Entergy Texas, Inc.// Office of Public Utility Counsel and Public Utility Commission of Texas v. Public Utility Commission of Texas and Texas Industrial Energy Consumers// Office of Public Utility Counsel and Entergy Texas, Inc. ( 2015 )

ACCEPTED
03-14-00735-CV
5514728
THIRD COURT OF APPEALS
AUSTIN, TEXAS
6/2/2015 3:48:59 PM
JEFFREY D. KYLE
CLERK
No. 03-14-00735-CV
IN THE FILED IN
3rd COURT OF APPEALS
THIRD COURT OF APPEALS AUSTIN, TEXAS
AT AUSTIN, TEXAS 6/2/2015 3:48:59 PM
JEFFREY D. KYLE
Entergy Texas, Inc., et al., Clerk
Appellants
v.
Public Utility Commission of Texas, et al.,
Appellees
Appeal from the 353rd Judicial District Court, Travis County, Texas
The Honorable John K. Dietz, Judge Presiding
________________________________________________________________
ENTERGY TEXAS, INC.’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.
June 2015
ORAL ARGUMENT REQUESTED
TABLE OF CONTENTS
TABLE OF CONTENTS ........................................................................................... i
INDEX OF AUTHORITIES..................................................................................... ii
ARGUMENT AND AUTHORITIES ........................................................................1
I.  There is no evidence or legal justification for the Commission’s
disallowance of over $11 million associated with ETI’s unrecovered
Hurricane Rita reconstruction costs.................................................................1
A.  Nothing in PURA required the Commission to address
amortization of the regulatory asset in Docket No. 37744. ..................1
B.  There is no evidence that anyone intended ETI to begin
amortizing the regulatory asset upon the settlement of Docket
No. 37744. .............................................................................................3
II.  The Commission’s refusal to make any adjustment to ETI’s test-year
level of purchased capacity expense is arbitrary and capricious and
unsupported by substantial evidence. ..............................................................7
A.  The Commission misapplied the standard for adjustments to
test-year expenses. .................................................................................8
B.  The Commission’s refusal to make any adjustment to test-year
levels of capacity costs is not supported by substantial
evidence. ..............................................................................................11
III.  The Commission’s decision to set ETI’s transmission equalization
expense at the test-year level is unsupported by substantial evidence. .........16
CONCLUSION AND PRAYER .............................................................................18
CERTIFICATE OF COMPLIANCE .......................................................................19
CERTIFICATE OF SERVICE ................................................................................20
APPENDIX ..............................................................................................................22
i
INDEX OF AUTHORITIES
Cases
AEP Texas Central Co. v. Public Util. Comm’n of Tex.,
286 S.W.3d 450 (Tex. App. – Corpus Christi 2008, pet. denied) .........................4
Bowden v. Phillips Petroleum Co.,
247 S.W.3d 690 (Tex. 2008) ..................................................................................8
City of El Paso v. Public Util. Comm’n of Tex.,
883 S.W.2d 179 (Tex. 1994) ..................................................................................9
Commint Technical Services, Inc. v. Quickel,
314 S.W.3d 646 (Tex. App. – Houston [14th Dist.] 2010, no pet.) ........................4
Freedom Communications, Inc. v. Coronado,
372 S.W.3d 621 (Tex. 2012) ..................................................................................5
Hawkins v. Texas Co.,
209 S.W.2d 338 (Tex. 1948) ................................................................................18
Hendee v. Dewhurst,
228 S.W.3d 354 (Tex. App. -- Austin 2007, pet. denied) ......................................5
Katy Intern., Inc. v. Jinchun Jiang,
451 S.W.3d 74 (Tex. App. – Houston [14th Dist.] 2014, pet. requested) .............5
Office of Pub. Util. Counsel v. Public Util. Comm'n,
878 S.W.2d 598 (Tex. 1994) ..................................................................................5
Office of Pub. Util. Counsel v. Texas-New Mexico Power Co.,
344 S.W.3d 446 (Tex. App. – Austin 2011, pet. denied) ......................................4
Railroad Comm’n of Tex. v. High Plains Natural Gas Co.,
628 S.W.2d 753 (Tex. 1981) .................................................................................9
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. requested) .................................4
Suburban Util. Corp. v. Public Util. Comm’n of Tex.,
652 S.W.2d 358 (Tex. 1983) ....................................................................... 8, 9, 16
Texas Utils. Elec. Co. v. Public Util. Comm’n,
881 S.W.2d 387 (Tex. App. – Austin 1994),
rev’d on other grounds, 935 S.W.2d 109 (Tex. 1996) .................................. 15, 18
ii
Vickers v. State,
No. 06-14-00072-CR, 2015 WL 1882910, *6 n.11
(Tex. App. – Texarkana Apr. 27, 2015, no pet. h.) ................................................5
Woods v. William M. Mercer, Inc.,
769 S.W.2d 515 (Tex. 1988) ..................................................................................4
Statutes
Tex. Gov’t Code Ann. § 2001.174...................................................................... 8, 18
Tex. Util. Code Ann. § 11.001, et seq. ......................................................................1
Tex. Util. Code Ann. § 11.002 .................................................................................10
Tex. Util. Code Ann. § 36.051 ...................................................................................9
Tex. Util. Code Ann. § 39.459 ...............................................................................2, 3
Tex. Util. Code Ann. § 39.462 ...............................................................................2, 3
Rules
16 Tex. Admin. Code § 25.231 ........................................................................... 9, 10
Tex. R. Civ. P. 94 .......................................................................................................4
Tex. R. Evid. 201 .......................................................................................................5
Administrative Cases
Application of Entergy Gulf States, Inc. for Determination of
Hurricane Reconstruction Costs, Docket No. 32907.............................................7
Application of Entergy Texas, Inc. for Authority to Change Rates and
Reconcile Fuel Costs, Docket No. 37744 .........................................................5, 6
iii
Appellant Entergy Texas, Inc. (“ETI”) respectfully submits this reply to the
appellees’ briefs of the Public Utility Commission of Texas (“the Commission” or
“PUCT”) and Texas Industrial Energy Consumers (“TIEC”).
ARGUMENT AND AUTHORITIES
I. There is no evidence or legal justification for the Commission’s
disallowance of over $11 million associated with ETI’s unrecovered
Hurricane Rita reconstruction costs.
ETI challenges the Commission’s decision to allow it to amortize only $15
million of its Hurricane Rita regulatory asset. That is about $11 million less than
ETI proved it is entitled to but has not recovered. The Commission, the only party
to address this issue in its response brief, does not present any persuasive argument
for upholding its decision.
A. Nothing in PURA1 required the Commission to address
amortization of the regulatory asset in Docket No. 37744.
One of the rationales the Commission gave in support of its decision was its
view that PURA section 39.459(c) required ETI’s unrecovered Hurricane Rita
reconstruction costs to be addressed in a previous case, Docket No. 37744.2 As
explained in ETI’s appellant’s brief, section 39.459(c) does not apply to the
situation at hand. That provision addresses what should happen when a utility
securitizes hurricane reconstruction costs and then recovers them a second time
1
See Tex. Util. Code Ann. § 11.001, et seq. (“Public Utility Regulatory Act” or “PURA”).
2
AR Part I, Binder 5, Item 185 (Proposal for Decision at 15 & 21-22); AR Part I, Binder 7, Item
244 (Order on Rehearing at 1).
1
from an insurance company. See Tex. Util. Code Ann. § 39.459(c). Here, neither
of those things happened. A different statute, PURA section 39.462(a), applies in
this situation. That provision authorizes a utility to seek unrecovered hurricane
reconstruction costs “in its next base rate proceeding or through any other
proceeding authorized by Subchapter C, Chapter 36.” Id. § 39.462(a) (emphasis
added). It is undisputed that this case is authorized by Chapter 36.
The Commission now tacitly acknowledges that section 39.462(a) applies,
but still argues that the issue was statutorily required to be addressed in Docket No.
37744.3 The Commission contends that even under section 39.462(a), it was
required to address the issue in Docket No. 37744 because that was the “next”
base-rate proceeding after ETI knew it would not receive the anticipated insurance
proceeds.4 That statute says no such thing. Indeed, section 39.462(a) broadly
authorizes the Commission to address the issue in “any” proceeding authorized by
Chapter 36. This reflects the legislature’s understanding of the fact that it is often
difficult or impossible for a utility to know when multiple, large insurance claims
or government grants will be paid in full. Under the plain language of PURA
section 39.462(a), the Commission had authority to address the issue in this case.
Moreover, the Commission is flat wrong that Docket No. 37744 was the first
base rate case after ETI “knew” what insurance proceeds it would recover. It is
3
PUCT’s Appellee’s Brief at 16-17.
4
See id. at 18.
2
true that ETI had not recovered these insurance proceeds when it initiated Docket
No. 37744. But it is undisputed that ETI ended up receiving another $5 million in
insurance proceeds after Docket No. 37744, and ETI adjusted its regulatory asset
to account for this fact.5 Even under the Commission’s erroneous interpretation
of PURA sections 39.459(c) and 39.462(a), then, the Commission was not limited
to addressing the issue of hurricane reconstruction costs in Docket No. 37744.
B. There is no evidence that anyone intended ETI to begin
amortizing the regulatory asset upon the settlement of
Docket No. 37744.
The second rationale the Commission gave for its order was its conclusion
that ETI did not disprove that the issue was resolved in Docket No. 37744.6 That
was not, however, ETI’s burden. ETI affirmatively established that it had not yet
included the unrecovered insurance proceeds in its rate base, or begun recovering
them, when it filed this case.7 Intervening parties responded by arguing that ETI
should already have either written off or begun amortizing the Hurricane Rita
regulatory asset upon the conclusion of Docket No. 37744.8 In other words,
intervenors argued that Docket No. 37744 barred ETI from seeking permission to
amortize the full amount of the asset in this rate case. Intervenors, not ETI, bore
5
AR Part II, Binder 37, ETI Exh. 46 (Considine Rebuttal at 18 of 55).
6
AR Part I, Binder 5, Item 185 (Proposal for Decision at 22); AR Part I, Binder 7, Item 244
(Order on Rehearing at 1).
7
AR Part II, Binder 32, ETI Exh. 8 (Considine Direct at 20).
8
E.g., AR Part II, Binder 40, Staff Exh. 1 (Givens Direct at 32-35); AR Part II, Binder 8, Cities
Exh. 2 (Garrett Direct at 11).
3
the burden of proof on this affirmative defense. E.g., Tex. R. Civ. P. 94; Woods v.
William M. Mercer, Inc., 769 S.W.2d 515, 517 (Tex. 1988); Commint Technical
Services, Inc. v. Quickel, 314 S.W.3d 646, 651 (Tex. App. – Houston [14th Dist.]
2010, no pet.).
Regardless of who bore the burden of proof, the Commission is bound to
interpret a settlement and an order adopting it in accordance with the rules of
contract interpretation. See AEP Texas Central Co. v. Public Util. Comm’n of Tex.,
286 S.W.3d 450, 464 (Tex. App. – Corpus Christi 2008, pet. denied). The
Commission cannot use the opportunity to interpret its prior order as a means to
amend it. E.g., Office of Public Util. Counsel v. Texas-New Mexico Power Co.,
344 S.W.3d 446, 452 (Tex. App. – Austin 2011, pet. denied). Under the rules of
contract interpretation, the primary duty of the Commission is to determine and
give effect to the parties’ intentions as expressed in the document. AEP Tex. Cent.
Co., 286 S.W.3d at 464.
The Docket No. 37744 order does not say anything about the Hurricane Rita
regulatory asset, and the Commission does not pretend that it does. Nor does the
Commission dispute that a utility must have a regulator’s authority to begin
recovering a regulatory asset. See, e.g., State of Texas’ Agencies & Institutions of
Higher Learning v. Public Util. Comm’n of Tex., 450 S.W.3d 615, 646 (Tex. App.
– Austin 2014, pet. requested) (recovery of regulatory asset is two-step process, the
4
second step being the authorization of a recovery mechanism). The Commission
nevertheless argues that the amortization of the Hurricane Rita regulatory asset
should have been “considered” approved in Docket No. 37744 because the order in
that case was “ambiguous,” and there is substantial evidence that no one in that
case disputed that ETI should get to recover the regulatory asset.
The Commission is correct that there is evidence in this case that no one in
Docket No. 37744 contested ETI’s right to recover the Hurricane Rita regulatory
asset at some point in time. However, there was a dispute in Docket No. 37744
about when and how ETI could recover the regulatory asset. Cities’ witness Jacob
Pous testified in Docket No. 37744 that ETI should not be able to amortize the
regulatory asset over a five-year period, and should credit the amount to its storm
reserve instead.9 No witness in this case testified about, much less controverted,
that fact. In short, no witness to this case said the parties to Docket No. 37744
agreed that ETI should begin amortizing the regulatory asset when the case was
9
See Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs,
Docket No. 37744 (Pous Direct at 113). A certified copy of Mr. Pous’s testimony is attached to
this brief at Appendix A. ETI does not present this document in support of the truth of its
content. ETI presents the document only to establish that it was filed, and the nature of the
matter the witness discussed, in the prior docket. This document was filed with the Commission,
a state agency. It is publicly available, and its authenticity is readily verifiable. This Court can,
therefore, take judicial notice of the document for the limited purpose ETI presents it. Tex. R.
Evid. 201(b); Freedom Communications, Inc. v. Coronado, 372 S.W.3d 621, 623 (Tex. 2012);
Office of Pub. Util. Counsel v. Public Util. Comm'n, 878 S.W.2d 598, 600 (Tex. 1994); Vickers
v. State, No. 06-14-00072-CR, 2015 WL 1882910, *6 n.11 (Tex. App. – Texarkana Apr. 27,
2015, no pet. h.); Katy Intern., Inc. v. Jinchun Jiang, 451 S.W.3d 74, 94 n.20 (Tex. App. –
Houston [14th Dist.] 2014, pet. requested); Hendee v. Dewhurst, 228 S.W.3d 354, 377 n.30 (Tex.
App. -- Austin 2007, pet. denied).
5
settled. Nevertheless, the Commission concluded in this case that ETI should have
done that. There is no testimony supporting the Commission’s conclusion.
The only evidence in this case of what the parties intended when they settled
Docket No. 37744 is the settlement agreement itself. Though the settlement
agreement expressly mentioned several issues in the case, it said nothing about
ETI’s request to amortize the Hurricane Rita regulatory asset. The agreement
certainly gave no indication that the parties intended ETI to begin recovering the
regulatory asset immediately. The agreement did, however, say, “[e]xcept to the
extent that the Stipulation expressly governs a Signatory’s rights and obligations
for future periods, this Stipulation shall not be binding or precedential upon a
Signatory outside this docket, and Signatories retain their rights to pursue relief to
which they may be entitled in other proceedings.”10
Despite that language in the agreement, the Commission maintains that the
Mother Hubbard clause in the order adopting the settlement supports its decision in
this case.11 The order says that “any … requests for general or specific relief, if not
expressly granted in this order, are hereby denied.”12 It is undisputed that neither
10
Id. (Aug. 6, 2010 Stipulation and Settlement Agreement at 12) (emphasis added).
11
PUCT’s Appellee’s Brief at 21.
12
Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs,
Docket No. 37744 (Dec. 13, 2010, Order at ¶ 15). Public filings in Commission dockets may be
accessed at the Commission’s interchange:
http://interchange.puc.texas.gov/WebApp/Interchange/application/dbapps/filings/pgSearch.asp
The “Control Number” for each case is its docket number.
6
the settlement agreement nor the order expressly granted ETI the authority to begin
amortizing the Hurricane Rita regulatory asset.13
In light of this language in the Docket No. 37744 order and the fact that
recovery of a regulatory asset requires express agency approval, it would have
been unreasonable for ETI to begin amortizing the asset upon the conclusion of
Docket No. 37744. The factual basis for the Commission’s contrary conclusion in
this case is not supported by substantial evidence. And there is no legal
justification – articulated in the Commission’s order or not – supporting what the
Commission did here. Because there is no evidence or law supporting the
Commission’s decision, it is not entitled to any deference and should be reversed.
II. The Commission’s refusal to make any adjustment to ETI’s test-year
level of purchased capacity expense is arbitrary and capricious and
unsupported by substantial evidence.
In its initial brief, ETI challenged the Commission’s refusal to include in
rates any of the increase in purchased capacity expense ETI proved it would incur
by the time rates went into effect. Neither the Commission nor TIEC presents any
13
The Attorney General makes a cryptic argument on page 21 of its brief, suggesting that ETI
cannot logically argue that “only one part of its request could have been approved” in Docket
No. 37744. See PUCT’s Appellee’s Brief at 21. ETI does not contend that the Commission
approved anything regarding the Hurricane Rita regulatory asset in Docket No. 37744. The
Commission approved ETI’s creation of the regulatory asset in Docket No. 32907 when it
recognized ETI’s future right to true-up its anticipated insurance recovery. See Application of
Entergy Gulf States, Inc. for Determination of Hurricane Reconstruction Costs, Docket No.
32907 (Dec. 1, 2006, Order at FOF 28). ETI sought approval of a recovery mechanism in
Docket No. 37744. ETI’s point here is that the Commission did not even mention the Hurricane
Rita regulatory asset, much less approve an amortization schedule for the asset, in its Docket No.
37744 order.
7
logical basis upon which to disallow the entire $30 million increase in expenses at
issue.
A. The Commission misapplied the standard for adjustments
to test-year expenses.
The Commission took the view that only ETI’s test-year level of purchased
capacity expense should be included in rates because acknowledging known and
measurable changes to test-year data is an “exception.”14 ETI challenged that view
as contrary to PURA and judicial precedent.
In response, the Commission and TIEC point out that the Commission may
exercise “discretion” in determining what changes to make to test-year levels of
expense. That does not mean, however, that the Commission has carte blanche to
do whatever it wants. Even when it exercises discretion, the Commission must
adhere to some guiding principles. See, e.g., Tex. Gov’t Code Ann. § 2001.174(2)
(agency order reversible for abuse of discretion); Bowden v. Phillips Petroleum
Co., 247 S.W.3d 690, 696 (Tex. 2008) (failure to adhere to any guiding principles
constitutes abuse of discretion).
One of those principles is that rates are set prospectively. E.g., Suburban
Util. Corp. v. Public Util. Comm’n of Tex., 652 S.W.2d 358, 366 (Tex. 1983).
Another is that a utility is entitled to a reasonable opportunity to recover all of the
14
AR Part I, Binder 7, Item 244 (Order on Rehearing at 1); AR Part I, Binder 5, Item 185
(Proposal for Decision at 108).
8
reasonable and necessary expenses it incurs when the rates are in effect. See Tex.
Util. Code Ann. § 36.051; Railroad Comm’n of Tex. v. High Plains Natural Gas
Co., 628 S.W.2d 753 (Tex. 1981). PURA provides no support for giving test-year
data more weight than rate-year data in the process of setting rates. PURA does
not even impose the test-year construct – that is a Commission-made ratemaking
convention. Compare Tex. Util. Code Ann. § 36.051 with 16 Tex. Admin. Code
§ 25.231(a). And the Texas Supreme Court has acknowledged that the goal of the
process is to make the test-year data as representative as possible of the cost
situation that is apt to prevail in the future, not the past. City of El Paso v. Public
Util. Comm’n of Tex., 883 S.W.2d 179, 188 (Tex. 1994). Costs that can be
anticipated with reasonable (not absolute) certainty should be included. See
Suburban Util. Corp., 652 S.W.2d at 362.
TIEC and the Commission acknowledge this is the standard. But they argue
the Commission’s order should be upheld because ETI could not predict its rate-
year costs with surgical precision. That cannot be a basis upon which to disallow
the entire adjustment. Without a crystal ball, it is impossible to know future costs
to the dollar. The Commission may not disregard compelling evidence of
substantial increases to test-year levels of expense simply because there may be
some level of uncertainty at the margin.
9
TIEC argues that projections of future expenses should be treated as
inherently suspect because there is a risk the projections will end up being too
high. TIEC fails to note that placing undue emphasis on test-year data imposes the
opposite risk – that rates will end up being too low. The Commission is charged
with setting rates that are just and reasonable for both consumers and utilities.
Tex. Util. Code Ann. § 11.002(a).
Contrary to TIEC’s assertions, ETI does not, in this appeal, seek to overturn
the Commission’s test-year approach to ratemaking. See 16 Tex. Admin. Code
§ 25.231(a). ETI simply seeks to hold the Commission to PURA’s basic guarantee
to utilities. To give effect to that guarantee, historical test-year data can only be
the starting place for setting rates. Because rates are set on a prospective basis,
evidence of known and measurable changes to test-year data must be given at least
equal weight to the test-year data itself. It cannot logically be treated with
suspicion or as an “exception” that is subject to a heightened proof requirement.
The Commission itself acknowledges this principle in other contexts. The
Commission made adjustments to other categories of ETI’s test-year expense, even
though those adjustments were based upon projections and estimates.15 If the
Commission is to allow post-test-year changes based upon projections in one
15
E.g., AR Part I, Binder 5, Item 185 (Proposal for Decision at 68 (short-term asset update), 163-
64 (payroll adjustments), & 182-86 (ad valorem tax rate update)).
10
situation, it must allow them in another. It is an abuse of discretion to apply
different standards in materially analogous circumstances.
B. The Commission’s refusal to make any adjustment to test-
year levels of capacity costs is not supported by substantial
evidence.
ETI showed that during the time rates would be in effect, it would incur over
$38 million annually above its test-year level of purchased capacity expense. ETI
showed that by procuring these third-party resources, it would save about $8
million annually in payments related to Entergy system resources. Accordingly,
ETI requested the Commission to include the net $30 million increase over its test-
year levels of purchased capacity expense in rates.
The Commission and TIEC argue the Commission was justified in denying
this request for several reasons. First, the Commission says ETI merely “believes”
its contracts will be in place during the rate year.16 But ETI proved that all the
third-party capacity contracts were executed before the hearing.17 Indeed, one of
them went into effect during the test year,18 and another went into effect five
months after the test-year end and several months before the hearing in this case.19
16
See PUCT’s Appellee’s Brief at 33.
17
E.g., AR Part IV, Binder 43, Vol. L (5/3/12 Tr. at 1942 & 1959) (Frontier contract); AR Part
II, Binder 35, ETI Exh. 34 (Cooper Direct at 17 of 25) (SRMPA contract); AR Part II, Binder 35,
ETI Exh. 34 (Cooper Direct at 16 of 25) (regarding Calpine contract).
18
AR Part IV, Binder 43, Vol. L (5/3/12 Tr. at 1942 & 1959) (regarding Frontier contract).
19
AR Part II, Binder 35, ETI Exh. 34 (Cooper Direct at 17 of 25) (regarding SRMPA contract).
11
The Commission and TIEC also argue that ETI simply “assumed” it would
have to pay for all the third-party resources it had contracted for. That is
affirmatively debunked by the record. ETI’s expectation that any adjustments for
poor performance under the Frontier contract would be minor was based upon its
past experience with the Frontier resource.20 ETI also proved that its agreement
with SRMPA was for “system capacity.”21 Even if one of SRMPA’s resources
were to falter, there is no evidence supporting the conclusion that SRMPA’s entire
system might become unavailable. ETI further proved that it had experience with
the Calpine resource, and that price deviations under that contract were “very, very
small” in ETI’s experience.22 ETI took its historical experience into account when
projecting future costs, and did not blindly assume what they would be under these
contracts.
The Commission and TIEC also contend that there are multiple “offsets”
that would negate any additional expense ETI will incur under the new third-party
purchased capacity contracts. As ETI pointed out in its appellant’s brief, none of
these offsets justifies a complete disallowance of ETI’s entire capital outlay for the
contracts at issue.
20
AR Part IV, Binder 43, Vol. F (4/26/12 Tr. at 705).
21
AR Part II, Binder 31, ETI Exh. 3A (SRMPA Power Contract) [Highly Sensitive].
22
AR Part IV, Binder 42, Vol. L (5/3/12 Tr. at 1942).
12
Both the Commission and TIEC contend that future load growth may offset
some of ETI’s increased purchased capacity expense. Even if the Commission
could properly consider future load growth in setting base rates, ETI made the
additional third-party capacity purchases to serve existing load,23 and existing
customers would recoup substantial savings from increased efficiencies and fuel
savings that would result from the purchases.24 Moreover, intervenors’ load
growth projections would not fully materialize until the rate year,25 but ETI began
incurring the additional purchased capacity costs during and shortly after the test
year. The prospect of load growth in ETI’s service area cannot logically offset the
immediate increase in purchased capacity expense at issue.
The Commission and TIEC also attempt to cast doubt upon ETI’s evidence
about how much the increased third-party capacity purchases enable ETI to avoid
in MSS-1 costs.26 But TIEC’s own witness admitted the inverse relationship
between the two categories of cost.27 Indeed, the record establishes that MSS-1
costs reached test-year lows during the last two months of the test year, when the
23
AR Part II, Binder 37 (ETI Exh. 47, Cooper Rebuttal at 5-7); see also AR Part II, Binder 37
(ETI Exh. 57, May Rebuttal at 13-15).
24
AR Part II, Binder 35 (ETI Exh. 34, Cooper Direct at 24 of 25).
25
AR Part IV, Binder 43, Vol. J (5/1/12 Tr. at 1299-1300) [Highly Sensitive].
26
As explained in ETI’s appellant’s brief, Schedule MSS-1 to the Entergy System Agreement
requires the various Entergy operating companies to make and receive payments according to
their relative share of total system capacity. See AR Part II, Binder 37, ETI Exh. 47 (Cooper
Rebuttal at 5-6).
27
AR Part II, Binder 41, TIEC Exh. 1 (Pollock Direct at 22, Table 1).
13
Frontier contract was stepped up.28 And another intervenor, Cities, adopted ETI’s
calculation of rate-year MSS-1 costs.29
Finally, the MSS-430 calculation is not a basis upon which to disallow all of
ETI’s increased third-party purchased capacity costs. The Commission itself
acknowledged that, save for costs associated with ETI’s contract with its Arkansas
affiliate, MSS-4 costs would remain “fairly stable” from the test year to the rate
year.31 Regarding the Arkansas contract (referred to by the parties as the Entergy
Arkansas, “EAI” or “EA” “WBL” contract), Cities’ and TIEC’s proposed
adjustments are not reasonably supported by the record. The evidence shows that
although the contract expired after the test year, ETI had extended the contract by
the time the hearing took place.32 Additionally, it is not reasonable to conclude
that if the Arkansas contract were not in place, ETI would not replace it with
another resource, since it is undisputed that ETI needed the capacity.33
In a nutshell, the Commission and TIEC argue that because there is “some
uncertainty” in these projections, it was inappropriate to make any adjustment. But
28
See AR Part II, Binder 9, Cities Exh. 6C (Nalepa Direct Attachment KJN-3 at 2) [Highly
Sensitive].
29
AR Part II, Binder 9, Cities Exh. 6C (Nalepa Direct at 17 [Highly Sensitive]).
30
As explained in ETI’s initial brief, Schedule MSS-4 to the Entergy System Agreement
contains a formula that sets the price of power purchased from specific units owned by other
Entergy operating companies. See AR Part II, Binder 36, ETI Exh. 39 (Cicio Direct at 24-26).
31
AR Part I, Binder 5, Item 185 (Proposal for Decision at 100); AR Part I, Binder 7, Item 244
(Order on Rehearing at 1).
32
AR Part IV, Binder 43, Vol. E (4/26/12 Tr. at 687-88 [Confidential]) .
33
See AR Part II, Binder 37 (ETI Exh. 47, Cooper Rebuttal at 15-16 of 21).
14
this Court long ago rejected the notion that when some of a utility’s proposal is
challenged, the entire proposal must be rejected unless the utility itself quantifies
the challenged piece. See Texas Utils. Elec. Co. v. Public Util. Comm’n, 881
S.W.2d 387, 404 (Tex. App. – Austin 1994), rev’d on other grounds, 935 S.W.2d
109 (Tex. 1996). This Court recognized that when the evidence conflicts about
how much of a proposal to include, it is the Commission’s job to sift through the
evidence and make the call. The Commission may not just throw its hands in the
air and refuse to address the issue simply because the utility’s evidence is contested
or because the issues are complex. See id. at 404-05.
TIEC cites the testimony of witnesses who recommended that the
Commission adopt a level of purchased capacity expense below the test-year level,
and suggests this testimony alone supports the Commission’s decision.34 But each
piece of testimony TIEC cites is based upon multiple “offsets” to ETI’s increased
level of expense. Each of these proposed offsets are flawed, as explained in ETI’s
appellant’s brief and above. Moreover, even assuming arguendo one of the offsets
were sustainable, no single offset justifies the entire disallowance. For both these
reasons, it is not reasonable to conclude from the evidence in this record that none
of ETI’s $30 million increase in third-party capacity costs were known and
measurable. The Commission did not even suggest that any single finding justifies
34
See TIEC’s Appellee’s Brief at 33.
15
the entire disallowance, or how much of the disallowance is attributed to each of its
findings. Therefore, if this Court determines that any of the Commission’s
findings are unsupported by substantial evidence, it must reverse the whole
disallowance and remand to the Commission for further consideration.
III. The Commission’s decision to set ETI’s transmission equalization
expense at the test-year level is unsupported by substantial evidence.
ETI challenges the Commission’s decision to set ETI’s MSS-2 (that is,
transmission equalization) expense at the test-year level for two reasons. First, the
Commission misapplied the “known and measurable” ratemaking standard, as it
did in setting ETI’s purchased capacity costs. Second, the Commission’s decision
is not supported by substantial evidence. The Commission and TIEC filed
responses. They devote their entire argument on this issue to attacking ETI’s
evidence supporting its request to include its rate-year level, rather than test-year
level, of MSS-2 expense in rates.
The issue before the Court, however, is whether there is substantial evidence
supporting the Commission’s conclusion that the test-year MSS-2 expense was the
level the utility “anticipated with reasonable certainty.” Suburban Util. Corp., 652
S.W.2d at 362. Clearly, this is not the case; there is no evidence that the test year
level allowed by the Commission is adequate or representative of the expense the
utility will incur when rates are in effect. All the evidence is to the contrary.
16
As ETI noted in its initial brief, no witness testified that the test-year level of
expense was a fair or reasonable representation of what ETI would incur under
Schedule MSS-2 when these rates would be in effect. Though they proposed
different levels of increase, every witness testifying on this issue – including ETI’s,
TIEC’s, and Cities’ – recognized that the test-year amount of MSS-2 expense was
too small and should be updated based on more recent, actual payment
information. 35 Moreover, ETI established that the actual, historical level of MSS-2
expense it incurred, in every month from the end of the test year to the time of the
hearing, pointed to a substantially increasing, known and measurable level of
expense. 36 TIEC now wholly ignores its own witness’s testimony on this issue,
choosing instead to focus exclusively on its criticisms of ETI’s evidence. Even
assuming arguendo that there is reasonable disagreement about ETI’s proposed
rate-year level of MSS-2 expense, the record conclusively establishes that the test-
year level is not adequate. In this circumstance, the Commission may not blindly
adhere to its test-year convention. There is literally no evidence to support the
Commission’s decision.
The Commission is bound to consider all the record evidence and reach a
conclusion that is reasonably supported by it. See Hawkins v. Texas Co., 209
35
AR Part IV, Binder 43, Vol. C (4/25/12 Tr. at 452-53); AR Part IV, Binder 43, Vol. F (4/27/12
Tr. at 738, 760, 763, 780, & 783-84); AR Part II, Binder 41, TIEC Exh. 1 (Pollock Direct at 32-
33); AR Part II, Binder 8, Cities Exh. 4B (Goins Direct, Errata No. 3 at 9 [Highly Sensitive]);
AR Part II, Binder 8, Cities Exh. 4 (Goins Direct at 22).
36
AR Part II, Binder 9, Cities Exh. 29 (Response of ETI to Cities RFI-5-1).
17
S.W.2d 338, 339-40 (Tex. 1948); Texas Utils. Elec. Co., 881 S.W.2d at 404. The
APA confirms this principle, requiring a court to reverse the agency if its decision
is “not reasonably supported by substantial evidence considering the reliable and
probative evidence in the record as a whole.” Tex. Gov’t Code Ann.
§ 2001.174(2)(E) (emphasis added). Because the Commission’s decision is not
supported by any evidence, much less reasonably supported by the evidence, the
Court must reverse it.
CONCLUSION AND PRAYER
For all these reasons, Entergy Texas, Inc. respectfully requests this Court
reverse the district court’s judgment insofar as it affirms the Public Utility
Commission’s order in the respects discussed above. ETI requests the Court
remand the case to the Commission for further proceedings consistent with the
Court’s decision. Entergy Texas, Inc. further requests its costs of court and any
other relief to which it may show itself justly entitled.
18
Respectfully submitted,
/s/ Marnie A. McCormick
John F. Williams
State Bar No. 21554100
Marnie A. McCormick
State Bar No. 00794264
mmccormick@dwmrlaw.com
DUGGINS WREN MANN & ROMERO, LLP
P. O. Box 1149
Austin, Texas 78767-1149
(512) 744-9300
(512) 744-9399 fax
ATTORNEYS FOR APPELLANT
ENTERGY TEXAS, INC.
CERTIFICATE OF COMPLIANCE
I certify that this document contains 4,727 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
19
CERTIFICATE OF SERVICE
The undersigned counsel certifies that 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 via electronic service on the 2nd day of June, 2015:
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 Intervenor Texas Industrial Energy Consumers
Susan M. Kelley (retired)37
Administrative Law Division
Office of the Attorney General
P. O. Box 12548
Austin TX 78711-2548
Counsel for Intervenor State Agencies
Sara Ferris
Office of Public Utility Counsel
1701 N. Congress Ave., Ste. 9-180
P. O. Box 12397
Austin TX 78711-2397
Counsel for Intervenor Office of Public Utility Counsel
37
State Agencies have not yet appeared or designated a new lead counsel in this appeal.
20
Daniel J. Lawton
LAWTON LAW FIRM PC
12600 Hill Country Blvd., Ste. R-275
Austin TX 78738
Counsel for Cities of Anahuac, et al.
/s/ Marnie A. McCormick
Marnie A. McCormick
21
APPENDIX
A. Certified copy of Direct Testimony of J. Pous in PUCT Docket No. 37744
22
APPENDIX A
SOAH DOCKET NO. XXX-XX-XXXX
PUC DOCKET NO. 37744
'I II
APPLICATION OF ENTERGY TEXAS, § BEFORE THE STATE OFFICE
INC. FOR AUTHORITY TO CHANGE § OF
RATES AND RECONCILE FUEL COSTS § ADMINISTRATIVE HEARINGS
Ii
DIRECT TESTIMONY AND EXIDBITS
OF
JACOBPOUS
ON BEHALF OF
I
CERTAIN CITIES SERVED BY ENTERGY TEXAS, INC.
CBRTIPIBD TO BS ATRUE AND CORRSCT
COPY OF THE OIUOINAL ON FH..E WITH THE
PUBLIC UTILITY COMMISSION OF TEXAS
JUNE9,2010
c~~'~.
:*t:3';•
Diversified Utility Consultants Inc.
1912 West Anderson Lane, Suite 202
Austin, TX 78757
Record copY
·-
UL \ 3 'l.0\6
Cities Exhibit , 'K.'f
·-·
,I '
TABLE OF CONTENTS
SECTION I: INTRODUCTION .................................................................................................... 1
SECTION II: DEPRECIATION ..................................................................................................... 7
1. General ........................................................................................................................................ 7
2. Production Life ........................................................................................................................... 11
A. General ................................................................................................................................... 11
B. Basis for Retirement Dates ..................................................................................................... 14
C. Recommendation .................................................................................................................... 21
3. Production Interim Retirements .................................................................................................. 22
4. Production Net Salvage ............................................................................................................... 26
5. Mass Property Life .................................................................................................................. 38
A. Introduction ........................................................................................................................... 38
B. Account Specific Adjustments .............................................................................................. 43
6. Mass Property Net Salvage ......................................................................................................... 71
7. ELG vs. ALG Calculation Procedure ......................................................................................... 76
8. Remaining Life Method .............................................................................................................. 86
SECTION III: FULLY ACCRUED DEPRECIATION ................................................................. 89
SECTION IV: SGSF CAPITAL RECOVERY .............................................................................. 93
SECTIONV: STORM INSURANCE RESERVE ...................................................................... 102
1. General .................................................................................................................................... I 02
2. Storm Reserve Deficit ............................................................................................................. 105
3. Target Reserve ........................................................................................................................ 114
4. Annual Expected Losses ......................................................................................................... 117
I 5. Minimum Storm Reserve Threshold ....................................................................................... 120
SECTION VI: CASH WORKING CAPITAL ................................................................................. 123
I I
1. Introduction ............................................................................................................................. 123
2. General .................................................................................................................................... 125
3. Revenue Lag ............................................................................................................................. 127
A. Meter Reading To Billing ................................................................................................... 127
B. Billing-To-Payment Revenue Lag ...................................................................................... 130
C. Customer Float .................................................................................................................... 135
4. Expense Leads .......................................................................................................................... 136
A. Payroll .................................................................................................................................. 136
B. FAS 106 .............................................................................................................................. 139
C. Entergy Services Inc. ("ESI") Expense Lead ..................................................................... 141
D. Other O&M Expense Lead ................................................................................................. 142
SECTION VII: RIVER BEND DECOMMISSIONING REVENUE REQUIREMENT .............. 144
SECTION VIII: RIVER BEND DEPRECIATION RATES ........................................................... 149
2
ACRONYMS:
2008 Study 2008 Gannett Fleming Depreciation Study
AICPA American Institute of Certified Public Accountants
ALG Average Life Group
APFD Accumulated Provision for Depreciation
ASL Average Service Life
CIS Consumer Information Systems
Company Entergy Texas, Inc.
