact
No. 210 to reflect the updated amounts of rate case expenses found reasonable and necessary for
AEP Central after reflecting the disallowance recommended by Staff. Finding of Fact No. 27 of
this Order modifies the SOAH ALJs' Finding of Fact No. 211 to reflect the updated amount of
Cities' requested rate case expenses. Finding of Fact Nos. 28 and 29 of this Order modify the
SOAH ALJs' Finding of Fact No. 212 to reflect the updating of Dr. Goodfriend's portion of Cities'
requested rate case expenses. Finding of Fact Nos. 31and32 of this Order adopt the SOAH ALJs'
Finding of Fact Nos. 214 and 215. Finding of Fact No. 33 of this Order modifies the SOAH ALJs'
Finding of Fact No. 216 to reflect the amounts found reasonable and necessary by the Commission
based on the updated information in this proceeding and corrects it to reflect that the rate case
expenses will be collected through a three-year surcharge and not through cost of service. Finding
of Fact No. 34 of this Order supplements the SOAH ALJs' Finding of Fact No. 256 to reflect the
updated amounts for AEP Central's and Cities' rate case expenses found reasonable and necessary
by this Order. Finding of Fact No. 35 reflects the Commission's policy decision, in accordance
with its decision in Docket No. 30706, 11 that AEP Central not be permitted to recover estimated
appeal costs in this proceeding, but that AEP Central be afforded the opportunity to recover in its
next rate case any reasonable and necessary expenses for Docket Nos. 28840 and 31433 that it
11
Application of CenterPoint Energy Houston Electric, LLC for a Competition Transition Charge, Docket No.
30706, Order at 28-29, 47 (COL 28) (Jul. 14, 2005).
DOCKET NO. 31433 ORDER PAGES
subsequently incurs that exceed the amounts found reasonable and necessary by this Order. Finally,
Conclusion of Law No. 6 in this Order incorporates the SOAH ALJs' Conclusion of Law No. 58.
The Commission adopts the following findings of fact and conclusions of law:
IV. Findings of Fact
A. Background and Procedural Matters
1. AEP Central is an electric utility providing transmission and distribution (T&D) services in
a 44,000 square-mile area of South Texas that includes the portion of Texas from just south
of San Antonio to the Mexican border and from Bay City west to Eagle Pass. AEP Central' s
service area is located within the Electric Reliability Council of Texas (ERCOT).
2. On November 3, 2003, AEP Central filed an application with the Commission to change its
T&D rates. The Commission assigned AEP Central's application to Docket No. 28840.
3. Concurrent with filing its application with the Commission, AEP Central filed a similar
petition and statement of intent with each incorporated city in its certificated service area
that retains jurisdiction over its retail rates. Eighty-six (86) cities denied AEP Central's
petition and statement of intent. AEP Central filed petitions for review of those denials and
filed motions to consolidate those petitions for review into Docket No. 28840.
4. On November 4, 2003, the Commission referred AEP Central's application in Docket
No. 28840 to SOAH to conduct an evidentiary hearing on the merits and issue a PFD.
5. The following parties intervened and participated in the hearing in Docket No. 28840:
Cities; Texas Industrial Energy Consumers (TIEC); CPL Retail Energy (CPL Retail);
Coalition of Commercial Ratepayers (CCR); City of Garland, Alliance for Retail Markets
(ARM); TXU Business Services (TXU); Texas Legal Services Center and Texas
Ratepayers' Organization to Save Energy (TLSCROSE); South Texas Electric Cooperative,
Inc. (STEC); State of Texas; Office of Public Utility Counsel (OPC); and Commission Staff
(Staff).
DOCKET NO. 31433 ORDER PAGE6
6. In Docket No. 28840, AEP Central requested approval of a revenue requirement of $519.9
million, based on an historical test year of July 1, 2002, through June 30, 2003. Of that
amount, $426.6 million was for providing retail T&D service (including the portion of the
ERCOT-wide transmission costs) and $93.3 million for providing wholesale transmission
service.
7. The evidentiary hearing on the merits in Docket No. 28840 was held on March 2 through
March 18, 2004.
8. On July 1, 2004, the SOAH ALJs assigned to hear Docket No. 28840 issued their PFD. The
PFD contained certain findings with respect to rate case expenses.
9. The Commission issued orders on July 28 and August 25, 2004, remanding portions of
Docket No. 28840 to SOAH, none of which involved rate case expenses.
10. On November 16, 2004, the SOAH ALJs issued their Remand PFD in Docket No; 28840.
11. On March 3, 4, and 7, 2005, the Commission held hearings on merger savings and affiliate
expenses.
12. On August 15, 2005, the Commission issued its final order in Docket No. 28840. In
Ordering Paragraph 5 of that order, the Commission severed the determination of the
reasonableness and necessity of rate case expenses into this proceeding, Docket No. 31433.
All portions of the evidentiary record in Docket No. 28840 relevant to rate case expenses are
part of the evidentiary record in this Docket No. 31433.
13. On August 26, 2005, the presiding officer issued Order No. 1, which required the parties to
file evidence of rate case expenses and directed AEP Central and Cities to file supporting
detailed documentation for their requested rate case expenses. Order No. 1 also made all
parties to Docket No. 28840 parties to this proceeding.
DOCKET NO. 31433 ORDER PAGE7
14. On August 29, 2005, Cities requested clarification from the presiding officer regarding the
extent of the supporting documentation the Cities were required to submit under Order
No.1.
15. On August 30, 2005, Order No. 2: Clarification of Order No. 1, was issued informing Cities
that:
The entirety of the rate case expenses will be considered in this proceeding.
To the extent supporting documentation for expenses prior to September
2004 is in the record of Docket No. 28840, Cities may simply provide the
relevant cite to the record. If the supporting documentation for expenses is
not in the Docket No. 28840 record, that information should be submitted in
this proceeding.
16. On September 9, 2005, AEP Central and Cities filed supporting documentation for their
requested rate case expenses, consisting of invoices, timesheets, receipts, etc. On September
16 and October 10, 2005, AEP Central filed supplemental information related to certain of
its requested rate case expenses.
17. On September 19, 2005, the presiding officer established a procedural schedule for this
docket. In accordance with the procedural schedule, statements of position were due on
October 14, 2005, and requests for hearing were due on October 28, 2005.
18. On October 14, 2005, AEP Central, Cities, and Staff filed statements of position. In its
statement of position, Staff questioned certain items of AEP Central' s rate case expenses as
lacking adequate supporting documentation. in its statement of position, AEP Central stated
that the SOAH ALJs had recommended that one:--half of Dr. Goodfriend's expenses be
disallowed and noted that Cities' requested rate case expenses included the entire amount
billed by Dr. Goodfriend to Cities, and not one-half of that amount. In its statement of
position, Cities indicated that they did not contest any of AEP Central' s rate case expenses,
but indicated that if Cities' request associated with Dr. Goodfriend's work was contested,
then Cities would urge that the standard applied to Dr. Goodfriend be applied to AEP
Central' s experts.
DOCKET NO. 31433 ORDER PAGES
19. On October 28, 2005, AEP Central filed a motion for ruling on a disputed issue and
conditionally requested a hearing seeking a Commission ruling on whether, by severing rate
case expenses from Docket No. 28840, it intended to reopen for litigation the issue of Dr.
Goodfriend's expenses which had been fully litigated in Docket No. 28840. AEP Central's
pleading also included an identification of the portions of the record in Docket No. 28840
that addressed the issue of the quality of Dr. Goodfriend's work and the recovery of her rate
case expenses.
20. On December 12, 2005, the presiding officer issued Order No. 4, which requested a
clarification regarding a contested issue and directed Staff to file a list of disputed factual .
issues and a list of threshold legal and policy issues that must be addressed before this
proceeding can be resolved, and permitting AEP Central and Cities to make similar filings.
21. On December 22, 2005, AEP Central and Cities filed their responses to Order No. 4. In its
response, AEP Central withdrew its conditional request for a hearing.