Commission Public Utility Commission of Texas
CPI Consumer Price Index
ewe Cash Working Capital
DUCI Diversified Utility Consultants, Inc
EIA U.S. Energy Information Administration
EAi Entergy Arkansas, Inc.
EGSL Entergy Gulf States Louisiana
ELG Equal Life Group
ESI Entergy Services, Inc.
ETI Entergy Texas, Inc.
FERC Federal Energy Regulatory Commission
FPL Florida Power & Light Company
FPSC Florida Public Service Commission
MPSC Michigan Public Service Commission
NARUC National Association of Regulatory Utility Commissioners
NIMB "not in my backyard" syndrome
NPC Nevada Power Company
NPSC Nevada Public Service Commission
NRC Nuclear Regulatory Commission
O&M Operation & Maintenance
occ Oklahoma Corporation Commission
OLT Observed Life Table
PSO Public Service of Oklahoma
PUC Public Utility Commission of Texas
RCT Railroad Commission of Texas
1
Reserve Accumulated Provision for Depreciation
SGSF Spindletop Gas Storage Facility
SGT Sabine Gas Transportation Company
SRP Strategic Resource Plan
SWEPCO Southwest Electric Power Company
USOA FERC Uniform System of Accounts
2
Docket No. 37744
APPLICATION OF ENTERGY TEXAS § BEFORE THE
INC. FOR AUTHORITY TO CHANGE § PUBLIC UTILITY
RATES & RECONCILE FUEL COSTS § COMMISSION OF TEXAS
SECTION I: INTRODUCTION
1 Q. PLEASE STATE YOUR NAME AND BUSINESS?
2 A. My name is Jacob Pous and my business address is 1912 W. Anderson Lane, Suite 202,
3 Austin, Texas 78757.
4
5 Q. WHAT IS YOUR OCCUPATION?
6 A. I am a principal in the firm of Diversified Utility Consultants, Inc. ("DUCI"). A copy of
7 my qualifications appears as Appendix A.
8
9 Q. HAVE YOU PREVIOUSLY TESTIFIED IN PUBLIC UTILITY PROCEEDINGS?
10 A. Yes. Appendix A also includes a list of proceedings in which I have previously presented
11 testimony. In addition, I have been involved in numerous utility rate proceedings that
12 resulted in settlements before testimony was filed. In total, I have participated in well
13 over 400 utility rate proceedings in the United States and Canada.
14
15 Q. WHAT IS YOUR PROFESSIONAL BACKGROUND?
16 A. I am a registered professional engineer. I am registered to practice as a Professional
17 Engineer in the State of Texas, as well as numerous other states.
18
19 Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?
20 A. I am testifying on behalf of the cities of Anahuac, Beaumont, Bridge City, Cleveland,
21 Conroe, Houston, Huntsville, Montgomery, Navasota, Oak Ridge North, Pine Forest,
22 Pinehurst, Port Arthur, Port Neches, Groves, Nederland, Orange, Rose City, Shenandoah,
I 1
I
1 Silsbee, Sour Lake, Splendora, Vidor, and West Orange ("Cities") served by the Entergy
2 Texas, Inc. ("Company" or "ETI").
3
4 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
5 A. The purpose of my testimony is to address certain adjustments that are required to ETI's
6 requested rate increase filed before the Public Utility Commission of Texas
7 ("Commission" or "PUC"). I have provided Cities' witness Mr. Garrett with my
8 recommendations in order that they will be incorporated into the Cities' total revenue
9 requirement presentation.
10
11 Q. PLEASE BRIEFLY SUMMARIZE YOUR TESTIMONY.
12 A. The following is a brief summary of each of the major areas I address herein.
13
14 • Production Plant Life Spans. The Company proposes to retire almost all of its
15 gas-fired generation on June 30, 2025, for purposes of calculating depreciation
16 rates in this case as set forth in the 2008 Gannett Fleming depreciation study
17 ("2008 Study"). The proposed retirement year is earlier than and inconsistent with
18 the Company's internal planning for system resources. The Company's proposed
19 depreciation life spans assumes a retirement date that is also artificially short in
20 comparison to the life expectancy by the industry as well as the Company's own
21 resource planning division. I recommend establishing minimum life spans for the
22 Company's gas-fired generating facilities at the later of the year 2029 or when
23 such units reach 65 years of age. The standalone impact of this recommendation is
24 a reduction in depreciation expense of $11. 7 million based on plant in service as
25 of December 31, 2008.
26
27 • Interim Retirements. In spite of this Commission's previous rulings and
28 precedent regarding exclusion of interim retirements in the calculation of
29 production plant depreciation rates, the Company still proposes interim
30 retirements in its calculation. The Company's witness, Mr. Spanos attempts to
31 distinguish the Commission precedent by relying on an incorrect premise that the
32 Company's interim retirement analysis is based on a historical perspective, and
33 the Commission's precedent is applicable to a future perspective. This is a
34 distinction without a difference, because the Company applies the result of its
35 historical calculations to projected future results. Therefore, the Company's
36 witness's attempt to distinguish the Company's request from previous
37 Commission decisions is incorrect. The impact of upholding the Commission's
38 long standing precedent against interim retirements results in an approximate $4.6
39 million reduction in depreciation expense based on plant as of December 31,
40 2008.
2
1
2 • Production Plant Net Salvage. The Company proposes negative net salvage
3 values ranging from a negative 15% to a negative 32% for its gas and coal-fired
4 generations. The Company's coal-fired proposal isbased on an undocumented,
5 unsupported and inappropriate regression analysis associated with a database for
6 which the Company's depreciation witness has no first-hand knowledge. The
7 Company does not have a regression or any mathematical model to estimate net
8 salvage for gas-fired generation, but rather assumes it is approximately 80% of
9 the coal-fired value. Therefore, assuming the 80% factor to be correct, any
10 inaccuracies in the coal regression analysis would carry over to the Company's
11 projected net salvage for gas-fired generation. As a second step to the Company's
12 unsupported net salvage analysis, Mr. Spanos escalates the estimated demolition
13 costs as of the end of 2008 into the future for as many as 35 years and
14 recommends s that current customers pay with current dollars for future inflated
15 costs. These aspects of the Company's analysis are neither credible nor
16 reasonable. Therefore, in consideration of significant increases in scrap metal
17 prices that have occurred in the last 5 years and the potential sale of used
18 equipment, a zero (0) level of net salvage for production plant is recommended.
19 On a standalone basis this recommendation results in a reduction of
20 approximately $11. 7 million in depreciation expense based on plant as of
21 December 31, 2008.
22
23 • Mass Propertv Life Analysis. There are numerous problems with the Company's
24 proposed life-curve combination for the various mass property accounts
25 (transmission, distribution and general plant). First and foremost, the Company's
26 life analysis includes the impact of hurricane activity as typical, ongoing events.
27 This has resulted in certain accounts having life expectations shorter than
28 basically all other utilities in the industry. In addition, the Company's consultant
29 recognizes that there is a "significant portion" of the survivor curve to which the
30 curve-fitting process should be geared; however he has failed to properly
31 implement such criteria. Finally, the Company has failed to provide reasonable or
32 adequate support for its various positions. Modifications to 16 of the Company's
33 proposals results in a standalone impact of a $11.1 million reduction to annual
34 depreciation expense based on plant as of December 31, 2008.
35
I 36
37
• Mass Property Net Salvage. The Company's analysis relies only on the most
recent 5 years of data. This compares to a 16-year database employed by the same
consultant in the current El Paso Electric Company case before this Commission.
l 38
39
40
Without any indication in the testimony, depreciation study or workpapers, is the
fact that the limited five years of data is not even maintained by account, yet it is
I 41
42
presented by account based on an initially unidentified data manipulation.
Another fatal flaw in the Company's proposals is that there are the effects of
several major hurricanes reflected in the 5-year historical database. Thus, the data
43
! 44
45
46
relied upon by the Company to propose net salvage parameters are significantly
skewed to more negative levels than would reasonably be expected. Given the
significant problems with the Company's presentation and database in this case,
I 3
I
1 retaining the existing levels of net salvage by account is recommended. On a
2 standalone basis this recommendation results in a $10.6 million reduction in
3 annual depreciation expense based on plant in service as of December 31, 2008.
4
5 • Calculation Procedure. The Company proposes to use the Equal Life Group
6 ("ELG") calculation procedure. The ELG procedure is not a conservative capital
7 recovery method and in fact represents an accelerated procedure when compared
8 to the industry standard Average Life Group ("ALO") calculation procedure. The
9 ELG procedure is inaccurate in all instances, except in the improbable scenario
10 that future annual retirements for up to 100 years into the future can be precisely
11 estimated. In reality, ETI cannot predict future annual retirement levels with any
12 degree of accuracy, even for as little as a 5-year period. Relying on the ALO
13 procedure, a straight line, non-accelerated procedure, results in a standalone
14 reduction to annual depreciation expense of $19.3 million based on plant as of
15 December 31, 2009.
16
17 • Combined Impact of Depreciation Adjustments. The combined impact of the
18 various depreciation adjustments is not simply the summation of the individual
19 standalone impacts. If life, net salvage, or calculation procedure proposals are
20 modified within the same account, they are interactive with each other. As set
21 forth on Schedule (JP-1 ), the combined impact of the various adjustments results
22 in a $57 million reduction in depreciation expense based on plant in service as of
23 December 31, 2008.
24
25 • Fully Accrued Depreciation. The Company admits that it unilaterally changed
26 the Commission approved depreciation rates when it ceased booking depreciation
27 expense for three accounts. The Company does not have the authority to
28 unilaterally change a depreciation rate previously approved by the Commission.
29 Reversal of the Company's inappropriate actions results in a $6.2 million decrease
30 in rate base and a $1.5 million credit amortization expense associated with a four-
31 year amortization period.
32
33 • Spindletop Gas Storage Facilitv l"SGSF"). Since the Company's last fully
34 litigated rate proceeding, the Company has exercised an option to purchase the
35 SGSF facilities for $1. Due to the unique situation of ownership, operation and
36 cost recovery, customers have significantly overpaid depreciation expense and are
37 now entitled to appropriate net salvage treatment and correction of the
38 intergenerational inequity that has transpired. Amortizing the excess depreciation
39 reserve over a 4-year period and recognition of Company-established net salvage
40 expectations results in a $5.5 million reduction to revenue requirements
41 associated with this unique investment. However, given Cities' witness Mr.
42 Nalepa's recommendation relating to the SGSF, only $1.2 million of my
43 recommendation associated with the recognition of net salvage is required, when
44 Mr. Nalepa's position is adopted.
45
4
1 • Storm Insurance Reserve. The Company has overstated revenue requirements in
2 the calculation of its insurance reserve request. The Company performs a flawed
3 Monte Carlo simulation. The Company has skewed its results to the high side
4 based on the inclusion of inappropriate costs and charges to the insurance reserve.
5 ETI also inappropriately attempts to segregate certain hurricane securitization cost
6 from the reserve. Removing certain inappropriate charges to the Company's
7 insurance reserve and performing a more realistic projection of future storm cost
8 accruals results in a $7. 7 million reduction to the Company's storm reserve annual
9 accrual and a $45.9 million reduction to rate base. In addition, I recommend an
IO increase in the current $50,000 storm insurance threshold limit to $500,000.
11
12 • Cash Working Capital ("CWC"). The Company overstates and incorrectly
13 calculates the Company's CWC requirements. In particular, the Company relies
14 on an inconsistent implementation of service period between revenues and
15 expenses. There are numerous other flaws associated with the Company's
16 approach to CWC that require correction. Based on my various recommendations,
17 the standalone impact of the corrected lead-lag analysis for the measurement of
18 ewe requirements would result in an incremental $43.7 million reduction to rate
19 base and an approximate corresponding $5. 7 million reduction to revenue
20 requirements.
21
22 • River Bend Decommissioning. The Company seeks approval from this
23 Commission for its proposed level of decommissioning expense associated with
24 the River Bend plant that is now owned by ETI's Louisiana affiliate Entergy Gulf
25 States Louisiana ("EGSL"). Cities' witness Mr. Brazell testifies that the
26 Commission does not have the authority to set a decommissioning revenue
27 requirement for River Bend given EGSL' s ownership of the plant. The
28 Company's proposal is based on a 40-year life span for River Bend, rather than
29 the more appropriate and realistic 60-year life expectancy. Therefore, if the
30 Commission were to determine the proper decommissioning revenue requirement
31 for Texas retail customers, I recommend that a 60-year life span be employed. In
32 addition, the beginning balances in the decommissioning funds are understated in
33 the Company's presentation and would need to be corrected. The standalone
34 impact of these adjustments eliminates the need for Texas retail customers to
35 contribute any additional amounts to the decommissioning trust funds. Therefore,
l 36
37
my recommendation results in a $2.8 million reduction to proposed annual
decommissioning revenue requirements.
38
39 • River Bend Depreciation. Cities' witness Mr. Brazell presents the position that
40 the Commission does not have the authority to set depreciation rates for River
41 Bend. However, the Company has requested that the Commission do just that.
42 Unfortunately, the Company's presentation reflects a 40-year service life for
43 River Bend. It should be noted that the Company relies on a 60-year life for
44 River Bend in the Louisiana jurisdiction and agreed to a 60-year life in Docket
45 No. 34800, a settled proceeding. While the Company has not yet received
46 permission from the Nuclear Regulatory Commission (''NRC") for such license
5
1 extension, it must be noted that not a single license application for the 20-year life
2 extension has been denied by the NRC. Therefore, if the Commission does elect
3 to establish a depreciation rate for River Bend, it should do so based on the 20-
4 year life extension and with no interim retirements reflected therein.
5
6 Q. IS THERE A CONCERN THAT NEEDS TO BE ADDRESSED AT THE
7 BEGINNING OF YOUR TESTIMONY?
8 A. Yes, in the area of depreciation and capital recovery a utility can present aggressive,
9 middle of the road, or conservative parameters given the subjectivity required in
10 performing any future depreciation or capital recovery estimate. After review of the
11 Company's depreciation presentation, it is clear that the Company's position in this case
12 is one of the most aggressive presentations realistically possible. The Company's
13 approach results in an extremely excessive level of depreciation expense, rapid return of
14 capital investment to shareholders, which in my estimation, is unreasonable and an
15 unnecessary burden for current customers.
16
17 Q. DO THE PROPOSED DEPRECIATION PARAMETERS CONTINUE THE
18 CORPORATE PLAN THAT PUSHES AGGRESSIVE DEPRECIATION
19 PRACTICES?
20 A. Yes. While utilities have become more sophisticated in the last several decades when it
21 comes to spelling out their corporate plans, this Company continues its predecessor's
22 Corporate Plan, which under the heading of Long-Range Corporate Objectives, stated the
23 following: "Push accounting/depreciation judgments aggressively where possible." 1
24 (Emphasis added).
25
26 Q. CAN YOU PROVIDE SPECIFIC EXAMPLES THAT DEMONSTRATE ETl'S
27 CONTINUATION OF THE PREVIOUSLY STATED AGGRESSIVE
28 DEPRECIATION PRACTICES?
29 A. Yes. First and foremost is the Company's decision to utilize the ELG calculation
30 procedure. Reliance on the ELG procedure in light of identifiable "anomalies" that result
31 from the analyses of the underlying data is flawed and can no longer be relied upon to
1
Gulf States Utilities Corporate Plan 1980-1984 item l(c).
6
I predict with some degree of certainty how mortality patterns might look in the future.
2 The anomalies in the analyses are due, at least in part, to problems with the data,
3 including potential problems associated with the jurisdictional separation of ETI and
4 EGSL. Indeed, the combination of the underlying data problems with the fact that the
5 ELG procedure is the most accelerated book depreciation calculation procedure that can
6 be proposed in a rate proceeding, can only result in a magnified distortion of the capital
7 recovery process compared to the industry standard ALG calculation procedure.
8
9 Next, in the area of production plant net salvage, Mr. Spanos not only relied upon an
I0 unsubstantiated regression analysis that produces excessively negative values, but then
11 proposed a unique escalation calculation. The Company, through Mr. Spanos' testimony,
12 proposes to charge current customers, who would have to pay with current dollars, for
13 costs that have been escalated, without discounting costs back to the present, for as many
14 as 35 years into the future. Such approach is illogical and unrealistic.
15
16 While there are other actions taken by Mr. Spanos that further push his and the
17 Company's aggressive depreciation goals, the above examples more than establish the
18 nature of the Company's presentation.
19 SECTION II: DEPRECIATION
20 1. General
21
I 22
23
Q.
A.
WHAT IS DEPRECIATION?
There are two commonly cited definitions of depreciation. The first comes from the
I 24
25
Federal Energy Regulatory Commission's ("FERC") Uniform System of Accounts
("USOA"): 2
l 26 'Depreciation', as applied to depreciable plant, means the loss in service
27 value not restored by current maintenance, incurred in connection with
I 28 the consumption or prospective retirement of electric plant in the course
2
Title 18 Code of Federal Regulations Part 101.
7
1 of service from causes which are known to be in current operation and
2 against which the utility is not protected by insurance. Among the causes
3 to be given consideration are wear and tear, decay, action of the
4 elements, inadequacy, obsolescence, changes in the art, changes in
5 demand and requirements of public authorities.
6 The second definition, from the American Institute of Certified Public Accountants
7 ("AICPA"), is similar:
8 Depreciation accounting is a system of accounting which aims to
9 distribute the cost or other basic value of tangible capital assets, less
10 salvage (if any) over the estimated useful life of the unit (which may be a
11 group of assets) in a systematic and rational manner. It is a process of
12 a/location, not of valuation. Depreciation for the year is a portion of the
13 total charge under such a system that is allocated to the year. Although
14 the allocation may properly take into account occurrences during the
15 year, it is not intended to be a measurement of the effect of all such
16 occurrences.
17 Q. WHAT ARE THE TWO GENERAL FORMULAS USED IN DETE RMINING
18 DEPRECIATION RATES?
19 A. The whole life and the remaining life technique are the most commonly used formulas.
20 The whole life technique is as follows: 3
Depreciation Rate (%) = [ Original Cost - Net Salvage
Average Service Life
Original Cost
J
21 The remaining life technique for calculating depreciation rates is as follows:
22
~ J
Original Cost - Reserve - Net Salvage
Depreoiation Rate (%) [ Remaining Life
Original Cost
3
A theoretical depreciation reserve calculation is developed and compared to the actual accumulated provision
for depreciation in conjunction with the whole life technique. If the differential is significant, an
amortization of the differential for some period of time may be recommended.
8
1 The two formulas should equal each other when the difference between the theoretical
2 reserve and the actual Accumulated Provision for Depreciation ("APFD" or "reserve")
3 are recovered over the remaining life of the investment under the whole life formula.
4
5 Q. ARE THERE ADDITIONAL CONSIDERATIONS IN DEPRECIATION BEYOND
6 THE DEFINITIONS?
7 A. Yes. The definitions provide only a general outline of the overall utility depreciation
8 concept. In order to arrive at a depreciation-related revenue requirement in a rate
9 proceeding, a depreciation system must be established.
10
11 Q. WHAT IS A DEPRECIATION SYSTEM?
12 A. A depreciation system constitutes the method, procedure, and technique employed in the
13 development of depreciation rates.
14
15 Q. BRIEFLY DESCRIBE WHAT IS MEANT BY "METHOD".
16 A. Method identifies whether a straight-line, liberalized, compound interest, or other type of
17 calculation is being performed. The straight-line method is normally employed for utility
18 depreciation proceedings.
19
20 Q. BRIEFLY DESCRIBE WHAT IS MEANT BY "PROCEDURE".
21 A. Procedure identifies a calculation approach or grouping. For example, procedures can
22 reflect the grouping of only a single item, items by vintage (year of addition), items by
23 broad group or total grouping, and equal life groupings. The vast majority of utilities and
I 24
25
regulatory authorities use the ALG procedure.
I 26
27
Q.
A.
PLEASE BRIEFLY DESCRIBE WHAT IS MEANT BY "TECHNIQUES".
There are two main categories of techniques with various sub-groupings: the whole life
I 28
29
technique and the remaining life technique. The whole life technique simply reflects
calculation of a depreciation rate based on the whole life (e.g., a ten-year life would
I 30
31
imply a ten percent depreciation rate over the life of a plant). The remaining life
technique recognizes that depreciation is a forecast or estimation process that is never
9
1 precisely accurate and requires true-ups in order to recover only 100% of what a utility is
2 entitled to over the entire life of the investment. Therefore, as time passes, the remaining
3 life technique attempts to recover the remaining unrecovered balance over the remaining
4 life or other period. Most utilities rely on a remaining life technique in utility rate matters.
5
6 Q. DO THE METHODS, PROCEDURES, AND TECHNIQUES INTERACT WITH
7 ONE ANOTHER?
8 A. Yes. Different depreciation rates will result depending on what combination of method,
9 procedure and technique is employed. Differences will occur even when beginning with
10 the same average service life and net salvage values.
11
12 Q. WHAT IS NET SALVAGE?
13 A. Net salvage is the value obtained from retired property (the gross salvage) less the cost of
14 removal. Net salvage can be either positive in cases where gross salvage exceeds cost of
15 removal, or negative in cases where cost of removal is greater than gross salvage.
16
17 Q. HOW DOES NET SALVAGE IMPACT THE CALCULATION OF
18 DEPRECIATION?
19 A. The intent of the depreciation process is to allow the Company to recover 100% of
20 investment less net salvage. Therefore, if net salvage is a positive 10%, then the utility
21 should only recover 90% of its investment through annual depreciation charges, under the
22 theory that it will recover the remaining 10% through net salvage at the time the asset
23 retires (e.g., 90% + 10% = 100%). Alternatively, if net salvage is a negative 10%, then
24 the utility should be allowed to recover 110% of its investment through annual
25 depreciation charges so that the negative 10% net salvage that is expected to occur at the
26 end of the property's life will still leave the utility whole (e.g., 110% - 10% = 100%).
27
28 Q. WHAT ARE THE KEY ELEMENTS OF THE DEPRECIATION FORMULA AT
29 ISSUE IN TIDS PROCEEDING?
30 A. All parameters in the previously noted formula are at issue. The establishment of life and
31 net salvage parameters are a function of the analyses performed, the interpretation of the
10
1 data, the judgment and experience of the analys~ and other relevant information. In
2 addition, the remaining life calculation is at issue given that Mr. Spanos of Gannett
3 Fleming performs a different remaining life calculation than every other utility that does
4 not retain Gannett Fleming that I have dealt with over the past 37 years, including this
5 Company. This remaining life calculation produces theoretically impossible results.
6 Finally, the calculation procedure is a major issue in this case, as ETI does not rely on the
7 industry standard ALG procedure.
8 2. Production Life
9 A. General
10
11 Q. WHAT IS THE ISSUE IN TlllS PORTION OF YOUR TESTIMONY?
12 A. This portion of my testimony addresses the appropriate life spans for the Company's
13 various generating units. In particular, I will address what appears to be a practice of
14 understating the life span for generating units. I recommend longer life spans for the
15 Company's gas-fired generating units.
16
17 Q. WHAT IS A LIFE SPAN FOR A GENERATING UNIT?
18 A. A life span for a generating unit sets the period during which it is expected to be in
19 service prior to being retired. For example, if a generating unit was placed into service on
20 January 1, 1980 and had a 60-year estimated life span it would have a projected
21 retirement date of December 31, 2040. It should be noted that a generating unit that is
22 placed in peaking or standby service is still in service and not retired.
I 23
24 Q. PLEASE EXPLAIN THE SIGNIFICANCE OF SETTING AN APPROPRIATE
~ 25 LIFESPAN.
26 A. In determining the depreciation rate, and thus depreciation expense for a generating unit,
I 27 it is necessary to establish the period over which customers are expected to receive
28 benefits and in return pay for such benefits. This process complies with the standard
f 29 regulatory "matching principle." As previously noted, the depreciation formula includes
I 11
I
1 the original cost less net salvage less the APFD, all divided by the remaining life. Thus, if
2 the life spans, and the related remaining life, are set at too short a period, current
3 customers overpay and vice versa. Failure to set a proper estimated retirement date for a
4 generating unit creates intergenerational inequities and fails to comply with the
5 "matching principle" of ratemaking.
6
7 Q. ARE THE RETIREMENT DATES FOR GENERATING UNITS KNOWN WITH
8 CERTAINTY?
9 A. Not for most units. Even for nuclear units that must operate within the period of a license
10 granted by the NRC, we now know that the initial estimate of a 40-year life span has been
11 or will be expanded to 60-years. Indeed, in ETI's last case, Docket No. 34800, the life
12 span for River Bend was extended for ratemaking purposes to 60 years. 4
13
14 Q. WHEN SETTING THE LIFE SPAN FOR A GENERATING UNIT, IS IT
15 APPROPRIATE TO LIMIT THE TIME FRAME TO THE INITIAL ESTIMATED
16 PERIOD CORRESPONDING TO WHEN MAJOR CAPITAL ADDITIONS MAY
17 BE REQUIRED IN ORDER TO KEEP THE UNIT IN SERVICE?
18 A. No, even though ETI and its depreciation consultant, Mr. Spanos, attempt to rely on such
19 a concept to artificially limit the current estimate of life span for units. Indeed, it is
20 questionable whether even the Company really believes such less than credible argument
21 given the sizeable capital additions it had to make in the early stages of service life for its
22 gas fired units. 5 In recognition of these sizeable capital additions that were necessary to
23 keep the units operating, ETI did not attempt to limit the life spans in its earlier
24 depreciation studies to the date of the expected capital additions.
4
PUC Docket No. 34800 Final Order FOF 34.
s Exhibit JJS-1pages209-252.
12
1 Q. WHY IS IT INAPPROPRIATE TO ARTIFICIALLY LIMIT THE LIFE SPAN OF
2 A GENERATING UNIT BASED ON UNCERTAINTY AS TO WHETHER
3 FUTURE CAPITAL ADDITIONS WILL BE MADE?
4 A. It is inappropriate to implement such depreciation judgment because it assumes that
5 utilities will act differently in the future than they have acted in the past without the
6 benefit of specific factors that would warrant such a change. Generating units are very
7 capital-intensive items. Economic theory recognizes that it is normally expected that
8 capital expenditures and normal maintenance expense will not only be made, but
9 encouraged as necessary, to keep a large capital intensive facility in operation for as long
10 as economically practical. This has been the Company's practice as it applies to actual
11 operation of its units.
12
13 An analogy would be associated with the purchase of a home. A new home can easily be
14 expected to last well over 50 years. However, a major capital expenditure for a new roof
15 may be required after 15 to 20 years. No reasonable person would set the life expectancy
16 of the house at 20 years because the decision has not been made regarding an expected
17 major expenditure 20 years in the future. The same can be said about limiting the
18 expected initial life expectancy of a house to even 30 or 40 years when the second
19 replacement of a roof can be expected. The issue becomes at what point would one
20 expect external forces such as a change in character of the neighborhood or other events
21 to change, for it to warrant the abandonment of the house. As long as the best use of the
22 house is as a dwelling and it is economically cost effective to make repairs and
23 replacements, the initial life should not be set artificially short due to potential
24 uncertainties surrounding future major capital additions.
I 25
I 26
27
Q. DOES THE COMPANY'S PRODUCTION PLANT DEPRECIATION EXPENSE
REPRESENT A SIGNIFICANT REVENUE REQUIREMENT?
I 28
29
A. Yes. The Company's 2008 Study identifies over $783 million of investment and proposes
$28.4 million in depreciation expense for annual Steam Production plant (Accounts 310-
316). 6 This level of depreciation expense is unnecessary and only arises as a result of the
l 30
6
2008 Study at Exhibit JJS-1 page 52.
I 13
I Company's witness's aggressive "depreciation judgment" for reflecting life spans,
2 corresponding interim retirements, and net salvage values.
3 B. Basis for Retirement Dates
4
5 Q. WHAT TESTIMONY DID THE COMPANY SPECIFICALLY PROVIDE IN
6 SUPPORT OF THE PROPOSED LIFE SPANS FOR ITS VARIOUS
7 GENERATING UNITS?
8 A. The Company provided the testimony of Mr. Spanos. The entire basis for this significant
9 parameter is set forth at pages 19 and 20 of Mr. Spanos' direct testimony where he states:
10
11 The bases for the probable retirement years are life spans for each facility
12 that are based on judgment and incorporate consideration of the age, use.
13 size. nature of construction. management outlook, and typical life spans
14 experienced and used by other electric utilities for similar facilities. Many
15 of the life spans result in probable retirement years that are many years in
16 the future, but included as part of ETI' s resource plan. As a result, the
17 retirements of these facilities are not yet subject to specific management
18 plans. At the appropriate time, detailed studies of the economics of
19 rehabilitation and continued use or retirement of the facility will be
20 performed and the results incorporated in the estimation of the facility's
21 life span. (Emphasis added).
22
23 Q. DID THE COMPANY ADD ANY ADDITIONAL INFORMATION REGARDING
24 THE BASIS FOR THE LIFE SPANS OF ITS UNITS IN THE 2008
25 DEPRECIATION STUDY?
26 A. While the 2008 Study added the following statements, such verbiage fails to provide any
27 additional meaningful basis for the Company's proposed life spans:
28
29 The life span estimates for power generating stations were the result of
30 considering experienced life spans of similar generating units, the age of
31 surviving units, general operating characteristics of the units, major
32 refurbishing, and discussion with management personnel concerning the
33 probable long-term outlook for the units. Final decisions as to date of
34 retirement will be determined by management on a unit by unit basis. 7
35 (Emphasis added).
7
2008 Study at Exhibit JJS-1 page 35.
14
1 Q. WHAT SPECIFIC ITEM OF INFORMATION HAS THE COMPANY
2 PROVIDED IN SUPPORT OF ITS "JUDGMENT" IN ESTABLISIDNG THE
3 LIFE SPANS FOR ITS GENERATING UNITS REFLECTING
4 "CONSIDERATION OF THE AGE" OR "USE, SIZE, NATURE OF
5 CONSTRUCTION" OF ITS UNITS?
6 A. The Company has provided no information that would support its proposal for a life span
7 as short as 46 years for Sabine 5. In fact, Sabine Units 1 and 2, which are much smaller
8 and dispatched less than Sabine 5, have already reached ages in excess of 46 years. Thus,
9 judgment in conjunction with consideration of age or physical characteristics of the units
10 should have caused the Company to propose longer life spans than it has.
11
12 Q. WHAT SPECIFIC ITEM OF INFORMATION HAS THE COMPANY
13 PROVIDED IN SUPPORT OF ITS "JUDGMENT" IN ESTABLISIDNG THE
14 LIFE SPANS FOR ITS GENERATING UNITS REFLECTING "MANAGEMENT
15 OUTLOOK"?
16 A. The Company has provided no information that would support its proposals. In fact, the
17 timing horizon of the Company's Strategic Resource Plan ("SRP") is through 2028. 8 The
18 SRP planning horizon exceeds the retirement dates for all of the Company's gas-fired
19 units, yet such plan relies on the continued operation of all such units to meet future
20 loads. Thus, even the Company's current management "outlook" refutes the judgment
21 employed by Mr. Spanos in the 2008 Study.
22
23 Q. WHAT SPECIFIC ITEM OF INFORMATION HAS THE COMPANY
I 24
25
PROVIDED IN SUPPORT OF ITS "JUDGMENT" IN ESTABLISIDNG THE
LIFE SPANS FOR ITS GENERATING UNITS REFLECTING "TYPICAL LIFE
~
26 SPANS EXPERIENCED AND USED BY OTHER UTILITIES OF SIMILAR
27 FACILITIES"?
I 28
29
A. The Company has provided no information. However, through discovery, it was
determined that Gannett Fleming has supported a range of life spans for gas-fired units
I 30 that is so wide that it would allow for a selection of about any value, even ones
8
Response to Rose City 1-36 Attachments.
15
l approaching 70 years. I submit that Gannett Fleming's life span range for gas-fired units
2 is so large that it defies any credibility that might have been assigned to it in the
3 "judgmental" process claimed by Mr. Spanos.
4
5 Q. DOES MR. SPANOS' TESTIMONY PROVIDE SUFFICIENT EXPLANATION
6 AND JUSTIFICATION TO SUPPORT THE COMPANY'S PROPOSED LIFE
7 SPANS FOR ITS GENERATING FACILITIES?
8 A. No.
9
10 Q. DID THE COMPANY PROVIDE ANY ADDITIONAL INFORMATION JN
11 RESPONSE TO DISCOVERY?
12 A. Yes. Mr. Spanos provided his site visit notes that reference limited additional information
13 such as:
14
15 • System maintenance good;
16 • Control upgrades;
17 • Monthly vibration program, performance tests; and
18 • Boiler exam and maintenance every year. 9
19
20 Q. DO THESE ADDITIONAL STATEMENTS CONTAINED IN MR. SPANOS' SITE
21 VISIT NOTES PROVIDE SUFFICIENT SUPPORT FOR THE COMPANY'S
22 LIFE SPAN PROPOSALS?
23 A. No. These statements represent the type of statements one would expect relating to a
24 dynamic situation requiring decisions whether to retire units or continue to expend funds
25 to permit continued operation. In fact, it is quite clear from these comments and other
26 information in the 2008 Study that the Company has historically decided, and currently is
27 deciding, to make necessary capital expenditures to keep its units in operation long after
28 the claimed initial design life. The Company has faced the decision whether to retire
29 these units or spend funds to keep them in operating condition beyond initial expectations
30 and in each instance has decided that it is economically appropriate and efficient to do
31 what all other utilities have been doing: maximize the life of a capital-intensive asset.
9
Response to Rose City 1-15 Attachment.
16
1 There is more support for longer life spans in Mr. Spanos' notes than there is for the
2 artificially short life spans being proposed.
3
4 Q. DID MR. SPANOS PROVIDE ANY ADDITIONAL INFORMATION
5 REGARDING ms PROPOSED LIFE SPANS DURING ms DEPOSITION?
6 A. Yes. Mr. Spanos stated that the life spans corresponded with the best estimate of the
7 likelihood of assets being either taken out of service (i.e. retired), or the date of expected
8 major capital additions in the future made to change the functionality of the asset. 10 He
9 also admits that the proposed retirement in his study does not necessarily relate to when
10 the units would be shut down. 11 These two statements taken together default to a position
11 that the probable retirement dates in Mr. Spanos' study are the unsubstantiated date Mr.
12 Spanos assumes the Company may make major capital additions to change the
13 functionality of the units.
14
15 Q. IS THERE ANYTHING IN THE USOA THAT DEFINES OR TIES THE
16 SERVICE PERIOD FOR A GENERATING UNIT TO AN ASSUMED DATE
17 WHEN A UTILITY MIGHT MAKE A MAJOR CAPITAL ADDITION THAT
18 CHANGES THE FUNCTIONALITY OF AN ASSET?
19 A. Absolutely not.
20
21 Q. DID MR. SPANOS OR THE COMPANY PROVIDE A SINGLE DOCUMENT
22 THAT DEMONSTRATES THE PROPOSED RETIREMENT DATES ARE THE
23 COMPANY'S BEST ESTIMATE OF WHEN A UNIT WILL RETIRE?
I 24
25
A. No. In fact, as previously discussed, the documents presented by the Company now
demonstrate that assumed retirements prior to 2029 are not the current best estimate of
~ 26 the Company.
~
I 10
Deposition of Mr. Spanos on April 20, 2010 at TR 39.
Id.
I
II
17
!
1 Q. DID MR. SPANOS PROVIDE A SINGLE DOCUMENT OR ITEM OF
2 EVIDENCE THAT IT IS APPROPRIATE TO TIE THE PROPOSED
3 RETIREMENT DATE TO A CONCEPT OF WHEN MAJOR CAPITAL
4 EXPENDITURES MIGHT OCCUR?
5 A. No, Mr. Spanos' concept is a backdoor approach to recognizing interim additions,
6 something the PUC and other regulators do not permit.
7
8 Q. WHAT ARE INTERIM ADDITIONS?
9 A. Interim additions are theoretical future dollars of investment or capital additions in plant
10 to be added to existing facility of the Company. Such additions are not the dollars of
11 investment currently in service. Rather, they are .estimated dollars for replacement of
12 certain existing facilities or for additions of new facilities to an existing generating
13 facility in the future.
14
15 Q. ARE INTERIM ADDITIONS APPROPRIATE FOR DEPRECIATION
16 PURPOSES?
17 A. No. Interim additions are inappropriate since they reflect the estimation of potential
18 additions to plant-in-service that currently do not exist and are not used and useful in
19 providing service. Interim additions may never actually occur or may occur at a much
20 different date or amount than initially assumed.
21
22 Q. IN THE RATEMAKING PROCESS, ARE INTERIM ADDITIONS EVER
23 APPROPRIATE FOR DEPRECIATION PURPOSES?
24 A. No. Interim additions are appropriate only after they occur. Once such expenditures
25 occur, and the plant becomes used and useful in providing service, it is appropriate to
26 incorporate the plant investment into a depreciation study. Under this approach, the
27 Company is not deprived of a return of its investments associated with interim additions.
28 Moreover, customers are not inappropriately charged for unknown plant that is not used
29 and useful in providing service to them at the time the depreciation rates are developed.
18
1 Q. WHAT SOURCE SUPPORTS YOUR POSITION THAT ESTIMATED INTERIM
2 ADDITIONS SHOULD NOT BE REFLECTED IN THE DEPRECIATION
3 CALCULATION?
4 A. The National Association of Regulatory Utility Commissioners (''NARUC") 1968
5 publication entitled Public Utility Depreciation Practices describes, on pages 133 and
6 134, how interim additions are treated. It states the following:
7 Appropriate computations must be made for such interim retirements, but
8 interim additions are not considered in the depreciation computation until
9 they are actually made.
10 It is possible to estimate the probable future retirements and additions to a
11 particular piece ofproperty and thus arrive at a single depreciation rate
12 applicable over the entire life of the property. This is an unsatisfactory
13 practice inasmuch as considerable speculations would be required to
14 make such an estimate on future additions. In any event. this is not
15 necessary inasmuch as the depreciation accrual can be adjusted in future
16 years as additions are made. (Emphasis added).
17
18 The 1996 NARUC depreciation publication reaffirms this concept. 12
19
20 Q. HAS THE FERC RENDERED A DECISION ON THE CONCEPT OF
21 INTERIM ADDITIONS?
22 A. Yes. The FERC reviewed and ruled on this issue in its Opinion No. 165, a
23 Commonwealth Edison Company case. 13 In that case, Commonwealth Edison had
24 proposed taking into account budgeted future interim additions and stated that without the
25 inclusion of the budgeted interim additions, there would be a violation of the matching
I 26
27
principle (i.e. revenues collected corresponding to the expenses incurred). In Opinion
No. 165, the FERC clearly rejected recognition of interim additions:
I 28
29
... we reject its [Edison 'sj claim that this will leave some costs
unrecovered after the plant is retired. Such a result might occur if
30 Commonwealth would fail to adjust its depreciation rates from time to
I 31
32
time, taking into account up-to-date information on changes in plant
balances, estimated remaining life, salvage and removal cost experience,
33 and accumulated provision for depreciation to date. However,
I 12
Page 142 states" ... interim additions are not considered in the depreciation base or rate until they occur."
13
23 FERC paragraph 61,219 (1983)
19
1 Commonwealth not only is free to make such adjustments to its
2 depreciation rates, but is obligated to do so to assure that as near as
3 possible the service value of electric plant is fully recovered during its
4 useful life. For all these reasons, we find no basis to approve
5 Commonwealth's depreciation methodology. 14
6
7 Q. IS THERE A NEED TO SPECULATE ON THE COMPANY'S FUTURE
8 INTERIM ADDITIONS?
9 A. No. The Company will have the opportunity to recover actual additions to plant from
10 customers once they occur.
11
12 Q. ARE OTHER UTILITIES FACED WITH THE SAME CONCERNS RELATING
13 TO THE DECISION TO REPAIR OR REPLACE WORN OR BROKEN
14 COMPONENTS VERSUS RETIRE A UNIT?
15 A. Yes, and the trend in the industry has been to project even longer life spans. In fact, in a
16 recent case here in Texas, Southwest Electric Power Company ("SWEPCO") filed for life
17 spans longer than ETI has for comparable units. 15 A listing of comparable size and age of
18 generating units between SWEPCO and ETI, along with the life spans filed by both
19 utilities is set forth in the table below:
20
21 COMPARABLE UNITS
Size Year Life Size Year Life
ETIUnit (MW) Installed Span SWEPCOUnit 5 A. Interim retirements have been characterized as a fine-tuning adjustment to the life-span
16 analysis. The life-span method is used in estimating the retirement date for any large unit
17 of property such as an entire generating facility to recognize that through the course of its
18 60-year life span, several components of that generating facility will be changed. The
19 theory behind interim retirement rates is that even though a large unit of property, such as
20 a generating facility might retire in 60 years, in the interim period many components have
21 to be replaced in order to maintain the overall generating facility in operating condition.
22 An analogy to this would be a car, which might be anticipated to have a service life of 10
23 years. During the 10-year life of the car, the owner might have to replace the battery,
24 tires, alternator and other components in order to maintain the automobile in a safe and
25 operable condition. Therefore, even though the automobile may have a 10-year life span,
26 a 9.8-year average service life ("ASL") for the automobile and its components would
27 result due to the averaging of the automobile's life span with the average of the
28 individual components. In other words, the interim retirement rate would be a fine-
29 tuning factor used to reduce the service life from 10 years to a 9.8 year ASL.
22
1 Q. HAS THE COMPANY INCORPORATED THE IMPACT OF INTERIM
2 RETIREMENTS IN ITS DEPRECIATION ANALYSIS?
3 A. Yes. 20
4
5 Q. HAS THE COMMISSION PREVIOUSLY REJECTED THE INCLUSION OF
6 INTERIM RETIREMENTS IN THE CALCULATION OF PRODUCTION PLANT
7 DEPRECIATION RATES?
8 A. Yes. The Commission has specifically and consistently excluded interim retirements
9 from prior production-plant depreciation-rate calculations in fully litigated rate cases. In
10 Docket Nos. 14965 and 16705, the most recent fully litigated major electric base rate
11 cases where interim retirements were an issue, the Commission once again reaffirmed its
12 position and rejected the inclusion of interim retirements from the depreciation rate
13 calculation for production plant. In Docket No. 14965 the Commission stated " ...
14 forecasted interim additions and retirements and net salvage increases to plant in service
15 are not known and measurable changes to test-year invested capital."21 (Emphasis
16 added). In Docket No. 16705 the Commission denied the impact or recognition of all
17 interim retirements and additions beyond the end of the test year. 22 The Commission has
18 also denied the inclusion of interim retirements in cases where I also recommended their
19 inclusion.
20
21 Q. WAS MR. SPANOS AWARE OF COMMISSION PRECEDENT WHEN HE
22 PROPOSED THE INCLUSION OF INTERIM RETIREMENTS?
23 A. Yes. However, he believed that the precedent dealt with future interim retirements, not
24 historical interim retirements. 23 While his analysis of interim retirements was based on
I 25 historical data, the results were applied to future remaining lives because Mr. Spanos
26 thinks "that is a good indicator of what is going to happen into the future for interim
~ 27 retirement purposes."24 Mr. Spanos' approach is no different than the practices of other
28 utilities where the Commission rejected the use of interim retirements. In fact, Mr.
~
20
Direct Testimony of Mr. Spanos at page 18.
I 21
22
23
Docket No. 14965 FOF 94.
Final Order Docket No. 16705 at FOF 186.
Deposition of Mr. Spanos on March 25, 2010 at TR 93-94.
24
I Deposition of Mr. Spanos on April 20, 2010 at TR 95-96.
23
I
l Spanos could not identify any docket where this Commission had allowed interim
2 retirements as he would characterize them. 25
3
4 Q. IF THE COMl\flSSION WERE INCLINED TO REVERSE ITS PRECEDENT ON
5 TIDS ISSUE IN Tms CASE, DO YOU BELIEVE THE ANALYSIS PRESENTED
6 BY THE COMPANY IS APPROPRIATE?
7 A. No.
8
9 Q. WHAT DOES THE COMPANY PROPOSE FOR INTERIM RETIREMENTS?
10 A. The Company proposes to implement a calculation procedure for interim retirements
11 based on a truncated interim retirement survivor curve. 26
12
13 Q. PLEASE EXPLAIN THE PROBLEMS WITH THE COMPANY'S PROPOSED
14 METHOD.
15 A. The Company's approach relies on an actuarial analysis of the historical data for the
16 investment in Accounts 311 through 316.27 Actuarial analyses are normally performed on
17 more homogenous-type investments. The types of investments booked in the major steam
18 production plant accounts are non-homogeneous and do not reasonably lend themselves
19 to actuarial analyses. In other words, the retirement forces experienced by boiler tubes
20 booked in Account 312 may be noticeably different than those affecting the lighting
21 system, also booked in Account 312. Moreover, the retirement of individual units of
22 property in Account 312 can vary significantly. Therefore, Mr. Spanos' reliance on an
23 inappropriate method, which in turn relies on non-homogenous data to "guess" at a 55-R2
24 life-curve combination for the largest production plant account, is inappropriate. I use the
25 term "guess" given the fact that Mr. Spanos analysis yielded a survivor curve that only
26 declined by 12 percentage points out of 100 percentage points for a full curve. He simply
27 "guesses" or forces a result for the remaining 88%. Moreover, his "guess" at the 12%
28 decline in the observed life table ("OLT") was not good or reasonable. 28 If the
25
Id., at TR 96.
26
Exhibit JJS-1, pages 209-254.
27
Id., at pages 56-80.
28
OLT reflects the actual retirement pattern exhibited over a given period.
24
1 Commission were inclined to change its precedent on this matter, "guessed" at or forced
2 results cannot be accepted as a valid basis for the inclusion of the impact of interim
3 retirements.
4
5 Another consideration relating to Mr. Spanos' proposal in this case is his constant
6 practice of relying on industry data. With this in mind, it is worth noting that Mr. Spanos
7 proposed much longer ASLs for the same accounts in his current El Paso Electric
8 testimony before the Commission, as shown in the table below.
9
10 COMPARISON OF INTERIM RETIREMENT CURVES
Increase to EPE
Account ETI EPE Years %
311 65-R2 100-Sl.5 35 54%
312 55-R2 80-82.5 25 45%
314 50-82.5 75-R4 25 50%
315 50-S0.5 65-Sl.5 15 30%
316 50-Rl.5 60-R3 10 20%
11 Moreover, it must be noted that Mr. Spanos had basically the same level of utility
12 specific OLT data with which to work with in both cases. Therefore, it appears that the
13 difference between the two contemporaneous studies both filed at the same time before
14 this Commission is the depreciation policy in place for ETI. Finally, it is worth noting
15 that the Florida Public Service Commission ("FPSC") this year denied the method of
16 calculating interim retirement employed by Gannett Fleming recognizing many of the
17 problems noted above. 29
I 18
19 Q. WHAT DO YOU RECOMMEND?
I 20
21
A. Given that this Commission has consistently denied the recognition and inclusion of
interim retirements for production-plant deprecation rates in prior proceedings, I
I 22
23
recommend that the Commission precedent on this matter be recognized for ratemaking
purposes in this proceeding and the impact of interim retirements be eliminated from the
I 24 Company's proposed depreciation calculation.
29
I FPSC Docket No. 080677-EI Order at pages 30-32.
25
I
1 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
2 A. The total standalone impact of the elimination of the proposed interim retirements from
3 production plant depreciation rates results in a reduction to the Company's requested
4 depreciation expense by $4,608,437 based on plant as of December 31, 2008.
5 4. Production Net Salvage
6
7 Q. WHAT ISSUE DO YOU ADDRESS IN TIDS PORTION OF YOUR
8 TEST™ONY?
9 A. I address the Company's request for production net salvage. Specifically, the Company
10 requests net salvage for its various generating facilities ranging from a negative 15% to a
11 negative 32% for its various generating facilities. 30 In response to the Company's
12 proposal, I recommend a zero (0) level of net salvage, even though a more appropriate,
13 yet still conservative, level would be a positive 5% to 10%.
14
15 Q. WHAT DOLLAR IMPACT DOES THE COMPANY'S PROPOSAL HAVE ON
16 DEPRECIATION EXPENSE?
17 A. Based on plant in service as of December 31, 2008, the Company's net salvage request of
18 $190.7 million over the life of the investment produces approximately $11.6 million of
19 annual depreciation revenue requirements. 31
20
21 Q. WHAT IS THE COMPANY'S BASIS FOR ITS REQUEST OF NEGATIVE NET
22 SALVAGE?
23 A. Mr. Spanos states the following:
24
25 final net salvage of dismantling costs of steam production units was based
26 on common industry practices of linear regression analysis by Megawatts
27 (capacity). These analyses were performed as of 2008 and the overall
28 dismantling costs were projected to the date of removal. 32
30
Exhibit JJS-1, pages 51 and 52.
31
Exhibit JJS-1, pages 51 and 52, setting the net salvage percentage to zero {O).
32
Direct Testimony of Mr. Spanos at page 22.
26
1 In other words, the Company performed what it claims is a common industry practice of
2 performing linear regression analysis on some unidentified data set to arrive at an
3 unidentified regression equation, which can then be applied to the individual megawatt
4 size of the Company's generating units. Once a current cost value has been established
5 under this method, Mr. Spanos then escalated the costs into the future until the proposed
6 retirement date for the Company's various generating units.
7
8 Q. CAN YOU PROVIDE A SPECIFIC EXAMPLE OF WHAT THE COMPANY
9 PROPOSES?
10 A. Yes. Mr. Spanos claims his regression analysis yields a $40.61 per kW dismantlement
11 cost for the Big Cajun coal-fired generating unit. 33 He then applies that value to the 588
12 Mw size of the Big Cajun coal unit, which yields an estimated cost of $23,878,680 in
13 2008 dollars. Mr. Spanos then applied ETI's 42.5% ownership share of what he believed
14 was the Entergy ownership share of the Big Cajun unit, in an attempt to establish a
15 $10,148,439 cost applicable to ETI. Mr. Spanos inflated that 2008 cost figure at an
16 annual compounded rate of 3% for 3 5 years into the future, the assumed future retirement
17 date for the Big Cajun unit. The result is an estimated future dismantlement cost of
18 $28,536,311. 34 The future escalation of cost raised the requested cost level by multiplying
i 19 the current cost level by a factor of 2.814 (l.03<35 ».
20
21 Q. SETTING ASIDE FOR THE MOMENT THE REGRESSION AND ESCALATION
22 CONCEPTS EMPLOYED BY MR. SPANOS, IS ms CALCULATION
23 CORRECT?
No. For Big Cajun and Nelson 6, Mr. Spanos failed to reduce the stated MW size of the
I 24
25
A.
units for Entergy's ownership share. While Mr. Spanos did apply a 42.5% ownership
I 26
27
share allocation between ETI and Entergy Gulf States Louisiana ("EGSL"), he failed to
recognize that these are jointly owned units with other utilities. In particular, Cajun
l 28
29
Electric Power Company, Inc. owns 58% of the Big Cajun unit, while other utilities own
30% of Nelson 6. Therefore, Mr. Spanos' calculation overstates the dismantlement cost
I 33
Exhibit JJS-1page189, column (a).
34
$10,148,439 X l.03 3S = $28,536,31).
27
1 for these units even if one were to accept his linear regression and future cost escalation
2 approach.
3
4 Q. IS THE LINEAR REGRESSION ANALYSIS AS PROPOSED BY MR. SPANOS A
5 COMMON INDUSTRY PRACTICE AS CLAIMED?
6 A. No. In fact, when requested to provide support for such claim, all Mr. Spanos could state
7 was that it "is utilized by many utilities."35 Clearly, the claim is incorrect. Indeed, no
8 other use of the "common" industry approach was found in review of the recent
9 testimonies of Mr. Spanos.36
10
11 Q. WAS MR. SPANOS REQUESTED TO IDENTIFY OTHER UTILITIES WHERE
12 GANNETT FLEMING HAD EMPLOYED A METHOD OTHER THAN LINEAR
13 REGRESSION ANALYSIS FOR PRODUCTION PLANT NET SALVAGE
14 DURING THE PAST 3 YEARS?
15 A. Yes. Surprisingly, Mr. Spanos only identified two examples in response to this request
16 for information. 37 What is surprising about Mr. Spanos' response is that he currently has
17 a Gannett Fleming depreciation study on behalf of El Paso Electric before the
18 Commission in Docket No. 37690. In that depreciation study, Mr. Spanos did not employ
19 a linear regression analysis for production plant net salvage. In other words, two
20 contemporaneous depreciation studies performed on two different utilities both providing
21 service in Texas, both of which have been filed before this Commission, reflect
22 inconsistent application of what Mr. Spanos claims is a "common'' industry practice.
23
24 Q. DID MR. SPANOS IDENTIFY ms STANDARD FOR PRODUCTION PLANT
25 DISMANTLEMENT COSTS DURING A RECENT DEPOSITION?
26 A. Yes. In the El Paso Electric case noted above, Mr. Spanos stated during his deposition the
27 following regarding his standards for production plant terminal net salvage:
35
Response to Rose City 12-S(a).
36
Response to Rose City 1-3.
37
Response to Rose City 12-5(b).
28
1 I feel as though you need to incorporate a terminal net salvage component
2 or a -- what's called a decommissioning study to be incorporated into the
3 development.
4 However, if the company has not gone through the practice of getting the
5 estimate on that or does not have any determination of what their plans are
6 at final dismantlement, it's, in my opinion, not proper to build in a
7 terminal net salvage component without some sort of support.
8 The company [El Paso Electric] at this time hadn't had any plans, so
9 we've not included that. But there is going to be a major cost to dismantle
10 these facilities, and that needs to be built into rates for production facilities
11 as a full-service value of that facility.
12 But unless you have a specific plan or at least an idea of what's going to
13 happen, I don't think it is wise to build that into rates. But I think that's
14 something that's going to be a consideration here. 38 (Emphasis added.)
15
16 In other words, Mr. Spanos has established his standard for production plant terminal net
17 salvage in the El Paso Electric case, which is inconsistent within his proposal in this
18 proceeding. He admits that it is not proper to build in a terminal net salvage component
19 without some sort of support. Neither ETI nor El Paso Electric produced a
20 decommissioning cost estimate and neither have specific plans as to what would transpire
I 21 at the time of retirement.
22
23 Q. CAN MR. SPANOS CLAIM THAT HE DID NOT HAVE THE DATA
24 NECESSARY TO PERFORM THE "COMMON INDUSTRY PRACTICE OF
25 LINEAR REGRESSION ANALYSIS" IN THE EL PASO ELECTRIC CASE
26 THAT HE HAS PROPOSED IN TIDS CASE?
27 A. No. Mr. Spanos claims that his firm obtained this data in the early 1990s. Thus, Mr.
28 Spanos had the information available for his El Paso Electric study and testimony, yet
I 29 found it not wise to rely on it there, unlike his decision in this proceeding.
1
I
38
Deposition of Mr. Spanos on March 25, 2010 in Docket No. 37690 at page 86.
29
1 Q. SETTING ASIDE MR. SPANOS' FAILURE TO COMPLY WITH ms OWN
2 STANDARD AND ms INCONSISTENT TREATMENT BETWEEN EL PASO
3 ELECTRIC AND ETI, ARE THERE MAJOR PROBLEMS WITH THE
4 COMPANY'S PROPOSED REGRESSION ANALYSIS?
5 A. Yes. The Company's basis for its production net salvage has almost too many problems
6 to enumerate. However, the following are some of the major problems:
7
8 • No underlying data exists to support the claimed regression data points;
9 • No first-hand knowledge exists of where the data came from;
10 • Assumed future inflation rates are inconsistent with what the Company's rate
11 of return witness is proposing in this case;
12 • Proposing that current customers pay with current dollars for future inflated
13 costs while failing to discount such costs back to a present value level is
14 rmproper;
15 • Reliance on a false premise that the data points in the regression analysis
16 represent actual dismantlement costs of generating units over many years,
17 rather than being associated with dismantlement cost estimates for plants that
18 have not been dismantled is improper;
19 • Mathematical errors exist in the net salvage process; and
20 • Failure to recognize or understand the dramatic underlying differences
21 between assumed values or values within the regression database associated
22 with comparable sized units leads to flawed results in addition to the flawed
23 results generated by the flawed analysis.
24
25 Q. PLEASE DESCRIBE THE DATABASE RELIED UPON BY MR. SPANOS TO
26 DEVELOP ms REGRESSION ANALYSIS.
27 A. As set forth in the Company's response to Rose City 12-5, Mr. Spanos claims
28 approximately 60 data points associated with demolition costs for coal-fired generating
29 facilities. However, he does not have a single item of information associated with the
30 underlying data points. In other words, he cannot identify the units, stations, year in
31 which the dismantlement supposedly occurred, the process employed, the utility at issue
32 or anything else about the underlying data. Review of the data points indicates a mixture
33 of individual units with stations that are comprised of multiple units. The smallest data
34 point reflects 21 megawatts, while the largest data point reflects 3,145 megawatts. I am
35 unaware of any single generating unit that begins to reflect a size even approaching 3,000
36 MW.
30
1
2 Q. DO VALUES IN MR. SPANOS' REGRESSION DATA SET REPRESENT
3 UNREALISTIC RANGES?
4 A. Yes. For example, at the low end of the MW size range, Mr. Spanos identifies a 21 MW
5 and a 23 MW unit. The observed values for these two similarly sized coal units are a
6 $38.14 per kW dismantlement cost and a $119.22 per kW dismantlement cost,
7 respectively. This cost range represents in excess of a 3 to I variance from the low value
8 to the high value. Ranges of this magnitude for the same type and size units call into
I 9 question the validity of the data. However, Mr. Spanos does not have the underlying data
IO and cannot explain such variances.
11
12 Q. IS THE UNREALISTIC LEVEL OF VARIANCE LIMITED TO ONLY THE
13 SMALLEST SIZE UNITS?
14 A. No. For example, Mr. Spanos' database includes a 610 MW and a 630 MW unit with
15 corresponding estimated decommissioned costs of $8.96 per kW and $84.33 per kW,
16 respectively. Again, this range represents a differential in excess of 9 times from the low
17 value to the high value. Ranges of this magnitude for similar size and type units
18 demonstrate that Mr. Spanos' unsubstantiated database does not produce credible values.
19
20 Q. DOES THE FACT THAT MANY OF THE VALUES FALL WITHIN MORE
21 REALISTIC RANGES HELP JUSTIFY RELIANCE ON THE REGRESSION
22 ANALYSIS?
23 A. No. Without access to the underlying data, we do not know whether the majority of the
24 values in the more plentiful middle range are not a function of cost estimates from the
25 same cost estimator firm, thus further diminishing the credibility of the database.
~ 26
27 Q. YOU STATE THAT THESE VALUES ARE ESTIMATED VALUES, DOES MR.
! 28
29 A.
SPANOS AGREE WITH YOU?
No. During Mr. Spanos' deposition, he stated that he believed that the values reflected in
I 30 his database were for actual demolition activity, rather than estimated demolition cost
I 31
I
1 studies. 39 Mr. Spanos' understanding of the data is based on his undocumented
2 discussions with his predecessors at Gannett Fleming. 40
3
4 Q. IS MR. SPANOS CORRECT?
5 A. No. This is the first time I have heard Mr. Spanos claim that these were actual demolition
6 cost studies. For example, when Mr. Spanos relied on a regression analysis for his
7 proposed production plant net salvage proposal in a Nevada Power Company (''NPC")
8 case before the Nevada Public Service Commission (''NPSC"), he believed the values
9 were from estimated cost studies.41 In that case, Mr. Spanos also stated that the "data
10 [demolition cost information] were obtained from a survey conducted by the Property
11 Accounting and Valuation Committee of the Edison Electric Institute.''42 However, Mr.
12 Spanos' statements regarding these studies included discussion of different contingency
13 factors between studies. If the data represented actual completed demolition of power
14 plants, there would be no need for references to contingency factors. Contingency factors
15 are only applicable to future occurrences. The most troubling aspect of this situation is
16 that Mr. Spanos now claims he has even less of the limited data he had in the NPC case
17 associated with the old demolition cost estimates in this case.
18
19 Q. IS THERE YET ANOTHER PROBLEM WITH THE RELIANCE ON A 20-YEAR
20 OLD UNIDENTIFIED DATABASE?
21 A. Yes. Productivity rates and types of potential demolition activities have changed over
22 time. For example, there now exists a mechanical boom that can reach 300 ft high with
23 sheers on the end that can sever large beams of steel. This type of equipment has changed
24 the productivity levels reflected in whatever studies Mr. Spanos relied upon in
25 comparison to today's activity. In addition, Mr. Spanos' reliance on demolition cost
26 studies fails to recognize that many portions of units may be sold, which diminishes the
27 level of negative net salvage or, in fact, results in positive levels of.net salvage. Another
28 consideration that Mr. Spanos fails to take into account is the possibility of reuse of the
39
Deposition of Mr. Spanos on April 20, 2010 at TR 117.
40
Id.
41
NPSC Docket Nos. 03/1001-03/1002.
42
Rebuttal Testimony Mr. Spanos, page 16 in NPC Docket Nos. 03-1001/03-1002.
32
1 facilities by ETI. Most of the decommissioning studies in the late 80s and early 90s
2 reflect a substantial amount of dollars for site restoration. Such costs would be
3 inappropriate if a utility were to reuse the facility, as those costs would be associated with
4 the new installation. Simply put, multiple problems with the Company's production net
5 salvage analysis render it unreliable for any purpose in this proceeding.
6
7 Q. DOES MR. SPANOS FURTHER EMPLOY AN EXCESSIVE DEPRECIATION
8 CONCEPT IN ms PRODUCTION PLANT NET SALVAGE PROPOSAL?
9 A. Yes. After inconsistently relying on a linear regression analysis for his proposal in this
10 case and obtaining results that lack credibility, Mr. Spanos takes another major
11 inappropriate step. That step is to escalate the results of his regression analysis for net
12 salvage costs into the future until the projected date of retirement. Mr. Spanos relies on a
13 3% inflation factor, which he claims is representative of the Consumer Price Index
14 ("CPI") over the last 40-50 years. 43
15
16 Q. DID MR. SPANOS DISCOUNT THE FUTURE ESCALATED COST BACK TO
17 THE PRESENT PERIOD?
18 A. No. Mr. Spanos believes that the negative net salvage to be reflected in current rates must
19 include the cost to demolish a unit at the time of retirement. 44 In other words, Mr. Spanos
20 proposes to have current customers pay in current dollars for future costs that may have
21 been escalated as many as 3 5 years into the future.
22
23 Q. IS TIDS APPROPRIATE?
24 A. No.
I
~
I
l 43
Deposition of Mr. Spanos on April 20, 2010 at TR 125.
44
Id., at TR 124.
33
l Q. HAVE OTHER COMMISSIONS DENIED REQUESTS FOR INCLUSION OF
2 FUTURE INFLATION IN THE CALCULATION OF PRODUCTION-PLANT
3 NET SALVAGE?
4 A. Yes. Recently, the Oklahoma Corporation Commission ("OCC") denied the identical
5 request in a Public Service of Oklahoma ("PSO") case. 45 Another example is the NPSC
6 in consolidated Docket Nos. 91-5032 and 91-5055. In that case the NPSC stated the
7 following:
8
9 Since NPC has no terminal salvage and cost of removal experience for steam
10 and combustion turbine generating units, Mr. Ferguson [the utility
11 witness] relied on demolition studies of other utilities, adjusted for the
12 expected inflation between the study date and date of removal, in
13 determining his recommended rates ....
14
15 Mr. Pous criticized Mr. Ferguson for applying inflation to the cost of removal
16 or demolition studies without also taking into consideration other factors
17 such as the potential sale of production facilities or increased labor
18 productivity which might impact gross salvage or cost ofremoval....
19
20 Mr. Pous' arguments regarding the unreasonableness of Mr. Ferguson's
21 proposed net salvage factors for Steam Production Plant are persuasive. It
22 is apparent that Mr. Ferguson has selected only a limited number of
23 demolition studies and interpreted them in a manner to suwort his
24 position without adequately considering all factors involved. ... (Emphasis
25 added).
26
27 In another case, the Michigan Public Service Commission ("MPSC") in case No. U9493,
28 a Consumers Power Company case, stated the following regarding the incorporation of
29 future inflation in determining net salvage for production plant:
30
31 The Commission finds that Consumer's arguments must be rejected for
32 several reasons. First, contrary to Consumer's assertions, it is not clear
33 from the Commission's definitions of salvage value and cost of removal
34 that future inflation must be included in the net salvage used to calculate
35 depreciation rates. In fact, a review of those definitions reveals that they
36 are silent on that issue and make no provision for inclusion ofinflation....
37
38 Finally, the Commission also agrees with Staff and ABATE that it is
39 unreasonable to charge current ratepayers for future estimated costs of
40 removal that are escalated for inflation...Although magnifying the costs,
45
OCC Cause No. 200800144.
34
1 Consumer's did not consider future technological changes that might
2 reduce removal costs. For these reasons, the Commission finds that
3 Consumer's proposal is not in the public interest. Future inflation should
4 not be reflected in the terminal net salvage for steam production plant.
5 (Emphasis added).
6
7 The concept underlying net salvage for depreciation purposes is to estimate a reasonable
8 level of net salvage to include in current rates so that current customers will pay their fair
9 share of any such costs. To assume that inflation is the only factor that impacts future
10 cost of removal is simply wrong. Many areas of construction or demolition that entail
11 potentially large costs are subject to technological changes and process improvements.
12 For example, the demolition or toppling of large smoke stacks rather than taking such
13 structures down brick by brick is one improvement. Thus, Mr. Spanos' focus solely on
14 inflation distorts any credible results obtained from the analysis.
15
16 Q. IS THERE ANOTHER SIGNIFICANT REASON WHY INFLATION AS
17 PROPOSED BY THE COMPANY IS INAPPROPRIATE?
18 A. Yes. Current customers should pay their current cost in current dollars. Under ETI's
19 proposal, customers would be forced to pay for future costs established at a future dollar
20 level without any discounting back to current dollar levels. This is simply not a logical
21 conclusion and is not an accepted practice in utility ratemaking. For example, when
22 future inflation is taken into account in the establishment of external decommissioning
23 fund payments for nuclear plants, not only is an inflation or escalation rate included in the
24 overall calculation, but an earnings or discount rate is included as well. The earnings or
25 discount rate is included in order to recognize time value of money that occurs between a
26 dollar being spent or invested today and a dollar spent or invested at some point in the
I 27 future. ETI's total failure to recognize a discount rate is a fatal flaw in its proposal.
28
~ 29 Q. WHAT DO YOU RECOMMEND FOR PRODUCTION PLANT NET SALVAGE?
30 A. I recommend a zero (0)-level of net salvage for steam production plant as a conservative
I 31 position. The Commission may find it appropriate to adopt a positive 5% or greater level
32 of net salvage for steam generating facilities in recognition of: (1) the significant increase
I 33 in scrap metal prices that have occurred during the last 5-7 years due in part to the
34 significant growth by the economies of China and India; and/or (2) recognition of
35
l potential total sale of generating unit, or partial sale of used equipment as operable
2 equipment, rather than a sale as scrap value.
3
4 Q. DID MR. SPANOS CONSIDER THE POTENTIAL THAT A POSITIVE NET
5 SALVAGE COULD BE OBTAINED EVEN THROUGH A DEMOLITION
6 PROCESS?
7 A. No. Mr. Spanos stated that he "would be very surprised that there is much of a market for
8 someone to come in and buy it [a generating unit] for the scrap value and consider that to
9 be more than the cost they will have to dismantle it when they have eventually walked
10 away from that site.'.46
11
12 Q. ARE YOU AWARE OF A RECENT SITUATION WHERE A DEMOLITION
13 CONTRACTOR PAID TO TAKE DOWN A POWER PLANT?
14 A. Yes. Just last year the King Power Plant in Ft. Pierce, Florida was being demolished.
15 Even though the cost estimator developed a study that estimated a substantial cost to
16 demolish, the winning bid to demolish the plant was a negative $974,000. In other words,
17 a contract offered to lli!Y almost $1 million to get the salvageable equipment and scraps
18 material while demolishing the plant. The winning bid also included substantial costs for
19 the removal of asbestos at the old plant. 47
20
21 Q. COULD TIDS BE A SITUATION WHERE A CONTRACTOR WAS JUST OUT
22 OF LINE WITH ms ESTIMATE?
23 A. No. In fact, there were four bids where contractors were willing to lli!Y between $250,000
24 and $600,000 for the right to demolish the plant.48
25 Q. IS THERE AN AFTER MARKET FOR EQUIPMENT THAT WAS DESIGNED
26
27 A.
FOR OLDER POWER PLANTS?
Yes. For example, the city of Traverse, Michigan, recently retired the 1940s vintage
I
28 Bayside generating station. As part of the demolition, a sugar cane grower from Central
46
Deposition of Mr. Spanos on March 25, 2010 in PUCT Docket No. 37690 at TR 91.
47
Several conversations with Mr. John Tompeck, Capital Project Engineer for the Ft. Pierce Utilities Authority.
48
Several phone conversations with John Tompeck Project Engineer for the King Generation plant demolition
plant for the Ft. Pierce Utility Commission, Ft. Pierce, Florida.
36 I
I
1 America came, dismantled the boiler and other equipment, and shipped it to Central
2 America for on his sugar cane plantation.49 Moreover, when investor owned utilities
3 demolish power plants, usable items are sold or transferred rather than scrapped.
4
5 Q. ARE YOU AWARE OF OTHER EVIDENCE THAT EQUIPMENT AT
6 DEMOLISHED POWER PLANTS CAN AND HAVE BEEN SOLD RATHER
7 THAN CONSIDERED USABLE ONLY FOR SCRAP VALUE?
8 A. Yes. A presentation was made at a decommissioning conference regarding Florida
9 Power & Light Company's ("FPL") Palatka decommissioning project. One of the slides
10 in that presentation clearly notes under the heading Salvage/Sale that the
11 turbine/generator for Unit 1 at that station was sold.so 1bis fact was confirmed by FPL's
12 decommissioning documents. In spite of an active "after market" for power plant
13 equipment, when it comes to presenting a proposal, Mr. Spanos believes that selling
14 pieces of equipment is unlikely because there are so many requirements as to perfectly
15 matching equipment.st In contrast to this false assumption, he is more than willing to
16 offer negative 15% to 32% values without any underlying support.
17
18 Q. HOW HAVE THE ECONOMIES OF CHINA AND INDIA IMPACTED
19 DEMOLITION COST ESTIMATES?
20 A. The dramatic expansion of these economies has resulted in substantial upward pressure
21 on scrap metal prices. Prices for scrap copper are now over $3.00 per pound, while in the
22 early 2000s the price was more in the $0.40 price per pound range. Indeed, ETI admits
23 that it obtained $0.5039 per pound for scrap iron in 2008 while it was only able to obtain
24 $0.0621 per pound back in 2003.s2 Since the demolition of a power plant produces large
25 quantities of copper, steel and other metals, the gross salvage associated with the sale of
26 scrap metal can exceed the cost of demolition.
49
Web article at http://www.tclp.org/news_details.php?id=l22, and discussions with Traverse City electric
department personnel.
so Response to AXM 6-93 in PUCT Docket No. 35763.
51
Deposition of Mr. Spanos on March25, 2010 at TR 89.
52
Response to Rose City 1-34.
37
1 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
2 A. On a standalone basis my recommendation results in an $11. 7 million reduction in annual
3 depreciation expense based on plant as of December 31, 2008.
4 5. Mass Property Life
5 A. Introduction
6 Q. WHAT IS THE PURPOSE OF THE LIFE PORTION OF A DEPRECIATION
7 ANALYSIS?
8 A. The purpose of a life analysis is to determine the "average service life" or ASL, the
9 dispersion pattern and remaining life for each account or subaccount. This information is
10 necessary to properly perform the depreciation calculation. A longer ASL results in a
11 longer remaining life and therefore a lower depreciation expense. Alternatively, a shorter
12 ASL will reduce the remaining life and increase depreciation expense. The dispersion
13 pattern is also important, as it is critical in the overall selection process of the best fitting
14 results. The same ASL with different Iowa Survivor Curves also results in different
15 remaining lives, due to the remaining expected pattern of retirements.
16
17 Q. WHAT ARE THE MAIN TOOLS UTILIZED IN PERFORMING LIFE
18 ANALYSIS?
19 A. Life analysis is normally performed by actuarial or semi-actuarial analyses. Actuarial
20 analyses rely on aged data. In other words, when an item of property is retired, the age at
21 retirement is known. 1bis is the type of analysis performed by insurance companies
22 when developing life tables in order to establish premiums. Semi-actuarial analyses are
23 performed in instances in which the age of retired plant is not known.
24
25 Q. PLEASE PROVIDE MORE INFORMATION REGARDING HOW A
26 DEPRECIATION ANALYST PERFORMS SUCH A LIFE ANALYSIS THAT
27 RELIES ON AN ACTUARIAL APPROACH.
28 A. Aged data is gathered and analyzed. Aged data means that when an asset retires in 2008
29 we know that it originally went in service in 1968, and was 40 years old at the time of
30 retirement. When all the aged data in a group is statistically analyzed by actuarial
38
1 techniques a resulting Observed Life Table or OLT is developed that depicts the rate of
2 retirement over the life of the group. The OLT starts at 100% surviving and declines
3 from there as each year of age is obtained and retirements occur. Naturally, not all units
4 retire at once; instead, the retirement dates are dispersed through time, creating a
5 "dispersion pattern." In order to permit testing and smoothing of the results some
6 standard or index must be used. The principal tool that a depreciation analyst uses for
7 this aspect of the study is a set of "survivor curves." The industry standard and most
8 extensively used curves are called the Iowa Survivor Curves. The name is derived from
9 the fact that they were developed at Iowa State College in the 1930s.
IO
11 Often, the historical data base analyzed does not yield a complete OLT, one that fully
12 declines to 0% surviving. This means that the data set will produce an incomplete OLT
13 or a "stub curve." Also, the limited data base may include atypical or abnormal events
14 not reasonably anticipated to occur again during the remaining life at the same levels
15 reflected in the historical data.
16
17 The Iowa Survivor Curves are based on empirical studies of retirement "behavior" of
18 physical property. They are designed to predict the retirement patterns of the property
19 under study based on detailed past observations. The Iowa Survivor Curves make the
20 calculation of the ASL far more manageable and comparable; instead of making and
21 weighting a myriad of individual calculations that include each data point in the universe,
22 the analyst measures the area below the curve and uses an established equation or
23 standard curve to "solve" for the ASL. And, even ifthe data set is incomplete-which is
24 often the case -by properly choosing a closely fitting curve to the known data, the
25 analyst can better predict the behavior of the entire universe and calculate the ASL with
26 reasonable statistical accuracy, if a meaningful "stub curve" exists. The results of any
27 estimation are more reliable if 70% of an OLT is known and only 30% must be assumed,
28 than if only 10% of the OLT is known and 90% must be assumed.
29
30 Not surprisingly, choosing the survivor curve that provides the best fit to the data is
31 critical to the accuracy of the analysis. When fitting the curves to the OLT the analyst
32 must bear in mind that some data points-those that occur on the points of the graph that
39
1 reflect the most significant level of plant exposed to retirement events-- are more
2 important to the determination of the ASL and dispersion pattern than others. Further,
3 the analyst cannot use the curves in isolation of other considerations. The analyst must
4 incorporate such things as knowledge of the nature of the property being studied, an
5 understanding of the causes of unusual events, recognition of changes or trends, and
6 judgment when using the curves. Also, the nature of survivor curves limits their
7 usefulness. For instance, they are best suited to studies of homogeneous items that,
8 because of their physical similarity and common exposure to retirement forces, can be
9 expected to share common retirement characteristics. (By analogy: When an insurance
10 actuary performs a mortality/longevity study for life insurance purposes, the actuary does
11 not combine people and horses in the universe of data.) It is for that reason that I
12 criticized ETI's analyst for inappropriately applying the Iowa Survivor Curves to interim
13 retirements for generation plant. The items of generation plant involved in interim
14 retirements frequently are far from homogeneous.
15
16 Q. HAVE YOU REVIEWED THE COMPANY'S MASS PROPERTY LIFE
17 ANALYSES?
18 A. Yes, I have reviewed the Company's mass property life analyses. The main problem
19 with the analyses is that Mr. Spanos proposes ASLs with corresponding Iowa Survivor
20 Curves that are not the best fitting results for the actuarial analyses, even when the final
21 proposal is based on actuarial results. Mr. Spanos' selections for most accounts reflect a
22 bias toward artificially short ASLs. It is unreasonable and inappropriate to ignore the
23 best fitting life analyses without detailed and credible explanations. Mr. Spanos fails to
24 provide support for his questionable practice.
25 Q. BASED ON YOUR REVIEW OF THE COMPANY'S LIFE ANALYSES AND
26 OTHER INFORMATION, ARE YOU RECOMMENDING ADJUSTMENTS?
27 A. Yes. I recommend adjustments to 16 accounts or subaccounts. The recommendations, as
28 well as the Company's proposals for each of the accounts where a change is
29 recommended, are set forth in the table below.
40
MASS PROPERTY LIFE SUMMARY
ETI Cities Difference based
Proposed Recommended on Plant as of
12/31/2008
Account Descrintion ASL Curve ASL Curve
ASL Imnact53
350 Transmission Land Rights 65 R4 95 R4 30 $183,605
353 Transmission Station Equipment 45 R2.5 52 R2.5 7 $1,462,347
354 Transmission Towers 50 S4 63 S4 13 $110,162
355 Transmission Wood & Steel Poles 55 R3 59 R2.5 4 $1,080,733
356 Transmission Overhead Conductors 53 R2.5 55 R2.5 2 $210,829
360 Distribution Land Rights 55 R4 85 R4 30 $120,195
362 Distribution Station Equipment 40 Rl.5 46 so 6 $783,405
365 Distribution Overhead Conductors 36 R0.5 39 S0.5 3 $1,103,876
366 Distribution Underground Conduit 50 R2 60 R3 10 $182,339
368 Distribution Line Transformers 29 so 32 L0.5 4 $1,478,940
369 Distribution Services - Overhead 27 L4 31 R3 4 $1,159,669
390 General Structures & Improvements 44 R2.5 53 R2 9 $299,763
391.2 General Information Systems 5 SQ 10 SQ 5 $1,423,792
394 General Tools, Shop & Garage 15 SQ 20 SQ 5 $187,514
397 .1 General Communication Equipment 10 SQ 15 SQ 5 $167,904
397.2 General Communication Equipment 15 SQ 20 SQ 5 $1,136,473
Microwave
53
Impact estimated based on change in ALG remaining life due to ELG calculation by ETI.
41
1 The combined impact of the various adjustments I recommend results in a standalone
2 impact of an $11,091,546 reduction to annual depreciation expense, based on plant as of
3 December 31, 2008. 54
4 Q. HOW ARE THE ULTIMATE LIFE-CURVE SELECTIONS MADE?
5 A. From an actuarial standpoint, the best fitting life-curve selections are made by visually
6 matching the OLT to standardized Iowa Survivor Curves. Mathematical curve fitting is
7 flawed when it assigns an equal level of significance to each point in the matching
8 process. Indeed, Mr. Spanos' admits that even though he does perform mathematical
9 curve fitting as a part of his analysis, he does not "view that to be the proper way to do
10 life analysis."55
11
12 Q. IN THE VISUAL MATCH PROCESS, ARE ALL POINTS OF COMPARISON
13 EQUAL?
14 A. No. Many of the points of comparison for an OLT may reflect dollar levels of exposures
15 that differ by a factor of 10,000 or more. Indeed, Mr. Spanos also notes, but does not
16 adequately implement in his analysis, that a "significant portion" of the curve exists as it
17 relates to the curve matching process. 56 In other words, the "head" or top of the curve and
18 possibly middle portions of the curve are more significant in the curve fitting process
19 than is the "tail" of the curve.
20
21 Q. IN THE CURVE FITTING PROCESS, IS IT MORE IMPORTANT TO MATCH
22 THE POINTS ON THE OLT THAT REFLECT LARGER DOLLAR LEVELS OF
23 EXPOSURES THAN THOSE POINTS WHERE THE DOLLAR LEVEL IS
24 MUCH LOWER?
25 A. Yes. It would be foolish to accept the results of a standardized life-curve that better fits
26 the results of the end or "tail" of the OLT rather than a life-curve combination that is a
27 better fit near the "head" or top and upper portions of the OLT. While it is desirable to
28 have close fitting results all along the OLT, this unfortunately does not occur for many
S4 Id.
ss Deposition of Mr. Spanos on April 25, 2010 at TR l 12.
s6 Direct Testimony of Mr. Spanos at page 34.
42
l accounts. Therefore, recognition of the dollar level of exposures at different points of the
2 OLT is critical.
3 This is significant, since as each new year of plant activity transpires, the OLT can and
4 usually does change. However, the future changes will not occur equally to all portions
5 of the OLT. In fact, it is unlikely, given the level of exposures near the "head" or top of
6 the OLT, that the few years between depreciation studies would result in any appreciable
7 movement of that portion of the OLT absent unusual events. The same cannot be said of
8 the "tail" portion of the OLT, and potentially even the mid portion of the curve. If larger
9 retirements transpire in older age intervals, or more dollars of exposures filter further
10 down in the OLT without corresponding retirements, the mid portion or tail of the OLT
11 can move significantly, based on only a few years of additional data. That is precisely
12 why matching the "head" and other significant portions of the OLT is more important
13 than matching the ''tail."
14
15 B. Account Specific Adjustments
16
17 Account 350.2
18
19 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 350.2 -
20 TRANSMISSION LAND RIGHTS?
21 A. The Company proposes a 65-year ASL with a corresponding R4 dispersion pattern. 57
22
I 23 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
24 A. This is one of the accounts where Mr. Spanos based his proposal on judgment, the nature
I 25 of the plant and equipment, the previous estimate for this Company and a general
26 knowledge of service lives of similar equipment in other utilities. 58
I
57
Exhibit JJS-1 page 52.
58
Exhibit JJS-1 page 36.
43
1 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
2 A. No. The Company's proposed 65-year ASL is artificially short. Land rights for
3 transmission lines are difficult to obtain. The "not in my backyard" (''NIMB") syndrome
4 is stronger than ever as it relates to new transmission right-of-way locations. Therefore,
5 utilities will continue to rely on existing transmission land rights into the future absent
6 unusual circumstances. In addition, all transmission right-of-ways remain in place until
7 the utility releases its right to the land.59 Thus, the land rights can easily be in place for
8 multiple life cycles of the equipment that rests upon such land rights. Indeed, the
9 Company's proposed ASL for this account represents a period shorter than a single
10 maximum life cycle for the equipment that resides upon the land right. This is illogical on
11 its face. In other words, the Company proposes a 53-R2.5 life-curve combination for
12 Account 356 - Transmission Overhead Conductors & Devices. The maximum life, a
13 complete life cycle, for an investment with this life-curve combination is in excess of 95
14 years. Yet the Company proposes an ASL for easements of only 65 years.
15
16 Q. HOW MANY EASEMENTS HAS THE COMPANY RETIRED IN ITS
17 RECORDED IDSTORY?
18 A. None. The Company does not report a single retirement during the 50 years of retirement
19 activity reflected in its study. 60
20
21 Q. WHAT DO YOU RECOMMEND?
22 A. I recommend a 95-R4 life-curve combination. This ASL is conservative as it corresponds
23 approximately to only one maximum life cycle for overhead conductors and devices.
24 Obviously, additional investment has and will continue to be placed into service on the
25 same right-of-ways in the future, thus requiring an extension of my recommended ASL at
some point in the future.
26
I
59
Response to Rose City 13-5.
60
Exhibit JJS-1 pages 86 and 87.
44
1 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
2 A. My recommendation of a 95-year ASL on a standalone basis results in a $183,605
3 reduction in depreciation expense based on plant in service as of December 31, 2008.
4
5 Account 353
6
7 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 353 -
8 TRANSMISSION STATION EQUIPMENT?
9 A. The Company proposes a 45-R2.5 life-curve combination. 61
10
11 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
12 A. This is an account where Mr. Spanos did not rely to any extent on the statistical analysis
13 he performed on the historical data. 62 This is an account where Mr. Spanos relied on his
14 standard statement of judgment, nature of the plant, previous estimates, and similar lives
15 for other electric companies. 63
16
17 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
18 A. No. The Company's proposal understates the realistic life expectancy for this account;
19 therefore, I recommend a 52-R2.5 life-curve combination as a better representation of the
20 life expectancy for this investment.
21
22 Q. WHAT IS THE BASIS FOR YOUR RECOMMENDATION?
23 A. First, the historical actuarial analysis does provide some useful information. While Mr.
24 Spanos apparently discounted the Company specific activity, it is clear that the Company
25 has substantial levels of investment that have already exceeded the Company's proposed
I 26
27
short ASL. Indeed, a better curve fit to the meaningful or significant portion of the data
indicates that a longer ASL is a better representation of the historical data than is the
I 28
29
Company's proposed 45-year life. In fact, as shown in the graph below, the 52-year ASL
I recommend is a superior fit to the Company's data.
61
Exhibit JJS-1 page 52.
62
Exhibit JJS-1page33.
63
Id., at page 34.
45
ENTERGY TEXAS
353-TRANSMISSION STATION EQUIPMENT(1984)
100
90
(f)
0:: ....c:
g Q)
....
(.)
80
>
0::
Q)
a.
:::>
(f)
70
60
0.5 8.5 16.5 24.5 32.5 40.5 48.5
4.5 12.5 20.5 28.5 36.5 44.5 52.5
AGE (YEARS)
Actual 52R2.5 __..,_ 45R2.5
I In addition, the Company's historical data reflects retirement activity associated with
2 recent hurricanes, thus resulting in an artificially short life indication even based on the
3 Company's actuarial analysis. Next, a review of Mr. Spanos' industry database indicates
4 that a longer ASL is warranted than the 45-year value he proposed. In fact, the mean,
5 median and mode for his industry database all exceed 45 years, even when taking into
6 account some unusually low values associated with cooperatives or old studies reflected
7 in that database. 64 Mr. Spanos' notes also support something longer than a 45-year ASL.
8 For example, Mr. Spanos' notes associated with substations specifically state "about 50
64
Response to Rose City 1-1 7 Attachment.
46
I
years. " 65 Indeed, the notes further identify the Company has a policy of cradle to grave
2 accounting for its transformers, which should have indicated a longer ASL compared to
3 the industry average since many utilities actually retire transformers when they move
4 such equipment from one location to another. In addition, while Mr. Spanos' notes
5 indicate that there is an expectation for a shorter lives in the future for transformers, this
6 is an argument that has been utilized in the industry for the past 20 or 30 years, yet the
7 industry has demonstrated increasing life expectancy for substation equipment as more
8 empirical data has been obtained. Therefore, the 52-year ASL is more indicative of the
9 Company's actual experience, better reflects industry expectations, and is more
10 representative of the type of equipment in the account.
11
12 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
13 A. My recommendation of a 52-year ASL on a standalone basis results in a $1,462,347
14 reduction to depreciation expense based on plant in service as of December 31, 2008.
15
16 Account354
17
18 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 354 -
19 TRANSMISSION TOWERS?
20 A. The Company proposes a 50-S4 life-curve combination. 66
21
22 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
23 A. This is an account where the historical data is not relied upon and Mr. Spanos reverts to
I 24
25
his generalized statement referring to judgment and other information.
26 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
27 A. No. I recommend a 63-S4 life-curve combination.
I
I 65
Response to Rose City 1-15 Addendum page 46.
66
Exhibit JJS-1 page 52.
47
1 Q. WHAT IS THE BASIS FOR YOUR RECOMMENDATION?
2 A. First, while the historical data provides an extremely short "stub curve", it does provide
3 an indication for a long ASL given the very limited level of retirement activity that has
4 transpired during over 50 years of data. 67 In addition, Mr. Spanos' industry database
5 indicates a mean, median and mode of 63, 65 and 65 years, respectively. 68 Indeed, the
6 industry data that would have formed possibly a major portion of Mr. Spanos'
7 'judgment" indicates that the use of a 50-year or lower ASL is very limited. Therefore,
8 all indications of available data indicate that a value in the mid 60-year range is by far
9 superior to the Company's proposed 50-year ASL. Moreover, the Company proposed a
10 55-year ASL for Account 355 - Transmission Poles. On a predominant basis, the
11 industry recognizes that transmission towers have longer expected ASLs than do
12 transmission poles. In this case, Mr. Spanos also failed to take this relationship into his
13 judgmental decision making process.
14
15 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
16 A. My recommendation of a 63-year ASL on a standalone basis results in a $110,162
17 reduction to depreciation expense based on plant as of December 31, 2008.
18
19 Account 355
20
21 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 355 -
22 TRANSMISSION POLES AND FIXTURES?
23 A. The Company proposes a 55-R3 life-curve combination. 69
24
25 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
26 A. This is another account where Mr. Spanos claims to have relied on the statistical actuarial
27 results. 70
67
Exhibit JJS-1pages99 and 100.
68
Response to Rose City 1-17 Attachment.
69
Exhibit JJS-1page52.
70
Exhibit JJS-1 page 33.
48
1 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
2 A. No. The Company's proposal is artificially short; therefore, I recommend a 59-R2.5 life-
3 curve combination.
4
5 Q. WHAT IS THE BASIS FOR YOUR RECOMMENDATION?
6 A. As shown in the graph below, my recommendation results in a better fit to the OLT in the
7 significant portion of the curve that Mr. Spanos referenced in his testimony. Indeed, Mr.
8 Spanos sacrificed a better fitting relationship during periods beginning around age 8 years
9 in order to strive for a better match during the age intervals of approximately 25 years
10 through 35 years. The problem with Mr. Spanos' election to discount the earlier portion
11 of the curve in an effort to match a later portion of the curve sacrifices exposures in the
12 $40-$70 million range for better fitting exposures in the $15-$40 million range. 71 As can
13 be seen in the graph be]ow, my recommendation is a superior fit during the first
14 approximate 24 years of age.
I
71
Exhibit JJS-1pages104-105.
49
ENTERGY TEXAS
355 - TRANSMISSION POLES AND FIXlURES (1954)
100
90
en
a:::
0
>
-
c::
Q)
....
(.)
~ Q)
0...
::::>
en 80
70
0.5 8.5 16.5 24.5 32 .5 40.5 48.5
4.5 12.5 20.5 28.5 36.5 44.5 52.5
AGE (YEARS)
Actual 59R2. 5 __..._ 55R3
1 In addition, Mr. Spanos' notes indicate that new poles are steel and concrete, thus
2 indicating a longer life expectancy in the future than reflected in the historical data,
3 which reflects a higher level of wood poles. While Mr. Spanos reflected such information
4 in his notes, he apparently failed to take that into consideration in his undocumented
5 decision making process. 72 Otherwise, he would have proposed a longer ASL. Thus, from
6 a curve-fitting process, and taking into account the limited additional information
7 provided by the Company, a longer ASL than the 55-year life proposed by the Company
8 is warranted. Analysis of historical data and supplemental information better supports a
9 59-year ASL.
72
Response to Rose City 1-15 Addendum at page 46.
50
I
1
2 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
3 A. My recommendation for a 59-year ASL on a standalone basis results in a $1,080,733
4 reduction to depreciation expense based on plant in service as of December 31, 2008.
5
6 Account 356
7
8 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 356 -
9 TRANSMISSION OVERHEAD CONDUCTORS?
10 A. The Company proposes a 53-R2.5 life-curve combination. 73
11
12 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
13 A. For this account, the Company relies on Mr. Spanos' claim relating to a good to excellent
14 indication from the statistical analyses. 74
I 15
16 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
I 17 A. No. The Company's proposal understates the realistic ASL for this account. Therefore, I
18 recommend a 55-year ASL with a corresponding R2.5 Iowa Survivor Curve. As shown in
19 the graph below, both Mr. Spanos' proposal and my recommendation are both good fits
20 of the data for approximately the first 27 years of age. At that point the Company's
21 proposal begins to deviate from the OLT until approximately 35 years of age and
22 understates the expected ASL. Thus, both curves are good fits through the most
23 significant portion of the curve, but the longer ASL continues the good fit through most
I 24
25
of the remaining portion of the OLT including portions of the curve that are still
significant. Another consideration for a somewhat longer ASL is that to the extent any
I 26
27
retirement activity associated with major hurricanes that occurred in recent periods is
reflected in the Company's data, it would understate the expected ASL for the remaining
l 28
29
investment. Therefore, a modest increase from what the Company has proposed in the
expected ASL is warranted at this time.
73
Exhibit JJS-1 page 52.
74
Id., at page 33.
51
ENTERGY TEXAS
356 - TRANSMISSION OVERHEAD CONDUCTORS AND DEVICES (1954)
100
90
C/)
a:
0
...c:
> Q)
,_
0 80
>
a:
Q)
a..
::>
C/)
70
60
0.5 8.5 16.5 24.5 32.5 40.5 48.5
4.5 12.5 20.5 28 .5 36 .5 44.5 52.5
AGE (YEARS)
Actual __..._ 55R2. 5 -6--- 53R2. 5
1 Q. WHAT IS THE IMP ACT OF YOUR RECOMMENDATION?
2 A. My recommendation for a 55-year ASL results in a $210,829 reduction to the Company' s
3 annual depreciation expense based on plant in service as ofDecember 31, 2008.
4 Accounf 360
5
6 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 360 -
7 DISTRIBUTION LAND RIGHTS?
8 A. The Company proposes a 55-R4 life-curve combination. 75
75
Exhibit JJS-1 page 51.
52
I Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
2 A. Given that there have been no retirement activity reflected in the Company's historical
3 database, this is an account where the Company relied on judgment and other undefined
4 parameters.
5
6 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
7 A. No. The same situation as discussed for Account 350 - Transmission Land Rights also
8 pertains to Distribution Land Rights. The Company's selection would have land rights
9 retiring long before the end of a single life cycle is reached for various other distribution
10 accounts. Thus, on its face, the Company's proposal is illogical. Therefore, I recommend
11 a 85-R4 life-curve combination, taking into account land rights must exist for at least one
12 complete life cycle relating to the investment that resides upon it. As time passes this
13 estimate will have to be expanded in recognition that retirements will not occur as
14 additional new plant is placed on the same land rights and that new investment must also
15 complete its life cycle.
16
17 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
18 A. My recommendation for an 85-year ASL results in a $120,195 reduction in depreciation
19 expense based on plant as of December 31, 2008.
20
21 Account 362
22
23 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 362 -
I 24
25 A.
DISTRIBUTION STATION EQUIPMENT?
The Company proposes a 40-Rl.5 life-curve combination. 76
I 26
27 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
I 28
29
A. This is an account where the Company relied on what appeared to be a good to excellent
statistical indication from its statistical analysis of historical data. 77
76
Exhibit JJS-1page53.
77
Id., at page 34.
53
1 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
2 A. No. The Company's proposed ASL is too short for the investment in this account.
3 Therefore, I am recommending a 47-Rl life-curve combination.
4
5 Q. WHAT IS THE BASIS FOR YOUR RECOMMENDATION?
6 A. A review of the historical OLT identifies two significant retirement periods that appear to
7 be out of line. In particular, the Company experienced its second highest retirement level
8 during the age interval of zero (0) to 0.5 year. 78 It is unusual to have such significant
9 levels of infant mortality in comparison to older aged equipment. Indeed, the vast
IO majority of this infant mortality incurred in 1954. 79 No other infant mortality of this
11 magnitude has transpired in the subsequent 54 years. Therefore, proper judgment should
12 have recognized this event as an outlier and normalized it in the database. The reality is
13 that utilities, absent unusual events, are not expected to purchase and install equipment
14 that is expected to fail immediately upon installation to any great extent. Thus, the
15 Company's historical OLT reflects an artificial reduction at an early time frame given
16 that such data is being used as a predictive tool for future expectations.
17 The largest level of retirement activity during any age interval occurred beginning at age
18 interval 6.5 years. 80 This annual level of retirement activity is approximately ten times the
19 level of retirement activity in the age intervals immediately preceding or following.
20 Again, this is the type of activity that should have caused an analyst to question the
21 validity of the resulting OLT as a basis for projecting future expectation for the remaining
22 investment. Indeed, this single age bracket yielded the highest retirement ratio through
23 the first 70 years of age.81 The impact of this single age bracket produced an atypical and
24 noticeable decline in the OLT as set forth in the graph in the Company's depreciation
25 study. 82 Events of this magnitude warrant further investigation, yet Mr. Spanos'
26 testimony, exhibits, workpapers and site visit notes make no reference to any specifics
27 regarding this retirement activity. Based upon further investigation it has been determined
78
Exhibit JJS-1 page 126.
79
Response to Rose City 13-7.
80
Exhibit JJS-1page126.
81
Id., at pages 126-127.
82
Id., at page 125.
54
I
I that $4.8 million of the $5.4 million was a retirement during age interval 6.5 years and
2 relevant to a 8MVA stored magnetic energy superconductor unit located at a substation.
3 The Company could not provide any support for why a retirement of this magnitude for
4 this type of equipment is expected to reoccur on a similar basis in the future. 83 Therefore,
5 the impact of what is a single, but large, unusual event should have been normalized in
6 the Company's analysis. Indeed, Mr. Spanos, who claims constant reliance on judgment,
7 apparently failed to even recognize that his own database of other utilities would have
8 indicated that his proposed 40-year ASL for this account was well below the mean,
9 median or mode for his industry range. 84 This discrepancy between ETI and the industry
10 should have resulted in this transaction being adjusted prior to the curve fitting process
11 had proper judgment been employed.
12
13 As set forth in the graph below, I have normalized only the outlier at the 6.5 age
14 interval. 85 As can be seen, my recommended 46-SO life-curve combination is a superior
15 or equal fit to all data points when compared to Mr. Spanos' proposal. Moreover, my
16 recommendation better matches Mr. Spanos' industry data and is consistent with the
17 cradle to grave type accounting employed by the Company for transformers and other
18 major equipment at substations, as identified in Mr. Spanos' site visit notes. 86 My
19 recommendation is conservative given the fact that the curve matching process still
20 incorporates atypical hurricane activity that should have also been normalized.
I
I
I
83
Response to Rose City 1-2 13-18.
84
Response to Rose City 1-16 Attachment even prior to the elimination of obvious outliers in Mr. Spanos' own
database.
' as Reflects 1979-2008 Experience band to address infant mortality issue.
86
Response to Rose City 1-15 Addendwn at pages 46 and 48.
55
ENTERGY TEXAS
362 - DISTRIBUTION STATION EQUIPMENT (Normafized)
100
90
en
g-
a:: 80
c::
Q)
0
>
a:: a.
~
Q)
::::> 70
en
60 I
50
0.5 8.5 16.5 24.5 32.5 40.5 48.5 56.5 64.5
4.5 12.5 20.5 28 .5 36.5 44.5 52.5 60.5
AGE (YEARS)
Actual 46R1.5 __..__ 40R1.5
1 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
2 A. My recommended 46-year ASL results in a $783,405 reduction to annual depreciation
3 expense based on plant as of December 31, 2008.
Account 365
4
5
I
6
7
Q. WHAT DOES THE
DISTRIBUTION OVERHEAD CONDUCTORS?
COMPANY PROPOSE FOR ACCOUNT 365 -
I
8 A. The Company proposes a 36-R0.5 life-curve combination. 87
1
87
Exhibit JJS-1page53.
56
I
2 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
3 A. This is an account where the Company relied heavily on the results of its statistical
4 analysis. 88
5
6 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
7 A. No. The Company's proposal is artificially short. Therefore, I recommend a 39-S-0.5 life-
8 curve combination. The Company's historical data included $2.8 million of unusual
9 retirement activity in the age interval 0.5 that occurred in 2008, the year in which
10 Hurricane Ike hit. 89 The retirement activity at age intervals 0.5 is significantly greater
11 than any other time frame and is atypical in nature. Therefore, at a minimum, the OLT
12 would need to be normalized for such activity. As shown in the graph below, my life-
13 curve combination is a better match to the historical data minimally for the first 30 years,
14 and then again beginning at approximately 44 years of age. If the remaining retirements
15 associated with recent hurricane activity were also removed from the data, it would raise
16 the OLT and make my recommendation even a better fit than set forth in the graph
17 below.
I
I
I
' 88
89
Id., at page 34.
Response to Rose City 13-11.
57
ENTERGY TEXAS
365- DISTRIBUTION OVERHEAD CONDUCTORS & DEVICES (Normalized)
100
:-..
90
~~ ~
80
~
70 ~~
Cl)
0:: ~
~
..,
.+J
0 cQ) 60
> e
6;
::::>
Cl)
Q)
a.. 50
40
30
' .....
~
~ ~
20
~~ a_
~
10 111 111 111 111 Ill 111 Ill 111 111 111 111 111 111 111 ~~ JUI 111 111 111
0.5 8.5 16.5 24.5 32.5 40 .5 48.5 56 .5 64.5
4.5 12.5 20.5 28.5 36.5 44.5 52.5 60.5
AGE (YEARS)
I Actual - - - 398-0.5 ___._ 36R0.5
I
1 Other considerations supporting a longer ASL are the fact that the only item of
2 information referenced by Mr. Spanos in his site notes was that if poles go down,
3 conductors may not be damaged and thus still in use. 90 All else equal, this would imply
4 that an ASL for conductors should be approximately as long as poles, if not longer. It
5 should be noted that my 39-year ASL recommended for conductors is one year shorter
6 than what Mr. Spanos has recommended for poles. Finally, a review of Mr. Spanos'
7 industry data would indicate that even a 39-year ASL is on the shorter side of life
8 expectancy. Thus, in conjunction with my life recommendation, the Commission should
9 also order the Company to perform a detailed analysis to normalize the impacts of major
1O hurricanes that occurred in the 2005 through 2008 era for use in the next depreciation
90
Response to Rose City 1-15 Addendum at page 49.
58
1 study. Overall, my recommended 39-year ASL is conservative, considering actual
2 historical data even before normalization for all hurricane activity.
3
4 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
5 A. My recommendation for 39-year ASL results in a $1,103,876 reduction in depreciation
6 expense based on plant as of December 31, 2008.
7
8 Account 366
9
IO Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 366 -
11 DISTRIBUTION UNDERGROUND CONDUIT?
12 A. The Company proposes a 50-R2 life-curve combination. 91
13
14 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
15 A. This is an account where the Company did not rely on the statistical analysis it
16 performed, but rather relied on unidentified judgment and other factors. 92
17
18 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
19 A. No. First, it must be noted that the existing ASL for this account is 60 years. Thus, the
20 Company is proposing a 10-year reduction based on undefined judgment. A review of the
21 data indicates unusually high levels of retirement activity at low age intervals, without
22 any explanation. 93 Substantial amounts of these early age retirements are associated with
23 underground plastic conduit and pads for transformers. These are not the type of
I 24
25
investments that one would normally anticipate retiring at early ages, absent unusual
circumstances. Moreover, industry experience would indicate that even a 50-year ASL is
26 artificially short. Indeed, Mr. Spanos' industry data, which is skewed with several very
94
27 short lives, still yields mean, median and mode values of approximately 55-60 years.
28 There is no logical explanation or documentation presented by the Company that
91
Exhibit JJS-1 page 53.
92
Id., at page 34.
93
Response to Rose City 13-12 through 13-15.
94
Response to Rose City 1-17.
59
1 warrants a reduction from the existing 60-R3 life-curve combination. Therefore, I
2 recommend retention of the existing ASL, which is more in line with the type of
3 investment reflected in this account.
4
5 Q. WHAT IS THE IMP ACT OF YOUR RECOMMENDATION?
6 A. My recommended 60-year ASL results in a $182,339 reduction to depreciation expense
7 based on plant as of December 31, 2008.
8
9 Account 368
10
11 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 368 -
12 DISTRIBUTION LINE TRANSFORMERS?
13 A. The Company proposes a 29-SO life-curve combination.95
14
15 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
16 A. For this account the Company relied on what it believed to be a good or excellent
17 statistical fit for the historical data. 96
18 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
19 A. No. The Company's proposal results in one of the shortest ASLs for any utility in the
20 industry. Therefore, at a minimum, I recommend increasing the ASL to 32 years with a
21 corresponding L0.5 Iowa Survivor Curve.
22
23 Q. WHAT IS THE BASIS FOR YOUR RECOMMENDATION?
24 A. First, a 31-L0.5 life-curve combination represents as good a fit to the OLT as does the
25 Company's proposal. Indeed, given the type of investment and other considerations, a 31-
26 L0.5 life-curve combination is a more realistic expectation for the investment in this
27 account. However, some of the other items of information exist that require some
28 additional level of increase in ASL. Those other items of information are the existing
29 ASL, the impact of hurricane related retirements, and industry information. The existing
95
Exhibit JJS-1 page 53.
96
Id., at page 34.
60
1 ASL for this account is 39 years, thus the Company is proposing a value 10 years shorter
2 than the existing level. Even if this was a reasonable prediction, which it is not, a degree
3 of gradualism may be warranted.
4
5 More significant to the concept for a longer ASL than proposed by the Company is the
6 fact that the Company has included significant retirement activity associated with
7 hurricane-related recent events. Normalization of the data to remove hurricane activity
8 would result in raising the OLT from its current position, thus resulting in a longer ASL.
9 Indeed, just removing the 2008 retirement activity for ages 0.5 year through 5.5 years,
10 corresponding to just the 2002-2007 vintage additions, increases the "head" or top
11 portion of the survivor curve by approximately 0.6 of a percentage point. This level of
12 increase is meaningful.
13
14 In addition, Mr. Spanos states in his site visit notes that the Company has historically
15 overloaded its line transformers. This is not a typical practice for an extended period of
16 time and thus, future life expectancy should be longer than that experienced historically. 97
17 Yet another consideration is the fact that Mr. Spanos' industry database indicates that a
18 29-year ASL would be basically at the extreme low end of the industry range. Even
19 retaining the unusually low values in Mr. Spanos' database, the mean, median and mode
20 would all be in the upper 30 to 40 year range, or more in line with the existing ASL.
21
22 Some minimal increase in the ASL above the 31-year ASL (that is as good a fit to the
23 historical data as is the Company's proposal) is warranted in light of industry data, the
24 Company's inappropriate historical actions of overloading transformers, the existing
25 ASL, and the inclusion of hurricane activity in the historical data. Therefore, I am
I 26
27
recommending a minimal incremental increase of one additional year as a conservative
estimate in favor of the Company. I further recommend that the Commission order the
I 28
29
Company to demonstrate the prudence of its continued operation of transformers above
maximum ratings, or that it is no longer performing such unusual activity, by the time it
30 files its next depreciation study.
97
Response to Rose City 1-15 Addendum at page 49.
61
1 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
2 A. My recommendation for a 32-L0.5 life-curve combination results in a $1,478,940
3 reduction to depreciation expense based on plant in service as of December 31, 2008.
4
5 Account 369
6
7 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 369 -
8 DISTRIBUTION SERVICES?
9 A. The Company proposes a 27-U life-curve combination for both underground and
10 overhead services. 98
11
12 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
13 A. This is one of the accounts where Mr. Spanos relied extensively on his actuarial analysis
14 for his proposal. 99
15 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
16 A. No. A 29-year ASL represents basically the shortest ASL in Mr. Spanos' industry
17 database of approximately 60 values. The only few values that are lower correspond to a
18 Canadian utility, a cooperative and a utility that has not had its proposed ASL tested in a
19 fully litigated proceeding. 100 Moreover, the historical data relied upon by Mr. Spanos
20 incorporates the impact of recent severe hurricane activity, which helps produce the
21 proposed artificially short ASL.
22
23 Q. WHAT DO YOU RECOMMEND?
A.
24
25
I recommend a very conservative estimate of a 31-year ASL with an R3 Iowa Survivor
Curve. Initial review of Mr. Spanos' proposal raises concern from not only the short ASL
I
26 standpoint, but also from the standpoint of the unusual "L4" dispersion pattern. Mr.
27 Spanos' database of other utilities indicates a 40-45 year ASL is indicative of average
98
Exhibit JJS-1 page 53.
99
Id., at page 34.
100
Response to Rose City 1-17.
62
J
1 industry expectations. 101 In other words, the industry indicates a longer ASL than the
2 existing 36-year level, definitely not a reduction to the 27-year level as proposed by the
3 Company. Next, review of Mr. Spanos' industry database further raises concern
4 regarding the proposed "L4" Iowa Survivor Curve. In this existence, Mr. Spanos'
5 judgment relating to what he has observed from the industry and the type of plant in this
6 account should have resulted in further investigation. Indeed, not a single other industry
7 value relies on "L4" dispersion, or for that matter any "L" pattem. 102
8
9 Another consideration that is not addressed by Mr. Spanos is the movement towards more
10 underground rather than overhead services. As reaffirmed by Mr. Spanos' industry
11 database, underground services are generally expected to have a longer ASL than
12 overhead services. l03 The percent investment in underground services has grown faster
13 than for overhead services in the last I 5 years. 104 This fact should have also indicated a
14 longer ASL. Finally, the fact that the Company's data includes hurricane related
15 retirements further demonstrates that a longer ASL than indicated by the OLT is
16 appropriate.
17
18 In order to remain conservative, I am recommending splitting the difference between the
19 existing 36-year ASL and the 27-year ASL proposed by the Company, which yields a 31-
20 year ASL. Such a value still leaves the Company at the very low end of the industry
21 range, well below industry averages, and the existing ASL. I also recommended a "R3"
22 Iowa Survivor Curve, which corresponds to the most frequently used curve in Mr.
23 Spanos' database. In conjunction with my ASL recommendation, I further request that
I 24
25
the Commission order the Company to provide a detailed analysis as to why its historical
database gives indications of artificially short ASLs and what portion of such lower ASLs
I 26 is due to the inclusion of recent hurricane related activity.
101 Id.
r 102 Id.
103 Id.
104
I Exhibit JJS-1 pages 289-291.
63
1 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
2 A. My recommendation for a 31-R3 life-curve combination results in a $1,159,669 reduction
3 to depreciation expense based on plant as of December 31, 2008.
4
5 Account 390
6
7 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 390 - GENERAL
8 PLANT STRUCTURES AND IMPROVEMENTS?
9 A. The Company proposes a 44-R2.5 life-curve combination. 105
10
11 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
12 A. The Company relies on the results of its statistical actuarial analysis for this account. 106
13
14 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
15 A. No. This is an account that requires special investigation. This account varies throughout
16 the industry because some utilities only rent facilities and have leasehold improvements
17 reflected in this account, while other utilities own the actual structure including the
18 interior components as well as roofs and other systems. The life expectancy for leasehold
19 improvements is much shorter than the life expectancy of an entire office building or
20 warehouse that is owned rather than leased. ETI owns most of its buildings. 107
21
22 Q. WHAT DO YOU RECOMMEND?
23 A. I recommend a 53-R2 life-curve combination as a conservative value. First, it must be
24 noted that a dramatic decline in the OLT as set forth on Exhibit JJS-1 page 176 is a result
25 of an internal decision by the Company to retire, for accounting purposes only, a portion
26 of its corporate headquarters. The investment in that building was subsequently
27 transferred to non-utility plant. In other words, the facility was not actually retired, but
28 reflects an accounting transaction between the regulated and non-regulated portions of
105
Exhibit JJS-1page53.
106
Id., at page 34.
107
Response to Rose City 1-41.
64
l the Company's business. 108 This type of transaction is atypical and should not negatively
2 affect current customers through the depreciation process. Relying on the remainder of
3 the OLT, but eliminating this unusual transaction, would require a substantial increase in
4 ASL.
5
6 In addition, the majority of the investment in this account is associated with office
7 buildings and other structures that the Company owns rather than leases. 109 Office
8 structures, warehouses and similar facilities can normally have life expectancies
9 approaching 75 to 100 years or more. Taking into account that the investments still
10 require a replacement of air conditioning systems, roofs and others components would
11 reduce the dollar-weighted ASL. Mr. Spanos' industry database indicates numerous
12 ASLs for investment in this account that still exceed 50 and even 60 years. In addition,
13 Mr. Spanos' site visit notes state that buildings are generally "concrete slab with steel
14 structures on top."uo Steel buildings on concrete slabs can easily be expected to achieve
15 50 or even 60 years on a dollar-weighted basis. Therefore, my recommended 53-year
16 ASL is conservative in favor of the Company.
17
18 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
19 A. My recommended 53-R2 life-curve combination results in a $299,763 reduction to
20 depreciation expense based on plant as of December 31, 2008.
21
22 Account 391.2
23
24 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 391.2 - GENERAL
25 INFORMATION SYSTEMS?
26 A. The Company proposes a 5-SQ life-curve combination, or a 5-year amortization
27 period. 111
I 108
109
110
Response to Rose City 13-18.
Response to Rose City 1-41.
Response to Rose City 1-15 Addendum at page 149.
111
Exhibit JJS-1 page 53.
65
I Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
2 A. Mr. Spanos establishes the amortization period based on the anticipated life of the asset
3 over which benefits will be realized. u 2 The amortization period is based on ''judgment
4 which incorporates a consideration of the period during which the assets will render most
5 of their service, the amortization period and service lives used by other utilities and the
6 service life estimates previously used for the asset under depreciation accounting." 113
7
8 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
9 A. No. The Company's proposal is artificially short; therefore, I recommend a IO-year
I0 amortization period. First and foremost, this is an account where the Company has
11 already experienced an acceleration of amortization expense given that many vintages are
12 already fully accrued, yet the plant is still in service. 114 What is clear is the 5-year
13 amortization clearly understates the expected useful life of the facility. Moreover, Mr.
14 Spanos' has failed to provide any judgmental basis that would render a 5-year
15 amortization period for this investment as realistic and appropriate.
16
17 Another consideration that recognizes the understatement of amortization period is Mr.
18 Spanos' reference to the period during which the asset will "render most of their service."
19 Service life or amortization period is not intended to capture "most" of the service life of
20 an asset, but the entire service life of the asset. Even if the "most" standard were
21 appropriate, Mr. Spanos has understated the reasonable amortization period for the
22 majority of the expected life. In addition, my recommend I 0-year amortization period is
23 consistent with what is the existing rate approved by the Commission in Docket No.
24 16705. Mr. Spanos' proposal cuts the existing IO-year amortization period in half. It is
25 therefore inappropriate from the standpoint of his stated basis. In addition, review of Mr.
26 Spanos' industry database further supports the use of the IO-year amortization period
27 rather than the proposed 5-year amortization period. In fact, the majority of the values
28 reported for information software systems in Mr. Spanos' database are IO years. No
112
Exhibit JJS-1 page 46.
113 Id.
114
Exhibit JJS- l page 302.
66
information software system was assigned a 5-year value in Mr. Spanos' database.
2 Indeed, other utilities are employing values up to 15 years for major customer
3 information software systems. Therefore, my recommendation to retain the existing 10-
4 year amortization period is conservative and complies with Mr. Spanos' stated basis for
5 his judgmentally derived proposal.
6
7 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
8 A. My recommendation to retain the existing 10-year life would result in a $1,423,792
9 reduction to amortization expense based on plant as of December 31, 2008. In addition, a
10 remaining life annual amortization rate should be set at 7. 7%.
11
12 Account 394
13
14 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 394 - GENERAL
15 TOOLS, SHOP & GARAGE EQUIPMENT?
16 A. The Company proposes a 15-year amortization period. 115
17
18 Q. WHAT IS THE COMP ANY'S BASIS FOR ITS PROPOSAL?
19 A. The Company's basis is the same as identified as above for Account 391.2.
20
21 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
22 A. No. The Company's amortization period is artificially short. Therefore, I recommend a
23 20-year amortization period for the investment in this account. First, it must be noted that
24 the existing depreciation life for the investment in this account is 20 years. Thus, Mr.
25 Spanos obviously did not rely on this particular item of information for his judgmental
26 approach even though it is one of the stated bases. Next, the investment in this account is
27 at the point of reaching the 15-year proposed amortization period, thus ifthe amortization
28 period is not extended the Company would be recovering through base rates a fully
29 recovered investment that has not been retired. 116
115
Exhibit JJS-1 page 53.
116
Id., at page 306.
67
1 The second item considered by Mr. Spanos referenced in his testimony is what other
2 utilities are using. Again, Mr. Spanos' proposed 15-year amortization period falls short of
3 his own industry database. Indeed, the predominant value Mr. Spanos reflects in his
4 industry database is 25 years, with very few utilities employing something less than 20
5 years. 117 Thus, Mr. Spanos' claim of reliance on service lives used by other utilities is
6 contrary to his artificially short proposed amortization period.
7
8 Relying on the parameters, which form the basis of Mr. Spanos' judgmental approach,
9 would require a conservative estimate of a 20-year amortization period, with a possibly
10 more appropriate level of 25 years. However, in order to remain conservative, I am
11 recommending the retention of the existing 20-year life.
12
13 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
14 A. My recommendation for a 20-year amortization period results m a reduction in
15 amortization expense of $187,514 based on plant as of December 31, 2008. In addition, a
16 remaining life rate should be set at 4.12%.
17
18 Account 397.1
19
20 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 397.1 - GENERAL-
21 COMMUNICATION EQUIPMENT?
22 A. The Company proposes a 10-year amortization. 118
23
24 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
25 A. The Company's basis for this account is identical as to that noted for Account 391.2.
117
Response to Rose City 1-17.
m Exhibit JJS-1 page 53.
68
1 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
2 A. No. In this case, the proposed amortization period is artificially short. Therefore, I
3 recommend a 15-year amortization as a conservative value. A review of the Company's
4 actual historical data identifies that the use of the 10-year amortization period will begin
5 allowing the Company to more than fully accrue the investment in this account. 119 In fact,
6 as of now, portions of the Company's original cost are over-amortized. Turning to Mr.
7 Spanos' industry database, one would also find that my recommended 15-year
8 amortization period is by far more prevalent than any other value reported. 120 Relatively
9 few utilities in Mr. Spanos' database utilize amortization periods as low as 10 years. 121
10 Another consideration for recommending a 15-year amortization period is the fact the
11 existing combined Account 397 life expectancy is 19 years, as approved in Docket No.
12 16705. Therefore, given the fact that Account 397.2 corresponds to microwave
13 equipment, one might expect a shorter life span for the remaining investment reflected in
14 Account 397.1, but not to a level of only 10 years as proposed by Mr. Spanos.
15
16 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
17 A. My recommendation for a 15-year amortization period results in a reduction of $167,904
18 based on plant as of December 31, 2008. The resulting amortization remaining life rate
19 for the investment is 5.72%.
20
21 Account 397.2
22
23 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 397.2-GENERAL
24 COMMUNICATIONS EQUIPMENT-MICRO WAVE?
25 A. The Company proposes a 15-year amortization period. 122
~ 26
27 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
28 A. The Company's basis is the same as previously stated for Account 391.2.
119
Id., at page 309.
120
Response to Rose City 1-17.
121
Response to Rose City 1-17.
122
Exhibit JJS-1page53.
I 69
I
1 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
2 A. No. Again, the Company's proposal is artificially short. Therefore, I recommend a 20-
3 year amortization period for the investment in this account. First, it must be noted that the
4 existing life expectancy for this account is 19 years, as set in Docket No. 16705. Given
5 that this account is now segregated between microwave equipment and remaining
6 communication equipment, and the fact that the remaining communication equipment has
7 a lower overall life, the life expectancy for microwave equipment should be greater than
8 the existing 19-year time frame. Therefore, this portion of Mr. Spanos' stated judgmental
9 basis supports a longer amortization period than what he has proposed.
10
11 Turning to industry data, Mr. Spanos only identifies one utility with an equivalent sub-
12 account identification. 123 That utility is Chugach Electric Association, which reported a
13 15-year period. This is a generation cooperative in the Anchorage, Alaska area.
14 Amortization of microwave equipment subject to the weather conditions in Alaska can
15 reasonably be assumed harsher than reflected in the lower 48 states. Therefore, from a
16 judgmental basis associated with industry information, Mr. Spanos should have proposed
17 a longer amortization period.
18
19 Finally, the most important aspect of the need for a longer amortization period is the fact
20 that almost half of the investment in this account is already fully accrued using a 15-year
21 amortization period. 124 The Company has substantial levels of investment that was placed
22 in service back in 1983 through 1985. In addition, substantial levels of additional
23 investment are at the point where they will become fully accrued (a form of accelerated
24 depreciation) if the 15-year amortization period is adopted. Therefore, I recommend a
25 minimum 20-year amortization period. In addition, I recommend that the Commission
26 order the Company to correct its reserve associated with any account that is fully accrued
27 and recognize the additional depreciation or amortization that should have been booked.
28 The Company's failure to comply with normal regulatory requirements to continue to
29 apply approved depreciation rates to all gross plant in service is inappropriate. The
123
Response to Rose City 1-17.
124
Exhibit JJS-1 page 310.
70
1 Company cannot be allowed to unilaterally and arbitrarily decide to cease the booking of
2 amortization or depreciation when it believes that an account is fully accrued.
3
4 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
5 A. My recommendation for a 20-year amortization period results in a reduction in
6 amortization expense of $1,136,473 based on plant as of December 31, 2008. In addition,
7 my recommendation results in an amortization rate of 1.67%.
8 6. Mass Property Net Salvage
9
10 Q. WHAT ISSUE DO YOU ADDRESS IN TIDS PORTION OF YOUR
11 T ESTIMONY?
12 A. I will address the Company's request for a significant increase in revenue requirements
13 associated with more negative net salvage for the Company's mass property plant
14 accounts. After review of the underlying information I recommend retention of the
15 existing net salvage levels.
16
17 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
18 A. The Company claims to have relied upon a 5-year historical database for its analyses. 125
19 Mr. Spanos claims he performed his analysis "based on common depreciation accounting
20 practices and judgment." 126 Mr. Spanos further stated that for many of the accounts, the
21 analyses of the 5 years of historical data did not produce conclusive results, therefore
22 judgment and industry averages were a major factor for those accounts. 127 Mr. Spanos
23 admits that for approximately 60% of the depreciable plant he based his proposal on
24 judgment and comparison with other utility information. 128
125
Exhibit JJS-1 pages 188-207 and Direct Testimony of Mr. Spanos at page 22.
126
Direct Testimony of Mr. Spanos at page 22.
127 ld.
128
Exhibit JJS-1 page 37.
71
1 Q. DID MR. SPANOS PROVIDE ANY DETAILED INFORMATION BY ACCOUNT
2 INms TESTIMONY OR DEPRECIATION STUDY THAT WOULD IDENTIFY
3 HOW HE SPECIFICALLy ARRIVED AT ms PROPOSED vALUES FOR EACH
4 INDIVIDUAL MASS PROPERTY ACCOUNT?
5 A. No, other than a partial explanation for Account 365 used as an example in his 2008
6 Study. 129 This is one of the accounts where Mr. Spanos claims he relied heavily on the
7 statistical information derived from his 5-year database. Even for this account, Mr.
8 Spanos admits that the cost of removal fluctuated quite a bit throughout the 5-year period
9 and that such fluctuations "were a result of storms that forced higher labor costs for
10 removing assets." 130 (Emphasis added). Mr. Spanos then compared the 5-year average to
11 the range of what other electric companies estimated for this account. However, when his
12 comparison with the industry data pointed out that ETI's 5-year average of a negative
13 50% was not only outside the industry range but was also more than double the midpoint
14 of the range employed by other utilities, Mr. Spanos then concluded that the historical
15 statistical analysis was adequate, taking into account the "conditions of the region." 131
16 Thus, Mr. Spanos' single narrative example added confusion rather than clarity given that
17 he totally disregarded his own industry data even though for Account 352 he did the
18 opposite and ignored the Company's actual historical data and relied on industry data for
19 what he viewed as appropriate. 132 Thus, we are left with a very generalized stated criteria,
20 a less than explanative or supported example, and then inconsistent actions with no
21 explanation. This leaves a situation where the Company has presented nothing of
22 substance as the basis for its mass property net salvage proposals.
23
24 Q. IS THE 5-YEAR DATABASE RELIED UPON BY MR. SPANOS ADEQUATE TO
25 ESTABLISH A REASONABLE INDICATION OF WHAT MIGHT OCCUR IN
26 THE FUTURE?
27 A. No. First it must be emphasized that the 5-year period Mr. Spanos relied on is an
28 exceptionally short timeframe for performing a historical analysis for net salvage
129
Exhibit JJS-1 pages 37 and 38.
130
Id., at page 38.
131 Id.
132
Depreciation of Mr. Spanos on April 20, 2010 at TR 125-126.
72
I
1 purposes. Indeed, Mr. Spanos ·relied on a 16-year period for his identical analysis in the
2 El Paso Electric case filed at the same time before this Commission. Moreover, reliance
3 on only a 5-year database for this type of analysis is anything but a "common
4 depreciation accounting practice" as claimed by Mr. Spanos. Next, Mr. Spanos
5 recognizes that the limited historical database is skewed due to results of storms that
6 forced higher labor costs. What Mr. Spanos glossed over is that these referenced storms
7 are major hurricanes. Indeed, on September 24, 2005 Hurricane Rita hit the area with 120
8 mile per hour winds. On September 13, 2007, Hurricane Humberto hit the area with 85
9 mile per hour winds. Then on September 13, 2008 Hurricane Ike hit the Texas coast with
10 110 mile per hour winds. 133 Thus, in the 5-year period relied upon for indications of the
11 future, the area was hit with at least 3 hurricanes, two of which would be categorized as
12 severe. This compares to only 7 hurricanes hitting the Texas coast at or east of Galveston
13 during the past 38 years. 134 That represents only one hurricane every 5.4 years during the
14 past 38 years compared to Mr. Spanos' database, which reflects such an occurrence once
15 every 1. 7 years. This represents an extremely skewed database. Next, due to the fact that
16 cost of removal and gross salvage may be recorded many years after a retirement is
17 recorded, the lack of time synchronization further diminishes the value of a short 5-year
18 database.
19
20 In addition, it turns out the database relied upon and presented by account does not reflect
21 actual information by account. Only through repeated attempts during discovery was it
22 determined that the account-specific 5-year data relied upon and presented by Mr. Spanos
23 in his 2008 Study represented an unsubstantiated allocation of net salvage values from
24 the functional level. 135 In other words, even in those instances where Mr. Spanos claims
25 to have given some significance to his statistical analysis, the underlying data was not
I 26
27
maintained by account and thus, cannot be assumed to be representative of the accounts.
The Company's database is so flawed not only from the standpoint of timeframe, or the
28 inclusion of major hurricanes, but also in the maintenance of account-specific data.
133
http://www.hurricanecity.com/city/portarthur.htm
134
Texas Hurricane History, National Weather Service.
135
Response to Rose City 1-21.
73
1 Indeed, while Mr. Spanos claims his allocation is "a little more than a gut" feeling, it "is
2 not logged" anywhere and only resides in his head. 136
3
4 Q. ARE THERE ERRORS IN THE COMPANY'S PROCESS OF ASSIGNING
5 FUNCTIONAL VALUES TO INDIVIDUAL PLANT ACCOUNTS?
6 A. Yes. Not only are there reversal of signs (i.e., reporting values as being negative when
7 they should have been positive) in the data, but there are theoretically impossible values
8 reflected in the data. 137
9
10 Q. TURNING TO THOSE INSTANCES WHERE MR. SPANOS DID NOT RELY TO
11 ANY EXTENT ON TIIE CLAIMED. IDSTORICAL STATISTICAL ANALYSIS,
12 DID HE PROVIDE ANY SPECIFIC DOCUMENTED SUBSTANTIATION FOR
13 EACH ACCOUNT?
14 A. No. This is important given that 60% of the investment falls into this category.
15
16 Q. DOES MR. SPANOS CLAIM THAT HE MAINTAINED ALL SUCH
17 INFORMATION SUPPORTING ms BASIS IN ms HEAD?
18 A. Yes. 138 When Mr. Spanos was requested in discovery to produce the items that affected
19 his judgment in a manner that could be verified, he stated that his judgmental process
20 cannot be quantified and therefore provided nothing. Indeed, Mr. Spanos stated that
21 ''there's no log that basically defines what's in my head." 139
22
23 Q. DOES MR. SPANOS PERFORM A NUMBER OF DEPRECIATION STUDIES
24 ANNUALLY?
25 A. Yes. During Mr. Spanos' deposition, he claimed that he performs about 20 depreciation
26 studies per year for the past 24 years. 140 Given that most utilities have dozens of plant
27 accounts means that the amount of detailed information that Mr. Spanos claims to
28 maintain in his head would be quite improbable.
136
Deposition of Mr. Spanos on April 20, 2010 at TR 32-33.
137
Response to Rose City 1-21 Attachment.
138
Deposition of Mr. Spanos on April 20, 2010 at TR 57-58.
139
Id., at TR 57.
140
Id., at TR 58.
74
1
2 Q. WAS MR. SPANOS ABLE TO DEMONSTRATE AN IMPRESSIVE ABILITY TO
3 RECALL SPECIFIC ITEMS OF INFORMATION DURING ms DEPOSITION
4 AS IT RELATES TO SPECIFIC FACTORS IN THE ETI STUDY?
5 A. No, quite the contrary. On any specific item for which Mr. Spanos was requested to
6 provide detailed explanations, he could not recall what specific information might have
7 been given to him from Company personnel or other factors. 141 The only documented
8 items of information that may have impacted Mr. Spanos' judgment is set forth in his
9 limited site visit notes. 142
10
11 Q. HAVE YOU REVIEWED THE SITE VISIT NOTES THAT MR. SPANOS
12 PROVIDED IN DISCOVERY THAT SHOWS THE TOTALITY OF ms
13 DOCUMENTED JUDGMENT?
14 A. Yes.
15
16 Q. DID YOU FIND THAT THE SITE VISIT NOTES PRODUCED ADEQUATE
17 SUPPORT FOR THE COMPANY'S NET SALVAGE PROPOSALS?
18 A. No. First, it must be noted that the site visit notes are rather cryptic, at best. Even when
19 the.re are items of information noted, there is no underlying support for any claim. As of
20 this time, the Company has still not provided any underlying support for any of the
21 claims referenced in Mr. Spanos' site visit notes. Moreover, there is generally no
22 connection identified as to how any item of information affected the decision making
23 process for each account. This connection apparently resides only in Mr. Spanos' head
24 and cannot be quantified except when Mr. Spanos actually developed his various
25 proposals.
26
27 Q. PLEASE SUMMARIZE THE COMPANY'S PRESENTATION.
28 A. There are many serious flaws with the Company's presentation for its mass property net
29 salvage proposals. The time frame is too short, the data has been manipulated, the data
141
Id., at TR 106-107 for example.
142
Response to Rose City 1-15.
75
1 includes numerous major hurricanes as though they would continue to occur on an
2 equally frequent basis in the future as they did in the limited 5-year period, the allocated
3 data includes errors, the industry data relied upon is ignored when it interferes with the
4 desired results, or the industry data reflects ranges so wide as to make the industry data
5 meaningless as a valid basis for selection of any given value. Finally, the Company has
6 failed to provide specific support for individual account proposals, even when
7 specifically requested to provide such information. Thus, the interveners and the
8 Commission are left with proposals by account without any discemable basis. The
9 presentation by the Company leaves the parties with a ''take it or leave it" approach to its
10 proposals.
11
12 Q. WHAT DO YOU RECOMMEND?
13 A. Given the Company's presentation and available data, I believe the only realistic option
14 left to the interveners and the Commission is to take up the Company's offer of"take it or
15 leave it." I recommend leaving the existing net salvage proposals in place as the best
16 alternative left at this point and time. I further recommend that the Commission order the
17 Company to develop and justify a net salvage database by account for an historical period
18 of 10 years for its next depreciation study. In addition, the Commission should order the
19 Company to actually present information substantiating its proposals on an account by
20 account basis, including underlying support and documentation and order that the
21 Company's books be maintained in that manner on a going forward basis.
22
23 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
24 A. The standalone impact of my recommendation results in a $10.6 million reduction to
25 annual depreciation expense based on plant in service as of December 31, 2008.
26 7. ELG vs. ALG Calculation Procedure
27
28 Q. WHAT IS THE PURPOSE OF TIDS PORTION OF YOUR TESTIMONY?
29 A. This portion of my testimony addresses the Company's decision to employ the
30 depreciation calculation procedure identified as the ELG procedure.
76
1 Q. WHAT DO YOU RECOMMEND?
2 A. For various reasons, including the change in the underlying data, I recommend reliance
3 on the industry standard ALG calculation procedure.
4
5 Q. HAS TIDS COMMISSION IDSTORICALLY RELIED ON THE ALG
6 PROCEDURE?
7 A. Yes, with the exception of adopting ELG for a limited number of accounts in ETI' s last
8 fully litigated case, Docket No. 16705. For example, in PUC Docket No. 14965 Finding
9 of Fact 95 states that "CPL's depreciation rate should be set using the average life group
10 ("ALG") procedure." This is the typical calculation procedure that I am aware of that has
11 been employed by the Commission in all prior proceedings. Given the change in the
12 underlying data for ETI, even the prior limited acceptance of ELG by the Commission in
13 Docket No. 16705, which was based on superior data, is no longer valid.
14
15 Q. DOES MR. SPANOS ATTEMPT TO IDENTIFY THE DIFFERENCE IN
16 CALCULATION PROCEDURES BETWEEN THE ELG AND ALG
17 PROCEDURE IN ms TESTIMONY?
18 A. Yes. Beginning on page 23 and continuing through 27 of Mr. Spanos' testimony, he
19 provides information comparing ELG and ALG depreciation procedures. I do not agree
20 with certain aspects of Mr. Spanos' presentation. These differences will be discussed later
21 and in Appendix B.
22
23 Q. CAN YOU BRIEFLY STATE WHY THE ELG PROCEDURE IS
I 24 INAPPROPRIATE FOR UTILITY RATEMAKING PURPOSES?
25 A. Yes. The ALG procedure calculates the remaining life on an average investment basis,
26 knowing that the projection will not be accurate for each vintage of additions and every
27 item of plant added within each vintage. Alternatively, the ELG procedure, which also
28 relies on the same less than perfect data and the same assumptions to derive the ASL and
29 dispersion curve, culminates with a calculation of the remaining life that assume that
30 every future year level of retirement is known with absolute precision for as much as 100
31 years into the future. Such a concept of absolute precision when forecasting is illogical on
77
1 its face in the real world of utility operation, and would only be more accurate than the
2 ALG procedure under the infinitesimally small possibility that future events on an annual
3 basis will actually follow a precisely defined pattern, each and every year for the next 50
4 to 100 years. Simply put, the ALG procedure recognizes and reflects reality, while the
5 ELG procedure clings to the presumption of unobtainable theoretical precision. I submit
6 that the probability of that occurring is so remote as to be nonexistent.
7
8 Q. SETTING ASIDE THE TECHNICAL DISCUSSION OF ELG VERSUS ALG FOR
9 NOW, CAN YOU PROVIDE AN EXAMPLE OF THE IMPACT BETWEEN THE
10 TWO PROCEDURES?
11 A. Yes. The remaining life for individual vintage can be compared between the ELG and the
12 ALG procedures when the same ASL and corresponding dispersion curve are employed.
13 For example, for Account 353 - Transmission Station Equipment, Mr. Spanos has
14 proposed a 45-R2.5 life-curve combination. Logically, one would normally assume that
15 brand new plant added into service at mid-year with an expected overall 45-year ASL
16 would have approximately a 44.5-year (45-0.5) remaining life at the end of the first year.
17 The precise value at the end of the first year for the 45-R2.5 life-curve combination is
18 44.53 years under an ALG procedure. However, review of the 2008 vintage addition for
19 ETI identifies a remaining life that is nowhere near the 45-year value for new plant in
20 service at the end of the first year. In fact, Mr. Spanos assigned the 2008 vintage addition
21 a 33.17-year remaining life due to his use of the ELG procedure. In other words, under
22 the ALG process, a 2008 vintage addition has a remaining life approximately 99%
23 (44.5/45) of the ASL when first placed into service, while the same 2008 vintage addition
24 has a remaining life of only 73.7% (33.17/45) of the ASL under the ELG procedure.
25 Approximately one-fourth of the remaining life for the newest vintages is eliminated
26 under the accelerated depreciation calculation of ELG, when compared to the ALG
27 procedure. It is this dramatic difference that is created by the acceleration caused by the
28 ELG calculation procedure that appeals to utilities that seek accelerated capital recovery.
29 Indeed, the overall ELG remaining life for Account 353 is 25.63 years, while the ALG
30 remaining life for the same data is 31.05 years, or 21 % higher. The artificially short ELG
78
remaining life increases annual depreciation expense for this single account by
2 approximately $1.8 million.
3
4 Q. HAVE YOU TESTED THE RELATIONSHIP BETWEEN ACTUAL
5 RETIREMENT ACTIVITY FOR TRANSMISSION ACCOUNT 353 DURING
6 THE PAST 5 YEARS COMPARED TO WHAT WOULD BE ASSUMED
7 THROUGH THE ELG PROCEDURE?
8 A. Yes. In order to demonstrate the false premise relied upon by Mr. Spanos regarding the
9 theoretical precision of the ELG procedure; I tested the ELG proposed relationships
10 against reality for the largest mass property account for the past 5 years. Transmission
11 Account 353 is the largest mass property account and reflects over $370 million of
12 investment as of December 31, 2008. Based on Mr. Spanos' assumed 45-R2.5 life-curve
13 combination, and testing such proposal on an ELG basis for the most recent 5 years
14 (2004-2008), one finds a dramatic difference between the assumed precision in the ELG
15 procedure and actual events. The table below identifies the expected ELG retirement
16 amounts by year for each vintage addition for the years 2004-2008. There are 15
17 expected levels of retirement activity, beginning with 5 values for the 2004 additions,
I 18 then 4 values for the 2005 addition, down to only one value for the 2008 addition.
ELG EXPECTED RETIREMENTS BY VINTAGE ADDITION
Year Addition 2008 2007 2006 2005 2004
2008 $10,225,616 $6,283
2007 $7,404,974 $9,791 $4,550
2006 $25 '744,244 $37,100 $34,040 $15,818
2005 $20,005,825 $31,409 $28,831 $26,452 $12,292
2004 $6,979,660 $12.021 $10.958 $10.058 $9.229 $4.289
Total $96,604 $78,378 $52,329 $21,521 $4,289
19 The following table reflects the actual retirement activity for the vintage additions for the
20 years 2004-2008 and sets forth the errors between the actual retirement activity and what
21 Mr. Spanos' ELG procedure would have assumed.
79
l ACTUAL RETIREMENTS BY VINTAGE BY YEAR
Year 2008 2007 2006 2005 2004
2008 $0.00
2007 $0.00 $0.00
2006 $187.08 $0.00 $0.00
2005 $15,447.35 $0.00 $0.00 $0.00
2004 $0.00 $12.014.15 $0.00 $0.00 $0.00
Total $15,634.43 $12,014.15 $0.00 $0.00 $0.00
ELG Expected $96,604.05 $78,378.39 $52,329.05 $21,521.10 $4,288.58
ELG Error-$ $80,969.62 $66,364.24 $52,329.05 $21,521.10 $4,288.58
ELG Error-% 83.8% 84.7% 100.0% 100.0% 100.0%
2 As can be seen, there are only 3 retirement values out of the potential of 15 values that
3 should have occurred had ELG been an accurate estimator. Moreover, one of the three
4 values that did occur is only a $187.08 at a point in time where the ELG procedure would
5 have expected $37,100 of retirement activity. A review of the data for the largest single
6 account as set forth in the two tables above clearly demonstrates that there is no
7 reasonable precision between the ELG calculation procedure and actual transactions. In
8 fact, for the 5-year period analyzed, the ELG procedure predicted a total of $253,121 of
9 retirements, while only $27,648 of actual retirements occurred, or only 11 % of the
10 expected total. This is precisely why the theory of ELG fails in any attempt to mirror the
11 real world of utility operations.
12
13 Q. ABOVE AND BEYOND THE PRACTICAL FALLACIES OF THE ELG
14 PROCEDURE, ARE THERE SPECIFIC PROBLEMS WITH THE COMPANY'S
15 ELG CALCULATIONS?
16 A. Yes. Mr. Spanos' calculation of ELG values is incorrect. Indeed, Mr. Spanos admits that
17 there appears to be an "anomaly" in his calculations. 143 There is no life-curve
18 combination that could be used in an ELG calculation procedure that would yield any
19 reasonable level of accuracy for the 5-year example above.
143
Deposition of Mr. Spanos on April 20, 2010 at TR 140.
80
1 Q. WHAT WAS THE ANOMALY TO WlllCH MR. SPANOS REFERS?
2 A. On Exhibit JJS-1 at page 258, Mr. Spanos presents his ELG calculation for Account 352
3 - Transmission Structures & Improvements. When asked why the remaining life for the
4 2008 vintage addition of 36.67 years was shorter than the remaining lives for older
5 vintage additions, Mr. Spanos admitted that that was "slightly unusual" and represented a
6 "slight anomaly." 144 Indeed, having a shorter remaining life for the newer vintages is
7 more than a slight anomaly - it is a theoretically impossible situation.
8
9 Q. IS TIDS THE ONLY ANOMALY REFLECTED IN MR. SPANOS' STUDY?
10 A. No. Moreover, the claimed "slight" anomaly grows into a major anomaly in other
I 11 accounts, such as for Account 365. In Account 365 - Distribution Overhead Conductors
12 and Devices, the remaining life for vintage addition 2008 is only 15.13 years, then
13 increases to 18.38 years for the 2007 vintage additions. In fact, as set forth in the table
14 below, the remaining life increases for each vintage addition from 2008 back through
15 2001. The remaining life then decreases for the 2000 addition, but turns around once
16 again and increases for the 1999 vintage addition. Not only do we have a major anomaly
17 in that remaining lives are increasing for older plant addition, but Mr. Spanos' calculation
I 18
19
yields a second theoretical impossibility by increasing - then decreasing - then again
increasing the remaining life as older vintages are analyzed. The remaining life
20 calculation should be a continuous movement in one direction (lower remaining lives for
21 older vintages) and would not, unless there were an error, increase or change directions
22 multiple times.
i44Id.
81
ELG REMAINING LIVES FOR ACCOUNT 365
Vintage Remaining
Year Life Difference
1998 21.65 (0.10)
1999 21.75 0.04
2000 21.71 (0.03)
2001 21.74 0.15
2002 21.59 0.21
2003 21.38 0.31
2004 21.07 0.53
2005 20.54 0.82
2006 19.72 1.34
2007 18.38 3.25
2008 15.13
2 Q. CAN THE COMMISSION RELY ON MR. SPANOS' ELG PRESENTATION
3 EVEN IF IT HAD AN INCLINATION TO ACCEPT AN ELG CALCULATION?
4 A. No. Even if the Commission had an inclination to accept the ELG procedure, it cannot do
5 so because of the inaccurate calculations reflected in the Company's presentation. Simply
6 put, not only is the theory underlying the ELG procedure inappropriate in the real world
7 of utility operations, but also the quantification of ELG results is faulty, thus rendering
8 the Company's ELG presentation in this proceeding fatally flawed and lacking any
9 credibility.
10
11 Q. HAS MR. SPANOS ATTEMPTED TO REVOKE ms USE OF THE WORD
12 ANOMALY IN REFERENCE TO ms CALCULATION PROCEDURE?
13 A. Yes. In response to Rose City 24-38, Mr. Spanos attempts to claim that his use of the
14 word anomaly was not a reference to an error in his program. Mr. Spanos attempts to
15 divert attention from his theoretically impossible results by: (1) indicating that the
16 anomaly might be associated with the mid-year convention; (2) discussing the composite
17 remaining life calculation rather than the vintage remaining life values; and (3) claiming
18 the vintage remaining life is calculated by dividing the future accruals by the annual
19 accruals by vintage. In other words, he claims that the remaining life is not a function of
20 the ASL and dispersion pattern combination, but rather a calculation of dividing future
82
1 accrual values by annual accruals. Mr. Spanos concludes his response by claiming that
2 the 2008 vintage remaining life being shorter than the 2007 vintage remaining life "is not
3 truly an anomaly, but a refinement of the annualized rate."
4
5 Q. IS THERE ANY VALIDITY TO MR. SPANOS' CLAIM REGARDING THE MID-
6 YEAR CONVENTION AS A BASIS FOR ms ANOMALY-REFINEMENT?
7 A. No. As noted in the table above for Account 365 and as reflected in numerous accounts,
8 the anomaly-refinement occurs for many vintages including the most current vintage to
9 which Mr. Spanos claims the half-year convention has an additional impact. The half-
10 year impact for the most current vintage is already addressed when an ASL and
11 corresponding dispersion pattern are selected. Simply put, Mr. Spanos' reference to the
12 half-year convention is misleading and disingenuous.
13
14 Q. DOES MR. SPANOS' DISCUSSION OF THE COMPOSITE REMAINING LIFE
15 CALCULATION SHED ANY LIGHT ON ms CLAIMED ANOMALY-
16 REFINEMENT?
17 A. No. Again, his reference to the composite remaining life is an attempted diversion from
18 the real issue, which is his claimed anomaly-refinement associated with individual
19 vintage remaining lives. It is theoretically impossible to have increasing remaining lives
20 for older vintages. The vintage remaining life calculation is the issue at hand, not the
21 composite remaining life. Mr. Spanos is well aware of the distinction and thus, his data
22 response represents yet another distortion.
23
24 Q. IS THERE ANY BASIS IN MR. SPANOS' CLAIM THAT THE VINTAGE
25 REMAINING LIFE IS CALCULATED BY DIVIDING THE FUTURE
26 ACCRUALS BY THE ANNUAL ACCRUALS BY VINTAGE?
27 A. No. The vintage remaining lives are a function of the ASL and the corresponding
28 dispersion pattern. The vintage remaining lives are used to develop the annual accruals by
29 vintage. This process is accomplished by taking the future accruals (the total amount still
30 remaining to be recovered) and dividing it by the vintage remaining life, in order to
31 obtain the annual accruals by vintage, not the other way around as Mr. Spanos claims.
83
1 Even if Mr. Spanos did work backwards and developed the annual vintage accruals first,
2 he would still need to rely implicitly on the vintage remaining lives derived from the
3 proposed life-curve combination. All such life-curve combinations must yield declining
4 remaining lives for older vintages unless there is an error.
5
6 Q. CAN YOU FIND THE IDENTICAL ASL AND DISPERSION PATTERN FOR
7 DIFFERENT ACCOUNTS IN MR. SPANOS' PRESENTATION?
8 A. Yes. For example, Accounts 369.1 and 369.2 - Distribution Overhead and Underground
9 Services, respectively, have the same ASL and dispersion pattern. 145 The original cost,
10 calculated reserve, allocated book reserves and future accruals are different for every
11 single vintage between the two accounts. The one thing that is constant, since it is derived
12 from the same ASL and dispersion pattern, are the vintage remaining lives. In fact, they
13 are identical down to the hundredth of a decimal place as would be expected as they are
14 derived from the same ASL and dispersion pattern. IfMr. Spanos would have us believe
15 that the remaining life factors were not derived from the ASL and corresponding
16 dispersion pattern, but rather by taking the resulting annual accruals by vintage and
17 dividing those into the future book accruals by vintage and thus, deriving the remaining
18 life, then the potential of coincidence that they would produce the identical remaining life
19 values by vintage to one hundredth of a percent value would be astronomical. Thus, Mr.
20 Spanos' own depreciation study clearly refutes his claim.
21
22 Q. IS THERE YET ANOTHER COMBINATION OF ACCOUNTS FOR WHICH
23 MR. SPANOS PROPOSES THE SAME ASL AND DISPERSION PATTERN?
24 A. Yes. Mr. Spanos proposed the same 40-S0.5 for distribution Account 364 - Poles,
25 Towers and Fixtures, as well as Account 373.2 - Non-Roadway Lighting. 146 Due to the
26 unusual manner in which Mr. Spanos' procedure artificially limits the allocation of book
27 reserve to a maximum of the original cost less net salvage, Account 373.2 only reflects I
28 one vintage remaining life, that being for the 2008 vintage. However, that vintage
29 remaining life for Account 372.2 is, again, identical to the corresponding 2008 vintage
145
Exhibit JJS-1page289-291.
I
146
Exhibit JJS-1 pages 276-278 and page 298.
84 I
I
1 for Account 364 down to the one hundredth of a decimal point level of accuracy. Again,
2 the possibility of another coincidence of this situation is so remote as to defy credibility.
3 Simply put, Mr. Spanos' attempt to divert attention from his anomaly, which is an error,
4 and claim that it is a refinement of the annualized rate is disingenuous. The real answer is
5 Mr. Spanos has a problem in his calculation procedure and refuses to admit to such
6 problem by employing deception in his explanative response to request for information
7 Rose City 24-38.
8
9 Q. WAS MR. SPANOS REQUESTED TO PROVIDE A NARRATIVE
IO EXPLANATION ALONG WITH NUMERICAL EXAMPLE AND ALL ACTUAL
11 FORMULAS ASSOCIATED WITH HIS ELG COMPUTER PROGRAM THAT
12 DEMONSTRATES HOW THE ANOMALY COULD OCCUR FOR CERTAIN
13 ACCOUNTS?
14 A. Yes. 147 However, Mr. Spanos failed to provide a single formula or numerical example
15 that supports the validity of his claimed refinement.
16
17 Q. WHAT DO YOU RECOMMEND?
18 A. I recommend the utilization of the standard industry practice of the ALG calculation
19 procedure. The ALG procedure is consistent with the overall process of depreciation,
20 which is based on analysis of numerous averages or broad brush approaches, recognizing
21 that historical indications and other information will only provide, at best, a reasonable
22 indication of what may transpire in the future on average. There will always be errors
23 between future projections and what actually transpires on an annual basis in the future;
24 however, the ALG procedure minimizes such error, while the ELG procedure maximizes
25 such error. Moreover, the ALG procedure is a standard straight-line approach, while the
26 ELG procedure represents an acceleration of capital recovery when compared to the
27 standard industry approach.
147
Response to Rose City 24-44.
85
1 Q. IS THERE ADDITIONAL SUPPORT FOR WHY THE COMMISSION SHOULD
2 NOT RELY ON THE FAULTY ELG PROCEDURE?
3 A. Yes. Given the extensive and technical nature of the problems to be addressed with the
4 ELG procedure, I have attached Appendix B to my testimony, which addresses in further
5 detail problems with the ELG procedure.
6
7 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION TO RELY
8 EXCLUSIVELY ON THE ALG CALCULATION PROCEDURE?
9 A. The standalone impact of relying on the ALG calculation procedure for mass property
10 plant accounts results in a $19.3 million reduction in annual depreciation expense based
11 on plant as of December 31, 2008.
12 8. Remaining Life Method
13
14 Q. WHAT DOES THIS PORTION OF YOUR TESTIMONY ADDRESS?
15 A. This portion of my testimony addresses the Company's remaining life calculation.
16
17 Q. WHAT DO YOU RECOMMEND?
18 A. I recommend relying on the industry standard remaining life calculation.
19
20 Q. DOES MR. SPANOS CLAIM THAT HE IS NOT PROPOSING A CHANGE
21 FROM THE REMAINING LIFE METHOD OF DEPRECIATION?
22 A. Yes. Mr. Spanos states that on page 13 of his direct testimony. However, what he fails to
23 note is that the remaining life method he employs is different from the remaining life
24 previously used and employed by basically all other utilities and depreciation consultants
25 other than those utilities for which Gannett Fleming performs depreciation analyses. In
26 other words, using the identical data the remaining life calculation process previously
27 employed by the Company would produce a different remaining life in every instance
28 when compared to the new remaining life calculation process proposed by Gannett
29 Fleming.
86
Q. WHAT IS THE DIFFERENCE BETWEEN THE STANDARD REMAINING LIFE
2 CALCULATION AND THE NEW CALCULATION PROPOSED BY GANNETT
3 FLEMING?
4 A. Gannett Fleming incorporates the impact of net salvage into the remaining life
5 calculation. Thus, a change in the net salvage will result in a change to the composite
6 remaining life for an account. This is illogical and inappropriate on its face.
7
8 Gannett Fleming's approach allocates the book reserve to individual vintage additions,
9 but not on a consistent basis. Gannett Fleming further deviates from the standard
10 approach by capping the level of accrued depreciation to the maximum level of the
11 original cost plus the impact of net salvage. Thus, a plant account that has a 5-year ASL
12 assigned to it, but has plant in service still at an age of 15 years would not reflect the
13 over-depreciation that occurred during the additional 10 years of service. Gannett
14 Fleming's approach artificially caps the level of reserve assigned to a vintage and spreads
15 the balance to other vintages. Given that Gannett Fleming's approach relies on a dollar
16 weighting of remaining life by vintage, that approach modifies the results of the standard
17 remaining life calculation.
18
19 Q. HAS TIDS ISSUE BEEN LITIGATED RECENTLY?
20 A. Yes. In a recent case in Florida in which the decision was rendered at the beginning of
21 2010, the FPSC stated in its order for the FPL that:
22
23 For the reasons explained below, we are of the opinion that FPL's calculation
24 of remaining life leads to questionable results. Accordingly, we approve of
25 remaining life calculation based on using the average age of the given
26 account, with the selected survivor curve. The remaining lives we approve
27 below are based on this calculation.
28 ***
29 We do not agree with FPL that its remaining life calculation is consistent with
30 FPL' s actual practice. FPL does not maintain its plant account reserves be
I 31
32
vintage; they are maintained on a total account basis. Also, depreciation rates
are not applied to individual vintages; the rates are applied to the total account
33 balance. Allocating the book reserve to individual vintages based on a
I 34
35
theoretical reserve calculation is not necessarily a concern. However, in its
allocation, FPL determined that the reserve for any given vintage could not
I 87
1 exceed the survivors for that vintage less net salvage. For example, in
2 reviewing the calculation presented for Account 396. l, Power Operated
3 Equipment, no reserve was allocated to the 1986-2000 vintages because the
4 allocation of the reserve indicated that these vintages were fully accrued. That
5 is because the most allocated to any given vintage was the surviving
6 investment for that vintage less net salvage. These vintages represent more
7 than 36 percent of the plant account investment. We believe this is a
8 significant amount of investment that has no remaining life. Looking at
9 Account 396.8, Other Power Operated Equipment, FPL uses an L0.5 Iowa
10 curve and 9-year life combination. The average age of the account is 7.5
11 years. Using the method endorses by OPC, the remaining life of the account is
12 5.2 years, compared to the Company's calculation of zero. While this account
13 has an existing reserve surplus, that should not deter from the fact that it does
14 indeed have a remaining life using FPL's proposed curve and life
15 combination.
16
17 FPL did not dispute that net salvage impacts its calculation of remaining life.
18 Net salvage impacts the remaining life depreciation rate, not the average
19 remaining life itself. 148 Unfortunately, because FPL's calculation assumes that
20 no vintage can have more reserve allocated than the surviving investment less
21 net salvage, as net salvage varies, so does the remaining life. For all the
22 foregoing reasons. FPL' s remaining life calculation leads to questionable
23 results. Accordingly, the remaining lives we address below are calculated by
24 applying the average age of the account to the selected survivor curve. This is
25 similar to OPC's calculation of remaining life and PEF's calculation in its
26 depreciation study in Docket No. 090079-EI. The remaining lives we approve
27 below use this calculation. 149
28
29 In other words, after a fully litigated analysis of the remaining life calculation, the FPSC
30 found that it could not rely on Gannett Fleming's remaining life calculation since it
31 produces questionable results and is affected by changes in net salvage.
32
33 Q. WHAT DO YOU RECOMMEND?
34 A. In each instance where I have recommended a change in the life or dispersion pattern for
35 a mass property account or where I have proposed an ALG calculation procedure, I have
36 employed the standard remaining life calculation that all other depreciation consultants
37 employ other than Gannett Fleming. My calculation is the same calculation that the
38 Company previously employed prior to retaining Gannett Fleming.
148
Remaining Life Rate= (100-Net Salvage-Reserve)/Average Remaining Life. Rule 25-6.0436(l)(e), F.A.C.
149
Order No. PSC-10-0153-FOF-EI in Docket Nos. 080677-EI, 090130-EI at pages 26 and 27.
88
1
2 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
3 A. The impact of my recommendation is reflected in the standalone mass property life
4 recommendations and the standalone ALG calculations. Finally, the correct calculation is
5 reflected in the combined impact adjustments set forth in my testimony.
6 SECTION III: FULLY ACCRUED DEPRECIATION
7
8 Q. WHAT DO YOU ADDRESS IN THIS PORTION OF YOUR TESTIMONY?
9 A. I address the Company's action to cease the booking of depreciation in instances where
10 an account or sub-account is unilaterally assumed to be fully accrued.
11
12 Q. WHO HAS THE AUTHORITY TO CHANGE DEPRECIATION OR
13 AMORTIZATION RATES?
14 A. The adoption of depreciation or amortization rates rests solely with the regulator, not with
15 the Company. This regulatory principal is essential in order to protect customers from
16 inappropriate action that a utility might take. For example, if a utility had the unilateral
17 right to change its depreciation rates as desired, it would be in the best interest of the
18 utility's shareholders to immediately reduce or cease the booking of depreciation expense
19 after the end of a rate case. If such practice were allowed, the utility would still recover
20 the depreciation related revenue requirement level built in base rates, but customers
21 would not receive the benefit expected with the payment of depreciation expense over
22 time. The benefit customers receive for depreciation expenses is an offset to rate base for
I 23 the utility's recovery of its invested capital. The benefit of depreciation expense is
24 booked into Account 108, the accumulated provision for depreciation ("APFD"). The
I 25 APFD is subtracted from gross plant in order to determine net plant. Net plant is the
26 largest component of rate base.
I
89
I
1 Q. HOW IS THE DEPRECIATION PROCESS PROPERLY PERFORMED BY A
2 UTILITY?
3 A. Once a depreciation rate is adopted by a regulator, that rate should be applied to gross
4 plant in service on a monthly basis until the plant retires.
5
6 Q. DOES THE COMPANY FOLLOW TIDS FORMAT?
7 A. No. The Company's policy is that once it makes a unilateral decision that it believes an
8 account has become fully accrued, it ceases the booking of depreciation expense to the
9 APFD. 150 Thus, by not continuing the booking of depreciation expense, ETI has changed
10 the applicable depreciation rate to zero (0) rather than whatever rate the Commission
11 previously adopted. The unilateral decision to cease the booking of depreciation expense
12 is made even though the plant has not retired.
13
14 Q. WHAT IS ETl'S STANDARD FOR ASSUMING A PLANT HAS BECOME
15 FULLY ACCRUED?
16 A. When the Company "believes" it has recovered the total investment plus the impact of its
17 estimate of net salvage, it ceases the booking of depreciation expense. Thus, the standard
18 employed by ETI is its unilateral "belief."
19
20 Q. WHAT IS THE IMPACT OF TIDS INAPPROPRIATE UNILATERAL ACTION?
21 A. By ceasing the booking of depreciation expense, the Company understates the APFD and
22 thus on a going forward basis overstates rate base since the APFD is artificially not
23 permitted to increase. Moreover, this inappropriate practice deprives customers of the
24 return of their overpayment of depreciation expense through the remaining life
25 depreciation technique.
26
27 Q. WHAT IS THE REMAINING LIFE DEPRECIATION TECHNIQUE?
28 A. As set forth under the General section of my testimony on depreciation, the remaining
29 life technique attempts to recover the net depreciable investment less net salvage over the
30 remaining expected life of the account. The remaining net depreciable investment less net
150
Response to Rose City 1-19.
90
I salvage can be either positive or negative. This approach recognizes that while recovery
2 of net depreciable investment less net salvage may be under or over recovered, the intent
3 is to allow only I 00% recovery, not more or less.
4
5 Q. WHAT DID TmS COMMISSION ORDER REGARDING THE APPLICATION
6 OF DEPRECIATION FOR Tms COMPANY?
7 A. In Docket No. 16705, the Company's last litigated rate case, the Commission ordered the
8 adoption of "Staff's proposed depreciation rates."m (Emphasis added).
9
10 Q. DOES THE COMPANY ADMIT THAT IT CEASED USING THE COMMISSION
11 APPROVED RATES FROM DOCKET NO. 16705?
12 A. Yes. The Company admits that it "stopped booking depreciation" for 3 accounts. 152
13
14 Q. WHO AT THE COMPANY MAKES THE DECISION AS TO WHEN AN
15 ACCOUNTBECOMESFULLYACCRUED?
16 A. The Company stated that its software program, PowerPlant, has a built-in algorithm that
17 automatically stops depreciation when a particular depreciation group is fully
18 depreciated. 153 The Company implemented this specialized software in January 2004. 154
19 It appears that prior to the implementation of this software progress this situation did not
20 exist.
21
22 Q. HOW DOES THE COMPANY JUSTIFY ITS ACTIONS?
23 A. The Company claims that depreciation is the loss of service value, as set forth in the
~ 24 USOA. 155 The Company believes that the definition of service value limits depreciation
25 to the original cost less net salvage. 156
I 151
Docket No. 16705 FOF 190.
152
Response to Rose City 13-32c.
153
Response to Rose City 13-32b.
1s4 Id.
155
Id., at (a).
1s6 Id.
91
I
 1 Q. IS THE COMPANY CORRECT IN ITS BASIS?
2 A. No. As part of the same series of definitions relied upon by the Company in the USOA,
3 there are general instructions which identify under depreciation accounting the reference
4 to a rate. The USOA states that utilities "must use percentage rates of depreciation that
5 are based on a method of depreciation that allocates in a systematic and rational
6 manner." 157 The Company takes a unique interpretation of these series of items, which
7 then allows it the unilateral authority to change a depreciation rate that has been approved
8 by the Commission through the back door mechanism of an algorithm built into a
9 software program that has never been approved by the Commission. This unique
10 interpretation of the USOA and hidden algorithms within software programs violate the
11 Commission's orders adopting depreciation rates in prior proceedings.
12
13 Q. WOULD THE COMPANY'S ACTIONS BE APPROPRIATE IF IT WERE AN
14 UNREGULATED COMPANY?
15 A. Yes. However, since ETI is a regulated utility, its actions are inappropriate because
16 captive customers would be forced to pay depreciation expense through rates approved
17 by the Commission without getting the benefit of the depreciation being added to the
18 accumulated reserve. Therefore, the Company's proposal must be rejected.
19
20 Q. WHAT DO YOU RECOMMEND?
21 A. I recommend that the Commission recognize the amount of loss in back depreciation
22 expense that should have been booked to the accumulated provision for depreciation
23 associated with three accounts referenced by the Company. As set forth on Schedule (JP-
24 2), the amount of additional depreciation expense that should have been recognized on
25 the Company's books and records through the end of the test-year in this case is
26 $6,160,578. I further recommend that the Commission order the Company to correct the
27 algorithm in its software system so as to comply with the booking of Commission
28 approved depreciation ate.
is1 Id.
92
l Q. HOW SHOULD THE COMMISSION TREAT THIS AMOUNT?
2 A. The Commission should reduce rate base by the $6,160,578 amount noted above and
3 amortize such amounts back to customers over a 4-year period. This would result in an
4 additional $1,540,145 reduction in annual revenue requirements.
5 SECTION IV: SGSF CAPITAL RECOVERY
6
7 Q. WHAT IS THE ISSUE IN THIS PORTION OF YOUR TESTIMONY?
8 A. In this portion of my testimony I discuss the Company's acquisition of the Spindletop
9 Gas Storage Facility ("SGSF") and two key resulting issues. The first issue is the
10 recognition of the substantial positive net salvage identified by ETI. The second issue is
11 the correction of the excess recovery of investment on an accelerated basis.
12
13 Q. WHAT DO YOU RECOMMEND?
14 A. Given the unusual facts and circumstances surrounding the construction, financing,
15 capital payments, rate treatment, admission by the Company that these are customer
16 savings rather than shareholder profits, and the exercise of the purchase option, I
17 recommend that: (1) current customers be reimbursed for their equitable right to the
18 current net depreciable value, and (2) current customers receive a credit for the $40
19 million of return of capital (i.e., depreciation) they have paid during the 1990s and early
20 2000s due to the special rate treatment granted the Company and that such credit be
21 amortized to current customers over a four-year period. Given that Cities' witness Mr.
22 Nalepa recommends the removal of all SGSF costs, the second above noted
23 recommendation is necessary in the event the Commission elects not to adopt Mr.
24 Nalepa's recommendation. In any event, the need to recognize the net salvage or sale
25 value is still required.
26 Q. PLEASE PROVIDE THE BACKGROUND ASSOCIATED WITH THIS
27 PARTICULAR ISSUE.
28 A. In the late 1980s and early 1990s, the Company's predecessor GSU was in a difficult
29 financial position. An opportunity arose where GSU could obtain a gas storage facility
93
1 for the benefit of customers. Unfortunately, due to its financial constraints, GSU could
2 not purchase and construct the gas storage facility. It contracted with Sabine Gas
3 Transportation Company ("SGT") to construct the facility and utilize it at the direction of
4 GSU. GSU retained control of construction, modifications, and operation of the facility.
5 In addition, the operating agreement included an option to purchase the facility from SGT
6 at a "Payoff Amount". The "Payoff Amount" reflected a reduced net cost in association
7 with the level of "Credit Payments" made by the Company. 158 The "Credit Payments"
8 were costs the Commission allowed the Company to pass on to customers. In 2004, the
9 Company exercised its purchase option and became the owner of the gas storage facility
10 for a $1.00 payment.
11
12 Q. HAVE SGSF CAPITAL COSTS BEEN INCLUDED IN ELIGIBLE FUEL SINCE
13 ITS INCEPTION?
14 A. Yes. In Docket No. l 0894, the Commission found that the "Credit Payments" to SGT for
15 capital reduction were costs that were passed on to customers. 159
16
17 Q. WHAT IS THE VALUE OF THE FACILITY?
18 A. Recently, the Company has appraised the value of the gas storage facility at $100
19 million. 160 In other words, the current best estimate of the value of SGSF is
20 $100,000,000 less the $1 it paid for the facility.
21
22 Q. ARE THERE OTHER EVENTS CURRENTLY TRANSPIRING THAT IMPACT
23 THIS PARTICULAR ISSUE?
24 A. Yes. As part the electric deregulation process in Texas, a jurisdictional separation has
25 been completed. The Company is now a distinct corporate entity, separate from Entergy
26 Gulf States Louisiana. While the ownership of SGSF remains with ETI, the completion
27 of the separation process may result in the sale of the Texas system. In fact, Entergy
28 Corporation chairman and Chief Executive Officer J. Wayne Leonard told shareholders
29 in November 2007 that he might sell the Texas operations if the jurisdictional split were
158
PUCT Docket No. 10894, Examiners' Report pages 106-110.
159
PUCT Docket No. 10894 Finding of Fact 288.
160
October 18, 2004 Hadco International Appraisal & Consulting Services.
94
1 approved by the Louisiana Public Service Commission. If this were to occur, or if
2 deregulation is eventually implemented for the Company, Texas retail customers stand to
3 lose the value of the facility they have already paid for and were previously promised.
4 Thus, Texas retail customers may lose their share of the current $100 million gross
5 salvage attributable to the SGSF unless action is taken.
6
7 Q. WHY IS IT APPROPRIATE TO TAKE ACTION IN TIDS PROCEEDING?
8 A. In Docket No. 10894, this Commission specifically afforded the Company recovery for
9 the capital costs of constructing the gas storage facility even though it did not own the
I0 facility. 161 This action was taken in spite of the Company's admission that if it had
11 constructed the facility itself it would have been subject to base rate treatment. 162 The
12 Company could not build the facility itself due to budgetary constraints at the time the
13 project to construct the gas storage facility became available. The Commission granted
14 the Company special treatment based in part on the fact that customers were expected to
15 benefit from the facility. The Commission also allowed the pass through of capital costs
16 (i.e., depreciation) on an accelerated basis. The Commission allowed the financing of the
17 facility to be paid within a 10-year period rather than the then-estimated 30-year useful
18 life of the facility. 163 Now, in recognition of the changed circumstances, and the drastic
19 intergenerational inequity that occurred for customers, it is only fair and equitable to level
20 the field for current and future customers due to prior significant overpayment.
21
22 Q. WHAT DO YOU RECOMMEND?
23 A. I recommend that with the changed circumstances associated with the purchase of the
24 facility for $1.00 by the Company that: (1) Texas retail customers be credited for their
25 allocable portion of the current $100 million valuation or net salvage, and (2) Texas retail
26 customers be given credit in the APFD for prior payments for the return of capital (i.e.,
27 depreciation). These recommendations are conservative in favor of the Company, given
28 that the gas storage facility may very well continue to increase in value.
161
PUC Docket 10894.
162
Id., at Finding of Fact 308.
163
Id., at Finding of Fact 310.
95
1 Q. WHY DO YOU BELIEVE THAT THE VALUE OF THE FACILITIES WILL
2 INCREASE IN THE FUTURE?
3 A. First and foremost, the value of the facilities increased by a factor of 2.5 times its original
4 $40 million cost in a little over a decade ($100 million + $40 million = 2.5). This increase
5 in value has occurred in large part due to the change in the natural gas industry and the
6 resulting prices that suppliers have and can demand for their product. The price of gas has
7 reached all-time highs in the last several years and the fact that the gas market is unstable,
8 coupled with the concern for air quality associated with coal-fired generation and
9 consideration of a return to a more robust economic market, results in the conclusion that
10 the future for gas prices will continue to be volatile and most likely be at a higher level
11 than experienced during the 1990s and early 2000s. As gas prices increase in cost over
12 time, the value of the gas storage facility further increases. Thus, in another 5 or 10 years
13 the gas storage facility may actually be valued at something much higher than the recent
14 estimate of $100 million to another entity. In the event the Commission opts to retain the
15 SGSF regulated service, the value should be revisited in future rate cases like other net
16 salvage values are expected to be revisited.
17
18 Q. FROM AN EQIDTY STANDPOINT, ARE TEXAS RETAIL CUSTOMERS
19 ENTITLED TO THE VALUE OF TIDS FACILITY?
20 A. Yes. There can be no doubt that Texas retail customers have paid their proportionate
21 share of basically all costs associated with this facility. Had GSU not been in a budgetary
22 constraint position when the opportunity arose to acquire the rights to build the gas
23 storage facility customers would have paid significantly lower fuel costs and base rate
24 charges. Historical fuel costs would have been lower since there would have been no
25 "Credit Payments" made to SGT. Moreover, base rates would not have increased on a
26 comparable basis if the original costs had been included in rate base. This result would
27 have occurred since the effective depreciation component of revenue requirements would
28 have essentially been minimal or even a negative value given the estimated gross salvage
29 for the value of the facility would have been subtracted from the original cost. This is
30 standard industry practice since the useful life of the facility would extend beyond the
31 estimated life of the generating facilities that it serves (Sabine and Lewis Creek
96
generating stations). The last unit at the Sabine station is scheduled to retire no sooner
2 than 2029 . 164 Thus, the gas storage facility could be sold at a substantial value above cost.
3
4 In addition, in compliance with the benefits-follows-burdens concept adopted by the
5 Texas Supreme Court, the fact that customers have in fact paid for capital costs, operating
6 costs, property taxes, and basically every other cost associated with the facility, entitles
7 any gain on sale to be assignable to customers. 165
8
9 Q. WHAT IS YOUR UNDERSTANDING OF THE DIRECTION THE COURTS
10 HAVE PROVIDED TO THE COMMISSION REGARDING WHO IS ENTITLED
11 TO THE GAIN INVALUE OF THE SGSF?
12 A. I have been advised by counsel that the Texas Supreme Court recognized that ''the proper
13 allocation is a complicated one that cannot be resolved simply by reference to who paid
14 for the property." 166 The court relied in part on the benefits-follows-burdens principal
15 established in the Democratic Central Committee case. 167
16
17 The Court, while not requiring the Commission to consider all of the standards set forth
18 in its ruling, nor forbidding it from considering others, listed a number of factors. The
19 Court noted:
20
21 In the general case, the gain should be allocated to that group (as
22 between shareholders and ratepayers) that has borne the financial
23 burdens (e.g., depreciation, maintenance, taxes) and risks of the asset
24 sold. In addition to these two general equitable factors, courts have
25 also considered numerous other factors, including whether the asset
26 sold had been included in the rate base over the years, whether the
27 asset was depreciable property, non depreciable property, or a
28 combination of the two types, the impact of the proposed allocation on
29 the financial strength of the utility, the reason for the asset's
30 appreciation (e.g., inflation, a general increase in property values in
31 the area), any advantages enjoyed by the shareholders because of
32 favored treatment accorded the asset, the dividends paid out to the
164
Response to Rose City 1-16.
165
798 s. w. 2d 560.
166 ld.
Id.
I
t67
97
I
l shareholders over the years, and any extraordinary burdens borne by
2 the ratepayers in connection with that asset.
3
4 Q. DID YOU CONSIDER VARIOUS FACTORS?
5 A. I have considered numerous factors. First while ETI did not own the plant prior to
6 January 2005 and thus it was obviously not included in rate base, the treatment afforded
7 the Company by the Commission was in fact superior to rate base treatment. As
8 previously noted, the Commission granted the Company the right to recognize all
9 construction costs and operating costs as reconcilable fuel. By doing so, it allowed the
10 Company to pass basically all financial burdens on to customers and without the normal
11 regulatory lag and guaranteed cost recovery. In addition, the costs incurred by SGT for
12 property taxes, operation and maintenance expenses, etc. were also passed on to the
13 Company. The Company in tum included such costs as reconcilable fuel costs, which
14 were then passed on to customers. Once again, customers paid all operating and tax
15 impacts of the facility.
16
17 Q. WERE CUSTOMERS RESPONSIBL E FOR DEPRECIATION?
18 A. In effect, yes. While the amounts paid to SGT did not specifically identify depreciation, it
19 is an undeniable fact that the "Credit Payments" were for debt service requirements. The
20 principal and interest components of debt service requirements are the equivalent of
21 depreciation and return., respectively for plant afforded base rate treatment. Thus, the
22 principal payment is the equivalent of depreciation, and the interest portion of the debt
23 service payment is the equivalent of return.. Therefore, while not identified specifically as
24 depreciation, customers did pay the equivalent of depreciation for the investment. This
25 fact also demonstrates that the regulatory treatment afforded the Company was more than
26 the equivalent of providing rate base treatment over the entire operating life of the
27 facility. This represents yet another burden carried by customers, not the Company.
98
1
2 Q. DOES YOUR RECOMMENDED 100% ALLOCATION OF GAIN TO
3 CUSTOMERS TAKE INTO ACCOUNT THE FINANCIAL STRENGTH OF THE
4 COMPANY?
5 A. Yes. While GSU was not in a financial position to construct the facility back in the early
6 1990s, that situation was rectified when GSU merged with Entergy. In fact one of the
7 benefits touted by Entergy in association with its proposed merger at that time was the
8 financial strength that it brought to the GSU system. Moreover, the financial strength of
9 the utility has been enhanced by normal regulatory treatment in rate proceedings as well
10 as very unique and special legislative treatments realized by the Company over the last
11 several years as it pertains to recovery of capacity charges and hurricane damage costs
12 during the period when the Company had been in a base rate freeze. In addition, when
13 the Company was granted fuel reconciliation treatment for the cost associated with the
14 SGSF it was granted favorable rate treatment for this particular asset. Had the Company
15 been required to place the asset into base rates rather than receiving reconcilable fuel
16 treatment it would have experienced a regulatory lag in recovery of funds and would not
17 have been guaranteed recovery. This regulatory lag was eliminated by the Commission
18 for the Company's use of the SGSF.
19
20 Q. IS THE COMPANY RESPONSIBLE FOR THE INCREASE IN VALUE OF THE
21 FACILITY OVER THE YEARS?
22 A. No. The value of the asset has increased due to market forces, not anything implemented
23 by the Company.
24
25 Q. IN SUMMARY, IS THERE ANY FACTOR THAT YOU'VE IDENTIFIED
26 WHICH WOULD INDICATE THAT THE COMPANY'S SHAREHOLDERS
I 27 WERE ENTITLED TO SOME PORTION OF THE GAIN TO BE OBTAINED
FROM THE ULTIMATE DISPOSITION OF TffiS FACILITY?
I 28
29 A. No. Based on every meaningful factor I have been able to identify associated with the
I 30
31
construction, financing, operations, etc. of this facility, it has been customers who are
responsible for each component. As such, in my opinion it would clearly be in violation
I 99
I
1 of the principals set forth by the Supreme Court of Texas if the Company were to be
2 afforded any portion of the gain in value of this facility. Moreover, in Docket No. 10894,
3 Company witness Mr. Harrington stated that the savings of the project were for
4 customers, not shareholders. 168
5
6 Q. HOW DO YOU PROPOSE TO RECOGNIZE THE $100 MILLION VALUE FOR
7 TEXAS RETAIL CUSTOMERS?
8 A. As of January 2005, the Company took ownership of the facility after purchasing the
9 facility for $1.00. Texas retail customers should be credited with their allocable portion
10 of the $100 million value as of that point in time. As shown on Schedule (JP-3) this
11 results in a $42.5 million credit to the Texas retail jurisdiction. I recommend that the
12 amount be returned to customers over the 35.5-year remaining life I recommended for
13 Sabine 5, or $1,197,183 annually. This amount should be credited whether Mr. Nalepa's
14 recommendation is adopted.
15
16 Q. WHY IS IT APPROPRIATE TO CREDIT CUSTOMERS FOR THE SGSF NET
17 SALVAGE VALUE WHETHER THE PUC ADOPTS MR. NALEPA'S
18 RECOMMENDATION?
19 A. Mr. Nalepa's recommendation reflects a prudent business decision regarding the annual
20 benefits versus costs for the SGSF. My recommendation relates to the value that a
21 different owner with a different operating philosophy might have regarding the facility. It
22 is my understanding that Mr. Nalepa's recommendation is based on the changed
23 circumstances relating to reliability issues and annual costs of operation. ETI no longer
24 needs the facility, but that fact does not change the value of the facility to a new owner.
25 By analogy, this is no different than a family no longer needing a two-seat sports car once
26 they have children. The fact that a two-seat sports can no longer fit one family's situation
27 does not diminish the value of the car.
168
Mr. Harrington's rebuttal testimony at WEH-7 in Docket No. 10894.
100
1 Q. TURNING TO YOUR SECOND ISSUE RELATING TO
2 INTERGENERATIONAL INEQUITY, WHAT DO YOU RECOMMEND?
3 A. I recommend correcting the significant level of intergenerational inequity that currently
4 exists by amortizing the future service value over a four-year period in conjunction with
5 corresponding depreciation treatment of the estimated remaining life of the facility. This
6 treatment will eliminate the "free ride" future customers will enjoy given the full, but
7 accelerated, depreciation realized for the initial capital costs.
8
9 Q. WHY ARE CUSTOMERS ENTITLED TO A CREDIT FOR PRIOR
10 ACCELERATED RETURN OF CAPITAL OR DEPRECIATION PAYMENTS?
11 A. Had the SGSF been afforded normal base rate treatment rather than the superior fuel
12 treatment, the Company's books would already reflect the "Credit Payments" in the
13 APFD (Account 108) as a credit to rate base. Given that customers were required to pay
14 off the facility on an accelerated basis to meet the construction related finance
15 requirements, it is only equitable to recognize such accelerated payments now that the
16 Company has taken formal ownership of the facility. The Texas retail jurisdiction should
17 be allocated its proportional share of the prior accelerated depreciation payments. This
18 results in a $17 million adjustment to rate base. 169 In conjunction with this credit to rate
19 base, I also recommend a four-year amortization in order to correct the substantial level
20 of intergenerational inequity. This will result in a net $3.8 million annual credit. 170
21 Q. HAVE OTHER REGULATORS ADOPTED THE CORRECTION OF
22 INTERGENERATIONAL INEQUITY AS YOU ARE RECOMMENDING IN
I 23
24 A.
TIDSCASE?
Yes. The FPSC within the past year ordered precisely this treatment I recommend in this
I 25 case. In fact, the FPSC ordered that state's two largest electric utilities to credit their
I
I 169
170
Production demand allocation factor of 42.5% as noted in response to Rose City 2-6(c) times the $40 million
initial cost.
$17 million amortized over 4 years equals $$4,250,000, less $17 million depreciated over 35 years equals
I $485,714.
101
1 retail customers with approximately $1 billion of excess or prior accelerated depreciation
2 over a four-year period. 171
3
4 Q. WHAT ANNUAL LEVEL OF DEPRECIATION WILL CUSTOMERS BE
5 REQUIRED TO INCUR ASSOCIATED WITH YOUR RECOMMENDATION?
6 A. As part of my recommendation customers will be required to pay $485,714 of annual
7 depreciation expense in order to extinguish the $17 million rate base credit over the 35-
8 year remaining life I am recommending.
9
IO Q. WILL FUTURE CUSTOMERS HAVE TO PAY FOR A PORTION OF YOUR
11 RECOMMENDATIONS?
12 A. Yes. After the proposed 4-year amortization is over and the Company files for a change
13 in base rates, future customers will begin paying a return and depreciation on the
14 $17million portion of my recommendation for the remaining life of the facility. This
15 future payment will better meet the regulatory matching principle tying the payment by
16 those customers to the benefit of the storage facility being used to provide that generation
17 of customer's electric service. The will be no need for future customers to pay for the
18 $42.5 million portion of my recommendation given that value will be provided through
19 the sale of the facility after it is retired from utility service.
20 SECTION V: STORM INSURANCE RESERVE
21 1. General
22
23 Q. WHAT IS THE ISSUE IN TIDS PORTION OF YOUR TESTIMONY?
24 A. The Company requests an insurance reserve storm cost accrual of $9,450,000. 172 This
25 request is comprised of two components. The first component of $4,180,000 relates to
26 recovering the Company's claimed $64.4 million deficit in its insurance reserve, plus
27 building the storm reserve to a positive $19 .3 million target. 173 The Company proposes to
171
FPSC Docket Nos. 080677-EI and 090079-EI, a FP&L and Progress Energy Florida case, respectively.
172
Direct testimony of Mr. Wilson at page 4.
173
Id.
102
1 amortize this claimed $83.7 million ($64.4 million + $19.3 million) change in reserve
2 position over a 20-year period, for a $4.18 million annual expense. The second
3 component of the Company's proposed annual accrual is $5,270,000, which represents
4 the Company's estimated annual ongoing storm losses. 174 In addition to these two
5 components, ETI also requests $25,278,210 in rate base, to be amortized over 5 years at
6 an annual rate of $5,055,642, associated with a proforma adjustment for hurricane
7 securitization cost that were removed from the storm reserve. 175 This portion of my
8 testimony addresses my recommendations to eliminate significant portions of the claimed
9 historical reserve deficit, reduce the projected reserve target level, reduce the annual
10 estimated storm loss expense, and assign storm reserve treatment to the proposed
11 hurricane securitization proforma adjustment. As summarized in the table below, the
12 combined impact of my recommendations reduces the Company's requested $9.45
13 million annual revenue requirement by $7,703,810 and also reduces rate base by
14 $45,867,967. I also recommend increasing the storm threshold level from $50,000 per
15 storm to $500,000 per storm.
Rate Base Impact
I Reserve Deficiency
ETI
$64,355,152
Cities
$47,497,395
Adjustment
($16,857,757)
Reserve Target $19,304,000 $15,572,000 ($3,732,000)
Subtotal $83,659,152 $63,069,395 ($20,589, 757)
Hurricane Proforma $25,278,210 ~ ($25,278,210)
Total Rate Base $108,937,362 $63,069,395 ($45,867,967)
Annual Accrual Imnact
Rate Base Amortization $4,182,958 $3,153,470 ($1,029,488)
Annual Loss Accrual $5,270,000 $3,651,320 ($1,618,680)
Hurricane Proforma $5,055,642 ~ ($5,055,642)
I Total Annual Expense $14,508,600 $6,804,790 ($7,703,810)
I 174
Id., at page 5.
175
Testimony of Mr. Wright at pages 19-20 and ETI Adjustment AJIS.10.
103
1 Q. DOES THE COMMISSION PERMIT SELF-INSURANCE BY UTILITIES?
2 A. Yes. The Commission has implemented Substantive Rule 25.23l(b)(l)(G) relating to a
3 self-insurance plan for storm damages. The establishment and operation of the insurance
4 reserve is intended to produce a less costly approach to dealing with storm damage,
5 which could not have been reasonably anticipated, than would be the case if the
6 Company purchased commercial insurance.
7
8 Q. DOES THE COMPANY CURRENTLY HAVE A SELF-INSURANCE
9 PROGRAM?
10 A. Yes. In fact, the issues addressed in this proceeding cover the changes in the Company's
11 self-insurance reserve subsequent to the settlement in Docket No. 34800 and in the
12 Company's last fully litigated rate case, Docket No. 16705.
13
14 Q. WHAT DID THE COMMISSION ADOPT REGARDING THE COMPANY'S
15 SELF-INSURANCE EXPENSE IN DOCKET NO. 16705?
16 A. The Commission granted the Company $1,651,320 per year for current losses and noted
17 the amount should accrue only enough each year to cover typical storm damage. 176 In
18 addition, the Commission did not set a storm reserve balance. The reason the
19 Commission did not set a storm reserve balance is because the Company did not provide
20 a reasonable post test-year level for its then existing reserve fund and because the
21 Company did not prove that the amounts expended in 1997 associated with an ice storm
22 were prudent or appropriate. 177
23
24 Q. WAS THE ANNUAL STORM LOSS LEVEL MODIFIED RECENTLY?
25 A. Yes. The Commission recently adopted a settlement in Docket No. 34800 that increased
26 the annual storm loss accrual to $3,651,320 effective January 1, 2009. 178
176
Docket No. 16705 FOF 146.
177
Id., atFOF 147.
178
Docket No. 34800 Settlement Term Sheet Item 8.
104
Q. WHAT DOES THE COMPANY CLAIM HAS TRANSPIRED TO THE STORM
2 RESERVE SUBSEQUENT TO DOCKET NO. 16705?
3 A. The Company claims that it has incurred storm losses from 155 different storms, each of
4 which exceeded $50,000 of charges in aggregate. 179 In addition, the Company increased
5 the reserve on an annual basis for the $1.651 million annual insurance accrual through
6 2008, and then by $3.651 million annually beginning in 2009.
7
8 Q. WHAT ARE THE VARIOUS COMPONENTS OF THE SELF-INSURANCE
9 RESERVE EXPENSE THAT REQUIRE INVESTIGATION?
10 A. The Commission has identified the annual level of contributions until the amount was
11 increased effective January I, 2009 in association with Docket No. 34800. All other
12 components that affect the insurance reserve level and annual expense are subject to
13 review and justification.
14 2. Storm Reserve Deficit
15
16 Q. WHAT DOES THE COMPANY CLAIM AS ITS STORM RESERVE DEFICIT?
17 A. The Company claims a $64 million deficit or negative reserve currently. 180
18
19 Q. WHAT IS INCLUDED IN THIS RESERVE THAT CAUSES IT TO BE SO
20 NEGATIVE?
21 A. The Company has included all storm-related costs that in aggregate exceeded $50,000 per
I 22 storm. Some of the costs recognized by the Company included incentive compensation,
23 fire and property insurance premiums, safety training expenses, computer hardware
24 acquisitions, and, in effect, anything else the Company deems appropriate.
25
26 Q. DID MR. WILSON DEVELOP THE $64 MILLION RESERVE DEFICIT
27 VALUE?
I 28 A. No. This amount was provided to him by the Company. 181
I 179
180
Response to Rose City 5-1.
Direct Testimony of Mr. Wilson at page 5. The precise claimed deficit is $64,355, 152.
181
Deposition of Mr. Wilson on April 22, 2010 at TR 12.
I 105
l Q. DID MR. WILSON INVESTIGATE THE REASONABLENESS OR NECESSITY
2 OF ANY OF THE EXPENSES THAT WERE INCLUDED IN THE CLAIMED $64
3 MILLION RESERVE DEFICIT?
4 A. No.182
5 I
6 Q. DID THE COMPANY PRESENT ANY DETAILED ANALYSES
7 DEMONSTRATING THE VALIDITY OF THE COSTS REFLECTED IN ITS
8 STORM RESERVE?
9 A. No. There was no presentation by the Company that demonstrates it has only included
l0 prudent, reasonable and necessary costs in its storm reserve. In fact, the loss-run data
11 supporting the costs included in the storm reserve for the periods prior to 1996 were not
183 Moreover, the Company did not provide any documentation that
12 retained.
13 demonstrates that the labor charges reflected in the storm reserve are not already being
14 recovered through base rate charges and thus may represent a double recovery of
15 expense.
16
17 Q. AFTER REVIEW OF ALL THE DOCUMENTATION PRESENTED BY THE
18 COMPANY ASSOCIATED WITH ITS STORM RESERVE, DO YOU BELIEVE
19 ADJUSTMENTS ARE NECESSARY?
20 A. Yes. In my opinion, the Company's claimed $64 million current storm reserve deficiency
21 is quite excessive. In fact, I recommend adjustments to remove the impact of: (1) the
22 major 1997 ice storm; (2) the first $50,000 of each storm corresponding to a deductible
23 that would be in place by standard insurance practices; (3) miscellaneous expenses not
24 appropriately included in the reserve; (4) a proposed situs based adjustment addressed in
25 Docket No. 34800; and (5) additional insurance proceeds associated with securitized
26 storms that have been received or estimated, but which are not reflected in the
27 securitization process or the current filing.
182
Id., at TR 12 and 13.
183
Response to Cities 30-1 in Docket No. 34800.
106
Q. PLEASE DISCUSS YOUR FIRST ADJUSTMENT RELATING TO THE 1997 ICE
2 STORM.
3 A. Included in the insurance reserve is a charge of $13,014,379 associated with the January
4 13, 1997 ice storm. 184 This particular storm resulted in a separate docket before the
5 Commission in which the Company's actions were investigated. That proceeding was
6 Docket No. 18249. The Order on Rehearing identified the following critical issues or
7 problems associated with the Company's actions that led, in part, to the significant cost
8 associated with storm restoration efforts:
9
10 • The Company conceded that it did not have a traditional pole inspection program.
11 With the Entergy-GSU merger, the Company reduced the number of inspections
12 for poles. The Company's pole inspection and work cycles were not sufficiently
13 rigorous, continuous or frequent to maintain all of its facilities in the condition
14 required to meet its reliability and service obligations under PURA. 185
15 • The Company's line maintenance and vegetation control were reactive in nature
16 and lacked written and specific preventative maintenance policies. Moreover,
17 priority was not given to capital additions to the detriment of adequate
18 maintenance practices. 186
19 • While the Company claimed that its vegetation management was adequate and
20 consistent with industry practices, extensive evidence was provided to document
21 serious neglect of vegetation management. Such serious neglect resulted in
22 heightened risk to the distribution system associated with the ice storm. "The
23 Commission concludes that the level of the Company's vegetation management is
24 unacceptable and has sipiticantly affected the reliability of the distribution
25 system in recent years." 18
26 • The Company itself found it necessary to hire 30 new vegetation clearance crews
27 subsequent to the ice storm, which only confirmed the existence of an
28 unacceptable backlog in vegetation control prior to the ice storm. 188
29 • "The January 1997 ice storm was certainly a severe storm that would have
30 diversely affected the best-maintained distribution system. EGS' distribution
31 system, however, is not the best-maintained. A major cause of the outages during
32 the storm was broken or bowed ice-laden tree limbs overhanging the wires. Tree
33 limbs in ROW overhanging distribution lines pose a threat to system reliability
34 and are largely within EGS' control. The Company's failure to clear the limbs
35 before the storm was a major factor in the number and duration of outages
36 experienced by customers. While the Company's initial efforts to mobilize and
184
Response to Rose City 5-2.
185
Docket No. 18249 Order on Rehearing page 9.
186
Id., at pages 9 and 10.
187
Id., at page 15.
188 Id.
107
1 deploy non-EGS personnel were slow and caused concern, vegetation
2 management failures greatly aggravated the situation." 189
3 • The Company's management structure is ill-suited to assure best supervision of
4 the T&D System in the Texas territory. 190
5 • The inspection program carried out by the Company was not sufficiently
6 extensive or adequate to fulfill its proposed purpose of securing reliable
7 service. 191
8 • The Company's distribution system maintenance practices fail to assure
9 continuance and adequate service to customers. 192
10 • "Negligent and backlog of vegetation management projects has posed
11 unacceptable risk of increasing and recurrent service outages, especially during
12 major storms." 193
13
14 Moreover, the Proposal for Decision in Docket No. 16705 stated the following regarding
15 the 1997 ice storm:
16
17 First, the ALJs recommend the Commission ignore the $13 million in this
18 case. EGS did not meet its burden to prove that the $13 million
19 expenditure was prudent and reasonable, or even that it was necessary.
20 Cities point out in their Brief that EGS did not inform the other parties that
21 further charges were made to the fund, and EGS did not update discovery
22 requests advising that the reserve was at a level different from the $11.4
23 million. Tr. 6928; 6744-6745 (Lawton). The only information concerning
24 post-test-year charges to the reserve appeared in Mr. Wilson's rebuttal. Tr.
25 8136. On cross-examination, Mr. Wilson testified that he did not know
26 when he first learned that the insurance reserve has been reduced. And he
27 did not review or evaluate the expenditures to determine whether they
28 were prudently incurred, or whether they had been properly expensed and
29 capitalized. Tr. 8800-8803. He did not know if any of the damage could
30 have been avoided by better tree trimming of maintenance of poles. Cities.
31 OPC. and General Counsel suggest. and the ALJs agree. that this issue can
32 be addressed in the 1998 rate filing when all parties will have the
33 opportunity to evaluate the reasonableness of the changes to the insurance
34 reserve fund. 194 (Emphasis added). ·
35
36 The above noted items, along with other items set forth in Docket No. 18249, clearly
37 establish that the Company did not perform adequately or prudently and incurred
38 excessive costs associated with the January 1997 ice storm. Therefore, I recommend that
189
Id., at pages 17-18.
190
Id., at FOF 26.
191
Id., at FOF 45.
192
Id., at FOF 46.
193
Id., at FOF 82.
194
Docket No. 16705 PFD at page 186.
108
the Commission exclude the $13 million of ice storm related charges from the
2 Company's insurance reserve.
3
4 Q. PLEASE DISCUSS YOUR SECOND ADJUSTMENT TO THE COMPANY'S
5 INSURANCE RESERVE ASSOCIATED WITH DEDUCTIBLE LEVELS.
6 A. The Company's self-insurance program fails to comply with standard insurance practices
7 and in fact, creates a perverse incentive. The issue is the Company's failure to treat the
8 lower $50,000 threshold as a deductible event. Indeed, with normal insurance policies, an
9 incentive is provided to the party purchasing insurance to not make unreasonable or
10 frivolous claims. Part of that deterrent is the requirement of a deductible. In this case, the
11 $50,000 minimum threshold employed by the Company should serve the purpose of
12 being the deductible in the insurance process.
13 Q. HOW SHOULD THE DEDUCTIBLE WORK AS IT RELATES TO THE
14 INSURANCE RESERVE?
15 A. If the Company incurred $49,999 of expense associated with the storm, it would absorb
16 the entire amount as O&M expenditures. However, if the Company captures one
17 additional dollar of expense, then it converts the process to insurance reserve treatment
18 and includes all expenditures associated with such storm in the insurance reserve, rather
19 than only those amounts in excess of the first $50,000. Regulation must provide
20 reasonable and appropriate incentives in order to minimize costs. The failure to recognize
21 a deductible only encourages the occurrence of costs and provides no incentive to act
22 prudently and in the best interest of customers.
23
24 Q. IS THERE ANY REASON TO TREAT THE FIRST $50,000 OF STORM COSTS
25 INCURRED AS INSURANCE RESERVE COSTS?
26 A. No. Failure to treat the first $50,000 of O&M expense related storm expenditures as a
27 deductible insurance practice is inappropriate and must be denied.
109
1 Q. WHAT IS THE IMPACT OF TIDS RECOMMENDATION?
2 A. The Company's insurance reserve reflects 155 different storms smce Docket No.
3 16705. 195 Therefore, after removal of the ice storm previously discussed, I recommend a
4 reduction to the insurance reserve in the amount of $7,700,000, or 154 times $50,000 per
5 storm.
6
7 Q. PLEASE ADDRESS THE THIRD AREA OF ADJUSTMENT ASSOCIATED
8 WITH MISCELLANOUS INAPPROPRIATE CHARGES.
9 A. As set forth in the table below, the Company has included numerous charges in its storm
10 reserve that do not comply with the Commission's rule. One of the Commission's rules
11 requires charges only for "property and liability losses which occur, and which could not
12 have been reasonable anticipated and included in operating and maintenance expense." 196
Description Amount 1Y 1
Incentive Compensation $1,002,104
Non-Productive Loading $1,586,480
Fire & Property Insurance $3,555,179
Computer Hardware Acquisitions $487,727
Safety Training Loader $722,796
Total $7,354,286
13 Items such as incentive compensation are not appropriate. Incentive compensation, to the
14 extent that is allowed in base rates in the first place, will not vary depending on whether
15 an employee's time is expended performing normal services or storm reserve related
16 activity. Thus, such charges easily can be anticipated and reflected in O&M expense.
17
18 Q. IS THE SAME SITUATION TRUE FOR NON-PRODUCTIVE AND SAFETY
19 TRAINING LOADERS AS IS THE CASE FOR INCENTIVE COMPENSATION?
20 A. Yes. The same is true for non-productive loaders and safety training loaders reflected in
21 the reserve.
22
195
Response to Rose City 5-1, including the ice storm.
196
P.U.C. Subst. Rule 25.23 l(b)(l)(G).
197
Response to Rose City 20-6 and Response to Cities 30-4 in Docket No. 34800.
110
1 Q. CAN THE COMPANY PROVIDE ANY DOCUMENTATION OR SUPPORT FOR
2 ITS INCLUSION OF HARDWARE ACQUISITION IN THE PROPERTY
3 INSURANCE RESERVE?
4 A. No. The Company was specifically requested to explain in detail and justify the inclusion
5 of costs associated with computer hardware acquisitions into the property insurance
6 reserve. The Company's entire response to the request for "all support" was that ''these
7 charges were related to and deemed necessary for storm restoration." 198 (Emphasis
8 added). The word "deemed" does not rise to the level of credible support for the inclusion
9 of computer hardware costs into the storm reserve.
10
11 Q. DO EXPENDITURES FOR FIRE AND PROPERTY INSURANCE PREMIUMS
12 QUALIFY FOR STORM INSURANCE RESERVE TREATMENT?
13 A. No. There is no credible claim that premiums for fire and property insurance are not
14 reasonably anticipated and includable in operations and maintenance expenses as noted in
15 the Commission's substantive rules. Indeed, beginning in December of 2007 the
1.6 Company no longer charged fire and property insurance premiums to its insurance
17 reserve. 199
18
19 Q. WHAT DO YOU RECOMMEND REGARDING THE COMPANY'S PRACTICE?
20 A. I recommend that the $3,555,179 of fire and property insurance premium charges be
21 removed from the claimed insurance reserve deficit.
22
23 Q. PLEASE DISCUSS YOUR NEXT ADJUSTMENT TO THE INSURANCE
24 RESERVE BALANCE ASSOCIATED WITH THE COMPANY'S PROPOSED
25 SITUS ADJUSTMENT.
26 A. As part of the Company's presentation of its current storm reserve deficiency, it identifies
27 a reapportionment of jurisdictional reserve balances due to an analysis during the
I 28 Jurisdictional Separation Plan split.200 As part of this analysis, the Company attempted to
' 198
199
200
Response to Rose City 21-33.
Response to Rose City 21-22.
Response to Rose City 5-1 Attachment 1, footnote 2.
111
I
1 shift $12,498,325 of charges previously recorded as Louisiana costs to the Texas
2 jurisdiction.201
3
4 Q. HAS THE COMPANY DEMONSTRATED THAT ITS PROPOSED
5 ADJUSTMENT IS APPROPRIATE?
6 A. No. In fact, the Company's presentation is an after the fact attempt to change the
7 historical allocation process.
8
9 Q. HAS THE COMMISSION PREVIOUSLY RECOGNIZED POTENTIAL
10 PROBLEMS WITH THE COMPANY'S AFTER THE FACT POLICY CHANGES
11 AS IT RELATES TO ALLOCATION OF COSTS BETWEEN JURISDICTIONS?
12 A. Yes. In Docket No. 34800, the Commission stated the change in the way that the
13 Company allocated its transmission costs is "a policy decision that should be made by the
14 Commission upon consideration of the facts and circumstances that necessitate such a
15 change. " 202 The Commission further stated that without "detailed analysis and findings of
16 fact, the Commission finds it inappropriate to change Entergy's transmission cost
17 allocation methodology as part of this case."203 In other words, the Company must make
18 a strong showing that its policy changes are appropriate before the Commission will
19 permit a shifting of cost previously charged to Louisiana to be reassigned to Texas
20 customers.
21
22 Q. HAS THE COMPANY PRESENTED A FULL AND COMPLETE ANALYSIS OF
23 ALL JURISDICTIONAL SEPARATION ISSUES IN THIS PROCEEDING?
24 A. No. Indeed, prior to allowing a change in the historical allocation of costs between
25 jurisdictions for the storm reserve, it is incumbent upon the Company to present and ...
26 justify that all historical jurisdictional charges are appropriately reflected in the
27 Jurisdictional Separation Plan. Failure to do so could and undoubtedly has resulted in
28 Texas retail customers already paying more than their fair share in comparison to
29 Louisiana ratepayers. Therefore, I recommend that the historical allocation of costs
201
Response to Rose City 17-26.
202
Docket No. 34800 Order on Remand page 10.
203 Id.
112
1 between Texas and Louisiana reflected in the storm reserve be retained. This
2 recommendation reverses the Company's proposed reassignment of costs.
3
4 Q. PLEASE DISCUSS YOUR NEXT ADJUSTMENT TO THE INSURANCE
5 RESERVE DEFICIT BALANCE.
6 A. In association with the securitization process relating to Hurricanes Rita and Katrina, the
7 Company has received insurance proceeds or has revised its insurance estimates
8 subsequent to the analysis reflected in Adjustment 15 to the Company's filing. 204 The
·. 9 Company states there have been two additional changes that impact the insurance related
10 amount reflected in the Company's filing. First, the actual proceeds for Hurricane Katrina
11 received in December 2009 exceeded the estimated proceeds by $7 ,290. Second, the
12 Company revised the estimated proceeds for Hurricane Rita that exceeded the previous
13 estimate by $1,511,688. 205 Therefore, the combined total of these two insurance proceed
14 related adjustments total $1,518,978 and should be recognized in this case.
15
16 Q. PLEASE DISCUSS YOUR LAST ADJUSTMENT TO THE INSURANCE
17 RESERVE DEFICIT BALANCE.
18 A. I recommend reversal of Company proposed Adjustment 15. This proposed adjustment
19 attempts to remove from the insurance reserve the unrecovered hurricane insurance
20 proceeds, insurance proceeds in excess of insurance proceeds included in the
21 securitization process and carrying costs. 206 ETI proposes to carve $25 million out of the
22 insurance reserve and establish a separate regulatory component for which it also
23 proposes a 5-year amortization. There is no valid basis for this proposed separate and
24 unique treatment. Therefore, ETI's proposed Adjustment 15, Hurricane Securitization,
25 should be eliminated by returning the $25 million amount to the insurance reserve. This
26 recommendation does not impact rate base, but does reduce the net annual amortization
27 by $3,791,732 due to the differing amortization periods (5 years for Adjustment 15
28 versus 20 years for storm insurance reserve).
29
204
Response to Rose City 23-21.
20s Id.
206
Testimony of Mr. Wright at page 20.
113
1 Q. WHAT DO YOU RECOMMEND?
2 A. I recommend that the storm reserve deficit balance be adjusted upward (less negative) by
3 $1,518,978 to reflect the additional funds received, or increased estimates by the
4 Company, for insurance proceeds relating to Hurricanes Katrina and Rita and by
5 $3,791,732 for reversal ofETI proposed Adjustment 15.
6
7 Q. WHAT IS THE IMPACT OF YOUR VARIOUS RECOMMENDATIONS TO THE
8 COMPANY'S CLAIMED CURRENT LEVEL OF STORM RESERVE
9 DEFICIENCY?
10 A. The Company claims a $64,355,152 current deficiency in its storm insurance reserve.
11 The adjustments previously discussed total $16,857,757, and reduce the Company's
12 claimed storm insurance reserve deficit to a deficit of $47,497,395.
13 3. Target Reserve
14
15 Q. WHAT TARGET RESERVE DOES THE COMPANY REQUEST IN THIS
16 PROCEEDING?
17 A. The Company proposes to increase the current $15,572,000 target storm reserve to
18 $19,304,000. This represents an increase of$3,732,000 or 24% above the current target.
19
20 Q. IS THE PROPOSED TARGET SIGNIFICANTLY DIFFERENT FROM THE
21 TARGET LEVEL PROPOSED IN DOCKET NO. 34800?
22 A. Yes. In Docket No. 34800, Mr. Wilson proposed a $37,110,000 total target amount to the
23 reserve. 207 While, the Company's proposed target level in this proceeding is noticeably
24 less than what was proposed approximately 2 years earlier, it is still excessive.
25
26 Q. HOW DID THE COMPANY DEVELOP ITS PROPOSED TARGET IN THIS
27 PROCEEDING?
28 A. Mr. Wilson ran a Monte Carlo simulation on Company loss history. Mr. Wilson
29 performed 5,000 iterations of simulated experience. Based on this simulation, Mr. Wilson
207
Direct Testimony of Mr. Wilson page 9 of 18 in Docket No. 34800, but included the anticipated impact of
major hurricanes.
114
I
l claims that in any 25-year period, the largest annual expected stonn loss totaling less than
2 a$100 million is approximately $19.3 million. 208
3
4 Q. DID MR. WILSON RELY ON THE MONTE CARLO ANALYSIS FOR THE
5 ESTABLISHMENT FOR THE TARGET RESERVE LEVEL IN THE LAST
6 CASE?
7 A. No. Mr. Wilson admitted that he did not use a Monte Carlo analysis in the last
8 proceeding.209
9
10 Q. DOES MR. WILSON'S MONTE CARLO SIMULATION INCLUDE THE
11 IMPACT OF THE PREVIOUSLY DISCUSSED 1997 ICE STORM?
12 A. Yes.210
13
14 Q. DID MR. WILSON INVESTIGATE ANY OF THE msTORICAL LOSS DATA
15 REFLECTED IN THE MONTE CARLO SIMULATION?
16 A. No. Therefore, Mr. Wilson cannot attest to the validity of his database as being
17 reasonable and necessary for ratemaking purposes. As previously discussed, the historical
18 analysis includes charges that are inappropriate for ratemaking purposes and thus,
19 overstates the target level even if it were to be appropriately based on a Monte Carlo
20 simulation.
21
22 Q. DO THE AMOUNTS REFLECTED IN MR. WILSON'S MONTE CARLO
23 SIMULATION ALSO INCLUDE HURRICANE RELATED COSTS?
24 A. Yes. While the Company has excluded the majority of hurricane related costs, it has still
25 included over $40 million of hurricane related costs that were not securitized in its
26 analysis. 211
208
Direct Testimony of Mr. Wilson at page 10.
209
Deposition of Mr. Wilson on April 22, 2010 at TR 30.
210
Id., at TR 28.
211
Response to OPC 2~ 1O(b).
115
1 Q. DID MR. WILSON NORMALIZE ms DATABASE PRIOR TO PERFORMING
2 THE MONTE CARLO SIMULATION?
3 A. No. While Mr. Wilson trended his historical loss data based on inflation considerations,
4 he failed to nonnalize for any other factors. Other factors include items such as
5 vegetation maintenance that the Company implemented after the 1997 ice stonn. any
6 process improvements developed as part of planning for stonn recovery activities, better
7 software mapping systems of the Company's service territory or other factors that would
8 change the resulting costs if the same stonn were to occur in the future.
9
10 Q. IN YOUR OPINION, IS THE msTORICAL DATABASE ARTIFICIALLY
11 SKEWED TO PRODUCE IDGH..SIDE COST ESTIMATES?
12 A. Yes. Mr. Wilson's sole efforts associated with attempting to recognize inflation and
13 failing to recognize any other factors that would offset costs results in a skewed database
14 that produces artificially excessive cost estimates.
15
16 Q. WHAT DO YOU RECOMMEND REGARDING THE TARGET STORM
17 RESERVE LEVEL?
18 A I recommend retaining the existing target reserve level. The existing target better
19 represents the historical data after adjustment for identifiable excesses reflected in the
20 losses (e.g., the 1997 ice stonn). Further, retention of existing target level also recognizes
21 that other factors (e.g., a more storm hardened system, computerized mapping systems,
22 etc.) other than inflation have changed from historical time periods that should result in
23 lower stonn losses even if the same event were to transpire in the future.
24
25 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
26 A. My recommendation results in a $2,732,000 reduction in the target level reserve. When
27 this amount is amortized over the same 20-year period proposed by Mr. Wilson, it
28 reduces the Company's storm insurance related revenue requirement by $186,600.
116
1 4. Annual Expected Losses
2
3 Q. WHAT DOES THE COMPANY REQUEST FOR ITS EXPECTED ANNUAL
4 STORM LOSSES?
S A. The Company proposes to accrue $5,270,000 annually in the self-insurance reserve to
6 cover expected losses for stonns each year. 212 This amount reflects Mr. Wilson's
7 expectation for annual storm losses, except for those storms over $100 million adjusted to
8 reflect cummt loss levels.213
9 Q. WHAT LEVEL OF ANNUAL EXPECTED STORM LOSSES DID MR. WILSON
10 PROPOSE IN DOCKET NO. 34800?
11 A. Mr. Wilson proposed an annual accrual of $13,840,000 for expected annual storm
12 losses.214
13
14 Q. HOW DID MR. WILSON DETERMINE HIS CURRENT $5.27 MILLION
15 ANNUAL STORM LOSS PROPOSAL?
16 A. Mr. Wilson again relied on the previously noted Monte Carlo simulation of the
17 Company's loss history. 215
18
19 Q. HOW DOES MR. WILSON'S CURRENT PROPOSAL COMPARE TO WHAT
20 THE COMMISSION HAS PREVIOUSLY ACCEPTED OR ADOPTED FOR
21 ANNUAL STORM LOSS LEVELS?
22 A. In Docket No. 16705, the Commission adopted a $1,651,320 annual storm loss level.
23 This amount was in place until 2009 when, based on the settlement adopted by the
24 Commission in Docket No. 34800, the annual amount was raised to $3,651,320 annually.
25 Thus, the parties and the Commission believed that a $3.65 million annual storm loss
26 level was reasonable and acceptable as recently as 1 year before the Company filed its
27 current case.
212
Direct Testimony of Mr. Wilson at page 7.
zu Id.
m Direct Testimony of Mr. Wilson in Docket No. 34800 at page 5.
215 Mr. Wi1son•s Direct Testimony at page 7.
117
1 Q. HAVE YOU REVIEWED MR. WILSON'S MONTE CARLO SIMULATION,
2 WIDCll FORMS THE BASIS FOR ms PROPOSAL?
3 A. Yes. As previously discussed, the Monte Carlo simulation is a new process employed by
4 Mr. Wilson. As previously noted, the database relied upon for simulation purposes
5 includes many significant levels of cost that are inappropriate for ratemaking purposes
6 and for purposes of predicting reasonable future expectations. In addition, the Company's
7 analysis fails to recognize any factor other than inflation that can and will impact the
8 severity of costs incurred in future storms. In addition, Mr. Wilson,s simulation over
9 estimates the number of storms eligible for inclusion in the stonn reserve, thereby
10 increasing the projected annual total of stonn related O&M expense of reach of his 5,000
11 iterations in his Monte Carlo simulation.
12
13 Q. HAS THE COMPANY PROVIDED ANY VALID BASIS ON WIDCH TO ADOPT
14 MR. WILSON'S FLAWED MONTE CARLO SIMULATION?
15 A. No.
16
17 Q. HAS THE COMMISSION RECOGNIZED THE VALIDITY OF RELYING ON
18 msTORICAL AVERAGES AS A REASONABLE APPROACH TO
19 ESTABLISIDNG EXPECTED ANNUAL STORM WSSES?
20 A. Yes. In Docket No. 35717, an Oncor Delivery case, the Commission accepted an annual
21 storm. loss expectation based in part on a 10-year average of storm cost values.216
22
23 Q. IS RELIANCE ON A 10-YEAR msTORICAL AVERAGE REASONABLE IN
24 TIDS CASE?
25 A. No. Given the significant spike of hurricane activity during the last 5 years, reliance on
26 too short of a historical average skews the reasonably expected results associated with
27 long-term weather conditions. Indeed, just the 2007 value, which includes approximately
28 $25 million of costs associated with Hurricane Humberto, noticeably skews any average
29 that relies on too short of a timeframe to an excessive level for purposes of future
30 projections. The 2007 level associated with Hurricane Humberto is more than 8QG/o
216
Docket No. 35717 Final Order at FOF 100 and page 111 of the Proposal for Decision.
118
1 greater than the next highest value reported in the Company's database, that being 1997.
2 As previously noted, the 1997 value includes over $13 million associated with the most
3 severe ice stonn the Company has ever experienced and which reflects excessive cost
4 levels due to inappropriate actions by the Company. Removing the 1997 storm-related
5 activity renders the 2007 Humberto related value at over 1500/o greater than the next
6 highest value reflected in the Company's 20 plus year historical database. Therefore,
7 reliance on a I 0-year historical period only serves to artificially inflate the expected
8 annual storm loss level.
9
10 Q. HAVE YOU ANALYZED THE HISTORICAL DATA FROM THE STANDPOINT
11 OF ESTABLISIDNG A REASONABLE ANNUAL STORM LOSS?
12 A. Yes. Review of the historical data, even on a trended loss basis, but absent the impact of
13 the category 1 Hurricane Humberto, indicates that the current existing $3.651 million
14 annual storm loss accrual would be both reasonable and adequate level for annual storm
15 loss accruals. The reasonableness of the existing annual stonn loss level is especially true
16 taking into considerations that the historical data still contains inappropriate storm loss
17 charges for ratemaking purposes. Indeed, both the IO-year and 20-year average of the
18 trended annual storm loss levels, excluding Hurricane Humberto and the 1997 ice storm
19 costs, each yield approximately the existing $3.651 million annual storm loss expected
20 cost approved by the Commission and agreed to by all parties in Docket No. 34800.217
21
22 Q. IS THERE ANOTHER CONSIDERATION THAT MUST BE RECOGNIZED IN
23 ESTABLISHING THE ANNUAL STORM LOSS VALUE?
24 A. Yes. The way the process works is that the annual accrual remains constant until the next
25 rate proceeding. Therefore, the stonn loss reserve was only increased by the $1.651
26 million annual accrual adopted in Docket No. 16705. However, the collection of that
27 amount through base rates is predominantly based on energy charges. Given that there
28 has been growth on the system since 1996, the Company's actually collected through
29 base rates much more than the $1.651 million annual accrual. However, customers have
30 not received the benefit of the annual additional amount that the Company has recovered
217
The JO-year average trended loss value is $3.8 million. while the 20-year avenge is $3.6 million.
119
1 through base rates for the insurance reserve annual stonn amounts. Therefore, the higher
2 the annual storm reserve amount set, the greater amount the Company actually recovers
3 from customers over time, but for which it does not credit customers. Such amounts
4 become additional return for the Company, rather than a credit to the insurance reserve.
5
6 Q. WHAT DO YOU RECOMMEND?
7 A. Based on the approaches discussed above, I recommend retention of the recently adopted
8 $3,651,320 annual stonn loss value. This results in a $1,618,680 reduction to the
9 Company's request.
IO 5. Minimum Storm Reserve Threshold
11
12 Q. WHAT IS THE CURRENT STORM RESERVE THRESHOLD?
13 A. Any storm-related property loss of at least $50,000 is accounted for in the storm
14 reserve. 218
15
16 Q. WHAT IS THE BASIS FOR THE 550,000 MINIMUM THRESHOLD LEVEL?
17 A. Other than having been approved prior to Docket No. 16705, the Company could not
18 provide any narrative explanation on how the $50,000 level was detennined.219
19
20 Q. HOW OFfEN HAS THE COMPANY REVIEWED THE $50,000 THRESHOLD
21 FOR REASONABLENESS?
22 A. The Company could not identify a single instance in which it has reviewed the $50,000
23 minimum threshold for reasonableness.220
218
Response to Rose City 9-2.
219
Response to Rose City 9-3.
220
Id.
120
1 Q. HAS TIIE COMPANY COMPARED ITS SS0,000 MINIMUM THRESHOLD TO
2 ANY OTHER UTILITIES FOR PURPOSES OF DETERMINING
3 REASONABLENESS?
4 A. No. The Company states that it "has not compared its stonn ~rve policies with any
5 other utility."22 1
6
7 Q. IS THE SS0,000 MINIMUM TIIRESHOLD REASONABLE?
8 A. No. The Company has incurred 155 stonns that it claims qualify for stonn reserve
9 treatment subsequent to Docket No. 16705.222 This represents in excess of 10 storms per
10 year, not counting Hurricane Rita and Hurricane Ike. Occurrences of this frequency on an
11 annual basis cannot credibly be claimed to comply with the Commission's rules that are
12 intended to allow for storms, "which could not have been reasonably anticipated.',m
13 Moreover, the threshold only encourages the Company to accumulate as many charges as
14 possible associated with, or around, a stonn in order to reach the low $50,000 threshold.
15 By reaching such threshold and attempting to employ stonn reserve treatment, the
16 Company can inappropriately manipulate its annual earnings.
17
18 Q. DOES THE MINIMUM SS0,000 THRESHOLD COMPORT WITH THE
19 COMMISSION RULE AS IT APPLIES TO THE COMPARISON TO
20 COMMERCIAL INSURANCE?
21 A. No. Indeed, during Mr. Wilson's deposition, he stated that the "deductibles are extremely
22 high" when discussing how insurance companies would set the deductible for the same
23 service.224 Mr. Wilson's statement was made with knowledge of the $50,000 lower
24 threshold for the Company's insurance stonn reserve. Therefore, Mr. Wilson recognizes
25 that insurance compWlies would set a deductible level far in excess of the current $50,000
26 level employed by the Company.
221 Id.
222
Response to Rose City 5-1.
221
P.U.C. Subst Rule 25.23 l(bXl)(G}.
:m Mr. Wilson's deposition on April 22, 2010 at TR 11.
121
1 Q. HAS THE COMMISSION RECENTLY RULED ON THE ISSUE OF WHAT
2 CONSTITUTES A REASONABLE MINIMUM INSURANCE THRESHOLD
3 DEDUCTmLE LEVEL?
4 A. Yes. In Docket No. 35717, an Oncor Delivery case, the issue as to whether to increase the
5 minimum threshold level to $10 million was raised. Oncor's witness stated that the
6 "demarcation point at $500,000 is the hallmark in risk management because losses under
7 $500,000 are considered routine and predictable. Anything over that loss cannot be
8 predicted."225 The Commission in Docket No. 35717 accepted the $500,000 minimum
9 threshold for storm reserve treatment. 226
10
11 Q. WHAT DO YOU RECOMMEND?
12 A. I recommend increasing the minimum threshold level from $50,000 per storm to
13 $500,000 per stonn and treating the threshold as a deductible. This level complies with
14 the Commission's rule as it relates to stonns that could not have been reasonably
15 anticipated and is equivalent to what the Commission recently adopted when this issue
16 was contested in Docket No. 35717. This level will further eliminate any unreasonable
17 efforts by the Company to aggregate charges so as to meet the low threshold currently in
18 place and thus remove any incentive for manipulating reasonably predictable O&M
19 expense.
20
21 Q. WHAT IS THE COMBINED IMPACT OF YOUR VARIOUS
22 RECOMMENDATIONS?
23 A. My various recommendations would result in a $3.9 million reduction to the Company's
24 expense request for storm damage reserve and a $45.868 million reduction to rate base.
225
Docket No. 35717 Proposal for Decision at page 106.
226
Docket No. 357 J7 Final Order FOFs 98-101.
122
1 SECTION VI: CASH WORKING CAPITAL
2 1. Introduction
3
4 Q. WHAT IS THE ISSUE IN nus PORTION OF YOUR TESTIMONY?
5 A. This portion of my testimony deals with ewe. ewe is a component of rate base and
6 represents the amount of funds supplied by either the shareholders or others, such as
7 customers, to fund the day-to-day operations of the Company.
8
9 Q. HOW DID THE COMPANY ARRIVE AT ITS PROPOSED CWC?
10 A. The Company has attempted to perform a lead-lag study in its efforts to quantify its CWC
11 requirements. The type of study is a cash lead-lag study as required by P.U.C. Subst. R.
12 25.231(c)(2)(BXiii)(IV).
13
14 Q. WHAT HAS THE COMPANY PROPOSED FOR CWC?
15 A. The Company has proposed a negative $1,979,613 of CWC.n7 However, the Company
16 has also admitted to two errors relating to state and local franchise fees. 228 The coJTeCtion
17 for those two errors yields a negative $4,869,630 ewe requirement.
18
19 Q. WHAT LEVEL OF CASH WORKING CAPITAL DID THE COMMISSION FIND
20 APPROPRIATE FOR THE COMPANY IN ITS LAST FULLY LITIGATED
21 RATE CASE?
22 A. ln Docket No. 16705, the Commission ordered a negative $36,016,000 ewe compared
9
23 to the Company's request for a negative $8,053,000 CWC in that casen In other words,
24 the Commission found errors and made adjustments that more than quadrupled the
25 negative level of ewe requested by the Company. My testimony in that case, upon
26 which the Commission relied in part, also addressed various errors and inappropriate
27 positions taken by the Company.
227 Schedule E-4 page 2.
228
Response to State of Texas 8-9.
229
Docket No. 16705 Final Order Schedules lV and Vl.
123
l Q. PLEASE SUMMARIZE YOUR RECOMMENDATIONS IN TIUS PROCEEDING
2 AS IT RELATES TO YOUR REVIEW OF THE COMPANY'S ewe REQUEST.
3 A. The Company's negative ewe estimate is again substantially inadequate {i.e. too little
4 level of negative CWe). A more appropriate level ofCWC is a negative $45.7 million or
5 $43. 7 million more negative than the Company's original request as set forth on Schedule
6 {JP-4). While, again in this case, there are many problems associated with the
7 Company's lead-lag study, I have attempted to correct mainly the major components and
8 make adjustments to comport with Commission precedent A summary of the specific
9 areas and issues follows.
10
11 • Meter·To-Billing Revenue Lag. In spite of expenditures for electronic meter
12 reading equipment, new computer hardware and software, the Company proposes
13 a longer period of time necessary to read a meter and issue a bill than in the past
14 This attempt to rely on a longer period of time signifies that the Company
15 believes it has become less efficient. The regulatory principle that customers
16 should not shoulder the burden of the Company's inefficiencies must be
17 recognized in the lead-lag study. Relying on a meter-to-billing period previously
18 achieved by the Company results in $4,973,701 more negative ewe.
19
20 • BiUing-To-Payment Revenue Lag. The Company relies upon an inappropriate
21 methodology to estimate the time period between when it bills a customer and
22 when a customer pays their bill. Moreover, Company's estimation process
23 reflects the unusual affect of the worldwide financial meltdown that began in the
24 last quarter of 2008. In addition, the Company proposes a 60-day lag for its MSS-
25 4 affiliate transaction. My recommended methodology relies on a previously
26 accepted approach, with a modification that will eliminate a concern raised by the
27 Commission in Docket No. 16705, and removal of the MSS-4 affiliate transaction
28 results in $26.2 million more negative ewe.
29
30 • Customer Float Revenue Lag. The Company proposed a customer float revenue
31 lag of 0.95 days for its retail revenues based on an estimation it believes to be
32 reasonable. The Company's estimation is based on customer count rather than
33 revenues. When revenues are used for the calculation, the float days decline to
34 0.49 days. The adjustment to the Company's proposed customer float results in
35 $1.6 million more negative ewe.
36
37 • Payroll Expense Lead. The Company's proposed lead-lag study does not
38 conform to Commission precedent in Docket No. 16705 as it relates to the service
39 period associated with vacation pay. The Company's attempt to ignore the
40 Commission's decision in Docket No. 16705 stems from its illogical and
41 inappropriate attempt to inconsistently measure the service period for expenses as
124
1 a period when the expense is recorded rather than when the product or service is
2 provided. In addition, the Company also failed to properly recognize the deferred
3 compensation aspect associated with incentive compensation. Reversal of the
4 Company's attempt to not follow the Commission's previous order relating to
5 vacation pay and proper treatment of incentive pay results in $6.3 million more
6 negative ewe.
7
8 • FAS 106 Expense Lead. In Docket No. 16705, the Commission adopted a
9 312.55 day expense lead for FAS 106 expenses. The Company again ignores that
10 decision by excluding the expense. This is another instance where the Company
11 attempts to employ an illogical and inconsistent approach in order to artificially
12 increase revenue requirements. Complying with Commission precedent on this
13 issue results in $2.2 million more negative ewe.
14
15 • Entergy Services, Inc. Expense Lead. The Company has proposed 38.04 lead
16 days for this category of CWC. The Company bases its lead day proposal on its
17 operating agreement with Entergy Service, Inc. That agreement permits payment
18 no later than the 25th of the following month. The major problem with the
19 Company's analysis is its failure to recognize that a substantial component of the
20 amount at issue is associated with incentive compensation. Proper recognition of
21 the extended lead days associated with incentive compensation results in $5.6
22 million of more negative ewe.
23
24 • Other O&M Expense Leads. As was the case in prior dockets, the Company
25 has made errors in its stratified sample of invoices used to determine the
26 appropriate expense leads for other O&M. Correction of certain problems in the
27 Company's current stratified sample analysis increases the expense lead days by
28 15.52 days resulting in $3.6 million of more negative ewe.
29 Due to the interactive nature between revenue lags and expense leads, the combined
30 impact of the above various adjustments is not simply the addition of each individual
r 31 component. Rather, the combined impact is $45.7 million, or $43.7 million more
32 negative CWC as set forth on Schedule (JP-4).
33
34 2. General
35
36 Q. WHAT ISALEAD-LAGSTUDY?
37 A. A lead-lag study is an attempt to measure the value of the difference between the time the
38 Company provides services to its customers and the time it receives payment for such
39 services, compared to the time the Company receives a product or service and the time it
125
1 pays for such product or service. As part of the lead-lag study, an attempt is made to
2 measure the revenue lag and compare it to an expense lead. 230
3
4 Q. WHAT ARE THE COMPONENTS OF THE REVENUE LAG?
5 A. Within the revenue lag component of a lead-lag study there are four components: the
6 service period, the billing lag, the collection lag, and the financial or customer lag. The
7 service period normally represents the mid-point of the month in which service is
8 provided. The billing lag represents the time period between the date a meter reading is
9 taken and a bill is issued to the customer. The collection lag is the period between the
I0 time the Company issues a bill to the customer and the date the customer pays the
11 Company. Finally, in instances where the Company receives payment in a form other
12 than cash or electronically, it is considered a :financial lag until funds become available.
13
14 Q. WHAT ARE THE COMPONENTS OF THE EXPENSE LEAD?
15 A. Normally for an electric company, the largest single component of expense leads is its
16 cost of energy, whether it is through self generation (e.g., coal, oil, gas, or nuclear) or
17 through purchase power costs. Other components are labor, other O&M, property taxes,
18 etc. The Company has identified many categories as set forth on Schedule E.
19
20 Q. IS THERE A MAJOR ISSUE REFLECTED IN THE COMPANY'S CONCEPT OF
21 A LEAD-LAG STUDY THAT IS CONTRARY TO COMMISSION PRECEDENT?
22 A. Yes. Company witness Mr. Gallagher states that "a central issue in the measurement of
23 both revenue and expense payment lags is a consistent definition of the Service Period -
24 i.e., the date the utility provides services to its customers for which it incurs costs and
25 accrues revenues and expenses. 231 (Emphasis added). Unfortunately, while Mr.
26 Gallagher desires consistency, the Company's practice, with his oversight, is anything but
27 consistent.
28
230
I
The revenue lag represents the claimed time period between date(s) the Company provides service to
customers and the date(s) the Company receives funds from the customer for such service. An expense
lead is the time period between the date(s) the Company receives a product or service and the date(s) it
pays for such product or service.
I
231
Direct Testimony of Mr. Gallagher at page 8.
126 I
1 Mr. Gallagher's discussion of service period between expenses and revenues violates
2 prior Commission decisions as well as logic and consistency. In particular, Mr.
3 Gallagher would have the Commission believe that it is logical and consistent to measure
4 the revenue lag as the time period during which customers receive service. For example,
5 if a customer's meter readings occur on April and May 1st, the service period is one
6 month or 30 days. On average, the customer will have received the service 15 days into
7 the 30-day period. This concept of service period has nothing to do with the fact that the
8 recording of the actual revenues that will be charged to the customer do not occur until
9 later in May when the billing process is completed. Alternatively, Mr. Gallagher would
10 have the Commission believe that the service period associated with expenses occurs
11 only when the recording of labor, materials or other costs occur. In other words, he
12 would have the Commission believe that the Company has not received a product or
13 service until it accrues or books the expense not when it receives a product or service.
14 This inconsistent logic between revenue and expense service periods must be recognized
15 for what it is, a direct attack on the Commission's prior decisions and a clear indication
16 of the Company's desire to artificially minimize the negative level of CWC that should
17 be reflected in rate base.
18 3. Revenue Lag
19 A. Meter Reading To Billing
20
21 Q. WHAT HAS THE COMPANY PROPOSED FOR ITS METER READING TO
22 BILLING REVENUE LAG?
I 23
24
A. The Company proposes 3.63 days associated with its Customer Information System
("CIS") related customers and 3.72 days for large power customers. 232
i 25
26 Q. ARE THESE REASONABLE LEVELS?
l 27 A. No. The Company has invested money into electronic meter reading devices and
28 expensive computer systems that incorporate billing systems. One would hope that the
l 29 expenditures of large amounts of capital on such equipment and software would result in
232
Company Work.paper WP/E-4 page 3.
127
1 recognizable benefits for customers given that customers must pay a return of and a
2 return on such investments. Unfortunately in this area, the Company has become less
3 efficient in the billing process in spite of such substantial capital expenditures.
4
5 Q. HAVE OTHER REGULATORY BODIES RECOGNIZED THE MORE
6 EFFICIENT BILLING PROCESS ASSOCIATED WITH MORE MODERN
7 ELECTRONIC METER READING DEVICES AND BILLING SYSTEMS?
8 A. Yes. The Railroad Commission of Texas ("RCT'). the regulator of gas utilities in Texas,
9 has adopted a I -day meter reading to billing lag for the largest gas utility in the state. 233
10 Moreover, the RCT adopted such shorter period of time in spite of the gas utility's
11 request to increase the number of days so as to permit verification of potential erroneous
12 billings. 234 The adoption of that position was based, in part, on my testimony in those
13 proceedings. The guiding principle for the RCT decision was that customers "should not
14 be punished if a utility decides to manage the business process and payment less
15 efficiently."235
16
17 Q. IS THE RCT'S GUIDING PRINCIPLE A REASONABLE AND APPROPRIATE
18 STANDARD?
19 A. Yes. If the Company elects to allow inefficiencies in the billing process that results in
20 higher cost to customers, then such costs should be borne by shareholders, not customers.
21 As previously noted, the customers are already paying for equipment and software that
22 provide the capability of performing the billing process in a much more efficient manner.
23 Moreover, this Company has demonstrated that it can and has completed the meter
24 reading-to-billing process in as little as 1.46 days for the equivalent to the CIS customer
25 class which comprises the majority of customers and revenues. 236
233
RCT GUD 9869, Atmos Gas Company.
234
RCT GUD No. 9670 Final Order FOF 126, and GUD No. 9902.
235
RCT GUD No. 9670 Final Order at FOF 148.
236
Company Workpaper WP/E-4 page 26 of 47 in Docket No. 12852 also set forth as Exhibit (JP-16) in Mr.
Pous' Testimony in Docket No. 16705.
128
1 Q. WHEN YOU STATE THAT THE METER READING-TO-BILLING PERIOD
2 HAS INCREASED RATHER THAN DECREASED, ARE YOU JUST
3 REFERRING TO THE 1.46 DAY PERIOD PREVIOUSLY REFERENCED?
4 A. No. While it obviously has increased from Docket No. 12852, it has also increased from
5 Docket No. 16705 where the Company proposed a 3.61-day meter reading-to-billing lag.
6 It is apparent that the Company, absent proper direction from this Commission to
7 demonstrate that it will not tolerate inefficiencies in the billing process, will have a
8 perverse incentive to perfonn in a manner that is detrimental to customers. In fact, the
9 Company has every incentive to be inefficient in this particular area because it earns a
10 full rate of return on the higher level of cash working capital due to its own inefficiencies.
11 The continuation of this situation is neither reasonable nor equitable.
12
13 Q. WHAT DO YOU RECOMMEND?
14 A. I recommend that the Commission follow the lead of the RCT and adopt a principle that
15 customers "should not be punished if the utility decides to manage the business process
16 and payment less efficiently." The Company's incentive to operate inefficiently by
17 earning a higher return is neither reasonable nor appropriate. The Company has
18 demonstrated that it can issue a CIS bill within 1.46 days after reading meters. The
19 largest gas utility in the state has demonstrated that it can read meters and bill either on
20 the same day or within one day and has its base rate set on a 1-day meter reading to
21 billing period. Customers are paying for investment in meter reading devices, computers,
22 and software that make it possible to perform the meter reading process in a more
23 efficient manner. Customers are entitled to the benefit of the bargain associated with
24 such expenditures. Based on the various items noted above, I conservatively recommend
25 that a 1.46 day meter reading-to-billing lag for CIS related customers be adopted. This is
26 a level that the Company has demonstrated that it can achieve even prior to its investment
27 in the newer meter reading devices, computers, and software.
129
l Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
2 A. My recommendation on a standalone basis would result in a $4,973,701 more negative
3 CWC requirement than what the Company proposed.237
4 B. Billing-To-Payment Revenue Lag
5
6 Q. WHAT BAS THE COMPANY PROPOSED FOR THE REVENUE LAG DAYS
7 ASSOCIATED WITH THE PERIOD BETWEEN ISSUING BILLS AND
8 RECEIVING PAYMENT FROM CUSTOMERS?
9 A. The Company has identified 4 separate revenue lag periods for this component of the
10 lead-lag study. The Company has proposed 22.26 days for its CIS customers, 16.21 days
11 for its large power customers, 60 days for MSS-4 sales, and 20 days for its other affiliated
12 sales.238
13
14 Q. DO YOU TAKE ISSUE WITH ANY OF THE COMPANY'S PROPOSALS?
15 A. Yes. I take issue with the Company's proposed 21.80 days for its CIS customers which
16 comprise approximately 53% of the entire revenues, and the 60-day lag proposed for
17 MSS-4 affiliate revenues. 239
18
19 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSED 21.80 REVENUE
20 LAG DAYS FOR ITS CIS CUSTOMERS?
21 A. The Company relies on an inconsistent accounts receivable turnover niethod. 240 As will
22 be discussed later, the Company attempts to relate an end of month amount of accounts
23 receivable to daily average revenues.
24
25 Q. IS THE COMPANY'S OVERALL APPROACH TO THE BILLING TO
26 COLLECTION REVENUE LAG DAYS APPROPRIATE?
27 A. No. While the Company's actual mechanics has problems, the overall process employed
28 by the Company is inaccurate. The Company relies on an end of month accounts I
237
Schedule E-4 page 2 of 2 average daily amount of $4,324,957 times l .15 days (3 .63-1.46) X .528732.
238
Company Workpaper WP/E-4 page 3.
239
Company Workpaper WP/E-4 page 3.
240
Id, at page 17.
130
1 receivable balance and compares that to the average daily revenues. The problem with
2 this approach rests on the premise that the end of month accounts receivable balance is
3 equivalent to the individual daily accounts receivable balances throughout the month.
4 Given that the Company has 21 different billing cycles throughout the month, the
5 accounts receivable monthly ending balance is skewed towards customers billed in the
6 later billing cycles and does not reflect the relationship experienced by those customers
7 billed in the early billing cycles of the month who have already paid their bill and are no
8 longer reflected in accounts receivable at the end of the month.
9
IO Q. HAS THE COMPANY'S APPROACH RECENTLY BEEN TESTED IN TEXAS?
11 A. Yes. In RCT Docket No. 9670, Atmos Energy, the state's largest gas company, proposed
12 the same approach. The RCT found that such approach was unacceptable based in part
13 on my testimony. Distortions can occur due to the difference between daily accounts
14 receivable balances compared to a month end accounts receivable balance in a turnover
15 analysis. This problem can result in several revenue lag days of difference in the
16 Company's billing-to-collection lag.
17
18 Q. HAS THE COMPANY'S BILLING-TO-COLLECTION LAG CHANGED OVER
19 TIME?
20 A. Yes. While the Company proposes 21.80 days in this proceeding for its CIS customers, it
21 proposed only 19.02 days in Docket No. 30123. 241 Moreover, in Docket No. 16705 the
22 Company proposed 21.63 days and in Docket No. 12852 the Company proposed 19.6
23 days. 242 It also proposed 19.67 days in Docket No. 20150 and 22.26 days in Docket No.
24 34800. 243 Therefore, the Company's proposal in this proceeding represents its second
\
25 highest requested value over the past numerous rate proceedings and is 1.48 days greater
26 than the level in place during Docket No. 12852 and 1.41 days greater than the 19.67
27 billing-to-payment revenue lag in Docket No. 20150.
241
Docket No. 30123 Company Workpaper WP/E-4 page 2.
242
Docket No. 12852 Company Workpaper WP/E-4 page 26 of 47.
243
Workpaper WP/1-A-1-111.1 AJ12-1 in Volume 40-VL at page 838 in Docket No. 22356 and Workpaper
WP/E-4 page 4 in Docket No 34800.
131
1 Q. DID YOU SEEK INFORMATION NECESSARY TO QUANTIFY A MORE
2 ACCURATE BILLING-TO-COLLECTION REVENUE LAG FOR THE
3 COMPANY IN THIS CASE?
4 A. Yes. I sought the Company's daily accounts receivable balances for retail sales, the
5 aging of accounts receivable reports for each month of the test year, and the daily revenue
6 receipts during the test year. The Company does not maintain all such information. 244
7
8 Q. IS THERE AN ADDITIONAL PROBLEM WITH RELYING ON THE
9 ACCOUNTS RECEIVABLE DATA EMPLOYED BY THE COMPANY?
10 A. Yes. The test year data includes the period during which this country, if not the world,
11 experienced a financial meltdown and was on the brink of financial collapse. Credit dried
12 up for both individuals and companies. Reliance on this period, August 2008 and for an
13 extended period thereafter, unrealistically skews the revenue lag upward. Therefore, even
14 if the Company's proposed approach were relied on, which it should not be, it is
15 excessively high due to the period contained in the analysis.
16
17 Q. CAN YOU PROVIDE AN EXAMPLE OF THE DISTORTION CAUSED BY
18 RELYING ON DATA CORRESPONDING TO THE PERIOD OF ECONOMIC
19 TURMOIL?
20 A. Yes. A proxy for the impact can be seen from the month end accounts receivable reports
21 for October 2008 and 2009. The October 2008 report identified $1,353,134 of arrears for
22 the 90-day category, while the same value for October 2009 was only $200,111. The 90
23 days in arrears level of accounts receivable during the thick of the financial meltdown
24 was almost 7 times the level one year later. 245 There were similar situations in other
25 arrears categories.
1
J
244
Response to Cities 9-18.
245
Response to Cities 9-6.
132
1 Q. GIVEN THE CIRCUMSTANCES THE COMPANY HAS PRESENTED, WHAT
2 DO YOU RECOMMEND?
3 A. The Company's current request is obviously incorrect and cannot be relied upon.
4 Unfortunately, the Company was unable to provide necessary information associated
5 with the current test year as it pertains to daily accounts receivable balances or even daily
6 revenues. Therefore, I recommend a modified aging of accounts receivable approach
7 adopted in Docket No. 16705.
8
9 In Docket No. 16705, the Company provided aging of accounts receivable information.246
10 I recommended an adjustment in that proceeding relying on that information, with one
11 assumption not adopted by the Commission. That assumption was that for those
12 customers under the current pay category, I assumed a conservative 14-day period while
13 the Commission rules allow up to 16 days.247 The examiners denied this approach since
14 they could "find no reason to justify changing the Commission-required 16-day paid
15 schedule."248 However, the examiners did say they questioned "whether the disconnects
16 really tipped the balance to 16."249 While I still believe that the 14-day assumption was
17 conservative given that all customers who are current do not pay on the very last day
18 possible, I base my recommendation in this case on adopting the full 16-day payment
19 period allotted by the Commission. In other words, I modified the values set forth on
20 Schedule (JP-17) page 1 of2 in Docket No. 16705 and increased the revenue lag days for
21 the current balances from 14 to 16 days. Increasing the payment period assumption to the
22 absolute maximum permitted by the Commission rules would increase my previously
23 proposed 18.66 revenue lag days to 20.38 days (an additional 1.72 days to reflect 2
24 additional days time for 85.97 % of customers that pay currently).
246
Docket No. 16705 Company response to Cities 97 - 1 as shown on Schedule (JP-17) in that case.
247
PUC Subst. R. 25.28.
248
Docket No. 16705, PFD at Section F 2 (a).
249 Id.
133
l Q. DO YOU BELIEVE TIDS APPROACH IS MORE REPRESENTATIVE THAN
2 THE COMPANY'S PRESENTATION?
3 A. Yes, and for the various reasons noted above, the Company's position is in error. The
4 Company's position is not only excessive but unsupportable. The Company has elected
5 not to maintain the type of data that would permit a more accurate current calculation.
6 Moreover, the Company's proposal is approximately 2.5 days greater than what it has
7 proposed in several prior proceedings. In comparison, my proposed 20.38 days is less
8 than half the difference between what the Company has previously proposed and what it
9 currently proposes and is based on real Company data associated with aging of accounts
10 receivable information utilizing the most conservative assumption for current billings.
11
12 Q. DO YOU BELIEVE YOUR ESTIMATE IS TOO CONSERVATIVE?
13 A. Yes I do. However, given the examiners concerns in Docket No. 16705 and the current
14 situation that the Company has placed both the interveners and Commission in, I find that
15 this conservative approach should cure any concern the Commission previously had in
16 Docket No. 16705 on this issue. Moreover, to the extent the Commission was so inclined
17 and elects to adopt my previous position based on an average 14-day payment period
18 versus the full 16 days permitted under the rule, then the revenue lead would need to be
19 reduced by an additional 1.72 days, or $3,933,198.
20
21 Q. WHAT IS THE IMPACT OF YOU RECOMMENDATION?
22 A. My recommendation of a 20.38 bill-to-payment revenue lag for the CIS class results in a
23 $3,243,718 reduction to rate base (1.42 days x $4,324,957 x 52.8732%).
24
25 Q. WHAT IS THE ISSUE WITH THE COMPANY'S PROPOSED 60-DAY BILLING
26 TO PAYMENT PERIOD FOR MSS-4 SALES?
27 A. Cities' witness Mr. Garrett recommends the removal of the EGSL Sabine and Lewis
28 Creek MSS-4 sales transactions from the Texas retail cost of service. Therefore, I have
29 removed this component from the revenue lag. I
I
134
I
i 1 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
2 A. My recommendation results in a $14.4 million reduction to CWC requirements. 250
3 c. Customer Floa t
I 4
5 Q. WHAT HAS THE COMPANY REQUESTED FOR THE REVENUE LAG DAYS
6 ASSOCIATED WITH THE CUSTOMER FLOAT CATEGORY?
7 A. The Company has proposed a lag of0.95 days for the CIS and Large Power categories. 251
8
9 Q. WHAT DOES THIS AMOUNT REPRESENT?
10 A. The Company states this amount represents the check float corresponding to the period
11 that funds from payment by customers are not available to the Company because checks
12 for payments have not cleared from the customers accounts to the Company's account. 252
13
14 Q. WHAT IS THE COMPANY'S BASIS FOR THE 0.95 DAY REQUEST?
15 A. Mr. Gallagher states that "it ap_pears that after taking into account immediate cash
16 available from electronic funds transfer" that a 0.95 weighted lag days for retail sales is
17 appropriate. 253 (Emphasis added).
18
19 Q. HAS THE COMPANY JUSTIFIED ITS REQUESTED CUSTOMER FLOAT?
20 A. No. First, the Company's proposal is based on customer count and not dollars. 254
21
22 Q. IS IT APPROPRIATE TO RELY ON A CUSTOMER COUNT RATHER THAN
23 ON THE CORRESPONDING REVENUES?
24 A. No. Indeed, the revenue float is quite different from what Mr. Gallagher proposes. The
25 Company admits that at least 51 % of its revenues were received in the form of cash, wire
250
Total revenue lag days decline to 39.84 ifMSS-4 revenues are removed. This represents a 3.33 reduction in
revenue lag days from ETI's proposed level of 43.17 days (3.33 x $4,324,957 = $14,408,915).
251
Company Workpaper WP/E-4 page 3.
252
Mr. Gallagher's Direct Testimony at page 13.
253
Company Workpaper WP/E-4 pages 14-16.
254
Company Workpaper WP/E-4 page 7.
135
I
1 transfer or other electronic manners. 255 Recognition of cash and electronic payments by 1
2 dollar amount rather than by count reduces the 0.95 check float to 0.49.
3 I
4 Q. WHAT DO YOU RECOMMEND?
5
6
A. I recommend the Company's request for a 0.95-day customer float be denied.
Company's request is based on the wrong factor (customer count rather than revenues).
The I
7 Therefore, I recommend a 0.49-day check float lag for the CIS and Large Power classes. I
8
9 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
10 A. My recommendation for a 0.49-day customer float reduces rate base by $1,612,822
11 ((0.95-0.49) x $4,324,957 x 81.06753%).
12
13 Q. WHAT IS THE NET IMPACT OF YOUR VARIOUS REVENUE LAG
14 RECOMMENDATIONS?
15 A. The adoptions of the revenue lag adjustments that I have recommended would reduce the
16 Company's overall revenue lag days from 43.17 days to 37.12 days or 6.05 less revenue
17 lag days. A 6.05 reduction in revenue lag days would result in a reduction to rate base of
18 $26,169,306 based on the Company's requested level of expenses.
19 4. Expense Leads
20 A. Payroll
21
22 Q. WHAT HAS THE COMPANY PROPOSED FOR EXPENSE LEAD DAYS
23 ASSOCIATED WITH PAYROLL?
24 A. The Company proposes 14.55 lead days for the expense lead. 256
255
Response to Rose City 9-12.
256
Company Work.paper WP/E-4 page 2.
136
1 Q. IS THE COMPANY'S PROPOSED PAYROLL EXPENSE LEAD DAYS IN
2 COMPLIANCE WITH THE COMMISSION'S ORDER IN DOCKET NO. 16705?
3 A. No. In Docket No. 16705 at FOP 114, the Commission adopted the position I sponsored
4 in that case. In doing so the Commission stated that "recognizing vacation time as a
5 separate component of payroll to account for the lag between when the employee earns
6 vacation time and when the Company pays for it in salary expense" is reasonable.
7 Unfortunately the Company• s calculation in this case fails to recognize the significant
8 incremental time period associated with vacation pay.257
9
10 Q. DOES THE COMPANY IDENTIFY ANY CHANGED CIRCUMSTANCES THAT
11 WARRANT THE REVERSAL OF THE COMMISSION'S PRECEDENT ON
12 THIS ISSUE?
13 A. No.
14
15 Q. WHAT DID YOU RECOMMEND FOR THE EXPENSE LEAD ASSOCIATED
16 WITH VACATION THAT WAS ADOPTED BY THE COMMISSION IN
17 DOCKET NO. 16705?
18 A. As set forth in my testimony in Docket No. 16705 at page 99, I recommended a 210.67
19 day period as the appropriate expense lead days for vacation pay.
20
21 Q. DO YOU STILL BELIEVE THIS LEVEL IS REASONABLE AND
22 APPROPRIATE?
23 A. Due to the change in relationship of vacation pay to total payroll, I am of the opinion the
24 recommended level is conservative.
25
26 Q. WHAT LEVEL OF VACATION PAY DID THE COMPANY INCUR DURING
27 THE TEST YEAR IN THIS PROCEEDING?
28 A. The Company incurred $3,842,535 of vacation pay for the test year. 258
257
Company Workpaper WP/E-4 page 164.
258
Response to Rose City 9-16 .
137
1 Q. HOW DID YOU ADJUST THE COMPANY'S PROPOSED PAYROLL EXPENSE
2 .LEAD DAYS FOR THE PROPER RECOGNITION OF VACATION PAY?
3 A. I began with the Company's payroll of $35,210,377. 259 I then subtracted the test year
4 vacation pay amount of $3,842,535. 260 Next, I applied a 210.67 lead day period to
5 vacation pay. I then applied the Company proposed 13 day payroll lead period to the
6 remaining payroll. I then added the Company proposed 1.23 lag days for the withholding
7 lag. This results in 35.81 lag days for payroll, or an adjustment of 21.57 days and a
8 reduction to rate base of $2,080,974.
9
10 Q. IS THERE A SECOND ISSUE RELATING TO THE PAYROLL EXPENSE LEAD
11 DAYS?
12 A. Yes. The second issue deals with incentive compensation.
13
14 Q. IS THERE A DEFERRED PAYMENT ASSOCIATED WITH INCENTIVE
15 COMPENSATION?
16 A. Yes. Just as the situation for vacation pay there is also a deferred payment associated
17 with incentive compensation.
18
19 Q. WHAT IS THE DEFERRED PERIOD OF TIME ASSOCIATED WITH
20 PAYMENT OF INCENTIVE COMPENSATION?
21 A. The Company paid its annual incentives on March 12, 2009 for calendar 2008 services. 261
22
23 Q. WHAT LEVEL OF LEAD DAYS DID THE COMPANY ASSIGN TO INCENTIVE
24 COMPENSATION?
25 A. The Company assigned the same 13 day lead it assigned to all other payroll, prior to the I
26 impact of withholding items. 262
1
259
Company Work.paper WP/E-4 page 294.
260
Response to Rose City 9-16.
261
Response to Rose City 7-l(E).
262
Company Work.paper WP/E page 164.
138
1 Q. IS THERE ANY REASON NOT TO RECOGNIZE THE MARCH 12111 OF THE
2 FOLLOWING YEAR AS THE APPROPRIATE DEFERRED PAYMENT DATE?
3 A. No. The Company's action is based on the same illogical and inconsistent opinion of Mr.
4 Gallagher that assumes that the service period for expenses begins when an expense is
5 recorded. This false opinion must be corrected.
6
7 Q. WHAT IS THE APPROPRIATE NUMBER OF LEAD DAYS FOR INCENTIVE
8 COMPENSATION?
9 A. The appropriate number of lead days for incentive pay is 253.5 days. This level of lead
10 days is based on the average service period of the prior year (365/2) plus 71 days
11 corresponding to January 1 through March 12 of the following year.
12
13 Q. HOW DID YOU CALCULATE THE IMPACT OF TIDS ADJUSTMENT?
14 A. I employed the same methodology that I discussed for vacation payroll. The only
15 difference is that I use $3,688,868 corresponding to the level of incentive
16 compensation.263 This process resulted in a 39.43-day increase in the payroll lead days.
17 This incremental addition is additive to the vacation payroll adjustment.
18
19 Q. WHAT IS THE IMPACT OF TIDS ADJUSTMENT?
20 A. Increasing the overall net payroll lead days from 14.23 days to 25.20 days results in more
21 negative working capital of$2,430,616.
22 B. FAS 106
23
24 Q. WHAT DOES THE COMPANY PROPOSE FOR LEAD DAYS ASSOCIATED
25 WITH FAS 106 EXPENSES?
26 A. The Company proposes to exclude this expense from its analyses. 264 It should be noted
27 that the Company also claims it reflected the impact in the "Other O&M" expense
28 category. 265
263
Response to Rose City 7-l(E) ..
264
Direct Testimony of Mr. Gallagher at page 18.
265
Response to Rose City 24-55.
139
1
2 Q. IS THE ELIMINATION OF FAS 106 IN COMPLIANCE WITH THE
3 PRECEDENT SET IN THE COMPANY'S LAST FULLY LITIGATED RATE
4 CASE?
5 A. No. The Commission's order in Docket No. 16705 found that FAS 106 expense is a form
6 of deferred compensation and should have a 312.55 day lead assigned to it.
7
8 Q. WHAT ARE FAS 106 EXPENSES?
9 A. FAS 106 expenses represent post retirement benefits other than pensions. In other words,
10 these amounts represent an employee benefit provided as part of an overall compensation
11 package. FAS 106 costs are deferred compensation.
12
13 Q. DO YOU AGREE WITH THE COMPANY'S DECISION TO EXCLUDE FAS 106
14 EXPENSE FROM THE ANALYSIS?
15 A. Of course not, and neither did the Commission in Docket No. 16705. Mr. Gallagher's
16 presentation in this proceeding is anything but clear or logical. First, he testifies that FAS
17 106 expenses are not cash expenditures and excluded from his analysis, but then claims
18 that they are treated as "Other O&M" expense. Mr. Gallagher also fails to even reference
19 the fact that FAS 106 expenses are deferred compensation. Thus, just as this
20 Commission has recognized vacation pay as deferred compensation requiring extended
21 number of lead days in comparison to normal payroll days, the same is true for FAS 106
22 expenses. There is no reason to vacate the Commission's precedent on this matter,
23 especially given the Company's presentation in this proceeding. There are no changed
24 circumstances. There is no underlying support or logic to conclude anything other than
25 cash payments are being made for FAS 106 expenses, that they are a component of
26 ewe, and that they represent deferred compensation.
27
28 Q. WHAT DO YOU RECOMMEND?
29 A. I recommend following the Commission's precedent on this matter. In Docket No.
30 16705 the Commission recognized that such costs are deferred compensation and adopted
31 my recommended 312.55 expense lag days for this category of expense.266
266
Schedule (JP-15) page 2 of2 in Docket No. 16705.
140
1 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
2 A. Given that the Company has proposed $2,522,308 of FAS 106 expense for the test year,
3 in conjunction with the 312.55 expense lead days I am recommending, results in a
4 standalone impact of$2,159,856 of more negative ewe requirement. 267
5 C. Entergy Services Inc. ("ESI") Expense Lead
6
7 Q. WHAT LEVEL OF LEAD DAYS DID THE COMPANY PROPOSE FOR
8 ENTERGY SERVICE EXPENSES?
9 A. The Company proposes an expense lead of 39.30 days for expenses associated with
10 Entergy Services, Inc. expense. 268
11
12 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSED 39.30 LEAD DAYS?
13 A. Mr. Gallagher at page 17 of his direct testimony states that the ETl/ESI Service
14 Agreement requires payments for ESI services to be made in the month after the expenses
15 are booked. The payment of these costs occur between the 20th and 25th of the month
16 following the provision of service. The actual calculation of the proposed lead days is set
17 forth in the Company's workpapers. 269
18
19 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
20 A. No. A substantial portion of the Company's charges from Entergy Services, Inc. is
21 associated with incentive compensation. In fact, during the test year, $9,481,590 of ESI
22 charges were attributable to incentive compensation. 270 As previously noted, incentive
23 compensation represents a form of deferred compensation. Therefore, the incremental
I 24 lead days associated with incentive compensation must be added to the portion of ESI
25 charges that are incentive compensation related. The Company pays its incentive
t 26 compensation on or about March 15th of the year following the period used to determine
27 whether incentive compensation has been earned. A March 12th payment yields 253.5
28 lead days compared to the standard payroll levels reflected in the ESI charges of 13 days.
267
Response to Rose City 24-55.
268
Company Workpaper WP/E-4 page 2.
'
r
269
270
Company Workpaper WP/E-4 page 764.
Response to Rose City 6-4 through 6-10.
141
1 Therefore, an incremental 241.5 days must be recognized for the incentive compensation
2 portion of the ESI charges.
3
4 Q. WHAT IS THE STANDALONE IMPACT OF YOUR RECOMMENDATION?
5 A. Segregation of the ESI related incentive compensation charges from the total ESI
6 expenses reflected in the ewe analysis, along with the application of a 253.5 lead day
7 period for such incentive compensation results in an incremental negative working capital
8 of $5,564,276.
9 D. Other O&M Expense Lead
10
11 Q. WHAT DID THE COMPANY PROPOSE FOR OTHER O&M EXPENSE LEAD
12 DAYS?
13 A. The Company proposed 28.55 days plus 3.84 days for check float, or a total of 32.39
14 days. 271 This level is 11.75 shorter than the 44.14 expense lag days Mr. Gallagher
15 supported in Docket No. 34800. 272 In other words, the value in the last case was 36%
16 higher than the current proposed value.
17
18 Q. HOW DID THE COMPANY ESTABLISH ITS OTHER O&M LEAD DAY
19 PROPOSAL?
20 A. The Company performed a stratified random sample process of 140 invoices. 273
21
22 Q. WHAT IS A STRATIFIED SAMPLE?
23 A. A stratified sample represents a situation where the variance in a population is recognized
24 by segregating the individual sample items into various stratums or categories that
25 represent different size intervals. In this case the Company recognized that the dollar
26 level of its invoices range from a few dollars to over $240,000. Therefore, it elected to
27 establish different dollar ranges with the highest stratum for invoices over $100,000 and
28 the lowest stratum for invoice amounts less than $250.
271
Company Workpaper WP/E-4 page 2.
272
Id., in Docket No. 34800.
273
Testimony of Mr. Gallagher at page 19.
142
1 Q. HAVE YOU REVIEWED THE SAMPLE AND THE COMPANY'S PROPOSED
2 RESULTS FROM SUCH SAMPLE?
3 A. Yes. As was the situation in prior cases, the Company has made several errors in
4 performing its sample analysis for the other O&M category.
5
6 Q. WHAT TYPE OF ERRORS DOES THE COMPANY'S PROPOSAL REFLECT?
7 A. The Company incorporated prepayments in its sample. Prepayments are already or should
8 be reflected in rate base in the prepayment category of rate base. The Company also paid
9 invoices early in order to capture a discount. Unfortunately, the discount taken was so
10 small that the Company's actions actually cost customers more than the discount, if not
11 corrected. Customers should not pay for imprudent financial decisions. There are also
12 instances where Mr. Gallagher did not capture the correct service period reflected on the
13 invoice in his sample.
14
15 Q. CAN YOU PROVIDE AN EXAMPLE OF EACH TYPE OF ERROR?
16 A. Yes. For sample item number 8 in the greater than $100,000 stratum, the Company
17 incurred an invoice with a September 1, 2008 through August 31, 2009 service period.
18 The Company paid that invoice on November 13, 2008 and attempts to claim a negative
19 99-day lead. 274 The payment represents a prepayment and should be excluded from the
20 ewe analyses.
21
22 An example of the Company's inefficient financial actions can be seen on sample item 9
23 in the greater than $100,000 stratum. This particular vendor offers a 0.7% discount if the
I 24
25
invoice is paid within 15 days. The vendor also provides for no discount or penalty if
payment is made within 45 days, or 30 more days. The invoice was for $126,190 and by
I 26
27
paying early the Company received an $883.33 discount. Unfortunately, by paying early
the Company now wants customers to incur a loss of 1.45 lead days for the greater than
I 28
29
$100,000 stratum. 275 Since the greater than $100,000 stratum represents 32.59% of the
total stratums, the failure to take full advantage of the 45 day net terms for this single
I 274
Company Workpaper WP/E-4 pages 828 and 878-880.
275
$126,190 x .993/$2,599,973.62 x 30 days= 1.45 days.
143
1 invoice caused the Other O&M category lead days to be understated by 0.47 days (l.45 x
2 0.3259). A loss of 0.47 lead days for this Other O&M category that has a $233,838
3 average daily balance increases rate base by $109,904 ($233,838 x 0.47). Using a 12%
4 grossed-up overall cost of capital for illustrative purposes yields a $13,188 increase in
5 revenue requirements. In other words, the Company saved customers $883.33 by taking a
6 discount, but wants to charge them $13,188 for its efforts. This is not appropriate.
7
8 An example of Mr. Gallagher's failure to capture the correct service period can be seen
9 on sample item 13 in the $25,000 to $50,000 stratum. This particular invoice clearly
10 identifies the service period by stating ''for services from 5/31/2008 to 6/27/2008."276
11 Unfortunately, Mr. Gallagher relied on a July 2, 2008 date as the service period. 277
12
13 Q. WHAT IS THE IMPACT OF THE VARIOUS CORRECTIONS THAT YOU
14 RECOMMEND TO THE OTHER O&M LEAD DA VS PROPOSED BY MR.
15 GALLAGHER?
16 A. As set forth on Schedule (JP-5), the numerous recommended corrections to the Other
17 O&M category increase the Company proposed 28.55 lead days to 44.07 lead days.
18 SECTION VII: RIVER BEND DECOMMISSIONING REVENUE
19 REQUIREMENT
20
21 Q. WHAT IS THE ISSUE IN TIDS PORTION OF YOUR TESTIMONY?
22 A. This portion of my testimony addresses the Company's request for decommissioning
23 expense revenue requirements associated with River Bend. To the extent the Commission
24 has authority to address this issue, I recommend that the Company's request for a $2.8
25 million decommissioning expense annual revenue requirement be reversed and the
26 existing $0-level of decommissioning expense be retained.
276
Company Workpaper WP/E-4 page 1026.
277
Id., at page 972 for sample number 13.
144
1 Q. WHY DO YOU STATE THAT THE COMMISSION MAY NOT HAVE
2 AUTHORITY TO RULE ON DECOMMISSIONING REVENUE
3 REQUIREMENT MATTERS?
4 A. It is my understanding that