22. Based on the filings of the parties set forth in Finding of Fact Nos. 16, 18, 19, and 21, the
Commission finds that no factual matters that have not already been fully litigated in Docket
No. 28840 are at issue or disputed. The only disputed issue in this proceeding involves the
recoverability of one-half of Cities' witness Goodfriend's expenses, which has been
subjected to a full contested case evidentiary hearing, briefing, and the issuance by the
SOAH ALJs of a PFD in Docket No. 28840.
B. AEP Central's Rate Case Expenses
23. Based on its filing of September 9, 2005, as supplemented by its filings of September 16 and
October 10, 2005, AEP Central sought recovery of $2,962,734 in recoverable rate case
expenses for Docket No. 28840 through June 2005.
24. In its statement of position filed on October 14, 2005, Staff questioned whether $24,604 of
AEP Central' s requested rate case expenses were supported by adequate underlying
documentation and recommended disallowance of these expenses.
DOCKET NO. 31433 ORDER PAGE9
25. In its filing of October 28, 2005, AEP Central indicated that it did not contest Staffs
recommendation to disallow $24,604 of AEP Central's requested rate case expenses.
26. AEP Central's reasonable and necessary rate case expenses for Docket No. 28840 as of June
2005 are $2,938,130.
C. Cities' Rate Case Expenses
27. In its filing of September 9, 2005, Cities requested rate case expenses for Docket No. 28840
of $1,391,925. This amount consisted of $1,166,925 in expenses actually incurred through
July 2005 and $225,000 in estimated expenses including appeals.
28. Cities' actual expenses of $1,166,925 through July 2005 included $83,253 billed by Cities'
witness Sarah Goodfriend.
29. The Commission adopts the SOAH ALJs' finding regarding disallowance of one-half of Dr.
Goodfriend's expenses from Docket No. 28840 because of the inadequacies in the survey
she performed. The record indicates that Dr. Goodfriend has billed the Cities $83,253;
therefore a disallowance of one-half of her fees is $41,626.
30. Based on Findings of Fact Nos. 27 through 29, Cities' recoverable rate case expenses are
$1,350,299.
31. AEP Central' s proposal to disallow Cities' witness Starnes expenses is not appropriate
because the principal rate design issues raised by Cities benefit other rate payers.
32. Cities' rate case expenses are system costs that should be borne by all ratepayers because
other ratepayers benefit from the Cities' participation.
D. Rate Case Exoense Surcharge
33. Based on Finding of Fact Nos. 26 and 30, the aggregate amount of rate case expenses found
reasonable and necessary for AEP Central and Cities are $4,288,429.
DOCKET NO. 31433 ORDER PAGElO
34. It is appropriate for AEP Central to surcharge the aggregate rate case expenses found
reasonable and necessary in Finding of Fact No. 33 to be collected from all customers over
three years.
E. Subsequent Rate Case Expenses
35. To the extent AEP Central incurs rate case expenses for Docket Nos. 28840 and 31433 after
June 2005, it is reasonable for it to recover such expenses in its next rate case to the extent it
demonstrates that such additional expenses are reasonable and necessary. Also, to the extent
that Cities incur rate case expenses for Docket Nos. 28840 and 31433 after July 2005 that
cause Cities' aggregate rate case expenses to exceed the amount found recoverable by this
Order, it is reasonable for AEP Central to recover such expenses in its next rate case to the
extent found reasonable and necessary.
V. Conclusions of Law
1. AEP Central is an electric utility as defined by §§ 31.002 of the Public Utility Regulatory
Act, TEX. UTIL. CODE ANN.§§ 11.001-66.017 (Vernon 1998 & Supp. 2005) (PURA) and is
therefore subject to the Commission's jurisdiction under PURA §§ 32.001, 33.051, and
36.102.
2. AEP Central is a T&D utility as defined in PURA § 31.002(19).
3. SOAH had jurisdiction over all matters relating to the conduct of the hearing in Docket No.
28840, including the preparation of a Proposal for Decision pursuant to PURA § 14.053 and
TEX. Gov'T CODE ANN.§ 2003.049(b).
4. AEP Central met its burden of proof regarding the amount of its rate case expenses for
Docket No. 28840 through June 2005 found reasonable and necessary in Finding of Fact No.
26.
DOCKET NO. 31433 ORDER PAGE 11
5. With the exception of the Cities' rate case expenses disallowed in Finding of Fact No. 29,
Cities met their burden of proof that their rate case expenses for Docket No. 28840 are
reasonable and necessary.
6. Cities are entitled to reimbursement for their rate case expenses as customers, as well as for
being regulatory authorities.
7. The evidentiary record in Docket No. 28840 on rate case expenses, including the portion
related to the quality of work performed by Dr. Goodfriend underlying her testimony
submitted in Docket No. 28840 identified in AEP Central's pleading described in Finding of
Fact No. 19, is part of the evidentiary record in this case together with the additional
supporting documentation filed by AEP Central and Cities in this proceeding as discussed in
Finding of Fact No. 16.
8. No contested issues of fact beyond those that were fully litigated, argued, and heard by the
SOAH ALJs in Docket No. 28840 have be.en raised in this proceeding; therefore, there is no
need for any further evidentiary hearing on the merits on recoverable rate case expenses in
addition to those already held in Docket No. 28840.
9. When the issue of the quality of the work underlying Dr. Goodfriend's testimony in Docket
No. 28840 was litigated before and the issue of the recoverability of her rate case expenses
was briefed to the SOAH ALJs, Cities had the opportunity to challenge the quality of AEP
Central' s experts' substantive work and the recovery of their rate case expenses under the
standard applied by the SOAH ALJs to Dr. Goodfriend's expenses. Cities failed to take
advantage of that opportunity and no additional evidentiary hearing on the merits is
appropriate in this proceeding as to that matter.
VI. Ordering Paragraphs
In accordance with these findings of fact and conclusions of law, the Commission issues the
following Order:
DOCKET NO. 31433 ORDER PAGE 12
1. The additional supporting documentation filed by AEP Central and Cities on
September 9, 2005, .and by AEP Central on September 16 and October 10, 2005, as
discussed in Finding of Fact No. 16 above, is admitted into the evidentiary record of this
Docket No. 31433.
2. To the extent provided in this order, the requests by AEP Central and Cities for
determination of their reasonable and necessary rate case expenses for Docket No. 28840 are
granted.
3. As set forth in Finding of Fact No. 34, AEP Central is authorized to surcharge, over a three-
year period, the aggregate rate case expenses for Docket No. 28840 found reasonable and
necessary in Finding of Fact No. 33.
4. AEP Central shall file tariff sheets consistent with this Order (compliance tariff) no later
than 20 days after receipt of this Order. The Compliance tariff, and all filings related to it,
shall be filed in Tariff Control Number 32385 and shall be styled: Compliance Tariff of
AEP Texas Central Company Pursuant to Final Order in Docket No. 31433 Severed from
Docket No. 28840. The Filing shall include a transmittal letter stating that the tariffs
attached are in compliance with this Order, giving the docket number, date of this Order, a
list of tariff sheets filed, and any other necessary information. The timetable for review of
the compliance tariff shall be established by the Commission's ALJ assigned to the tariff. In
the event any sheets are modified or rejected, AEP Central shall file proposed revisions to
those sheets in accordance with the Commission's ALJ. All subsequent filings in
connection with the compliance tariff (i.e., requests for extensions, textual corrections,
revisions) shall be filed in the Tariff Control Number provided above, and styled as set forth
above. After issuance of the final order, no further filings other than those pertaining to a
motion for rehearing shall be made in this docket. .
5. As set forth in Finding of Fact No. 35, AEP Central may seek to recover in its next rate case
expenses in connection with Docket Nos. 28840 and 31433 that it incurs after June 2005 and
Cities' rate case expenses incurred in connection with Docket No. 28840 and 31433 that
DOCKET NO. 31433 ORDER PAGE 13
exceed the amounts authorized to be recovered herein, to the extent such additional expenses
are found reasonable and necessary.
6. All other motions, requests for entry of specific findings of fact and conclusions of law, and
any other requests for general or specific relief, if not expressly granted herein, are denied.
SIGNED AT AUSTIN, TEXAS the c9: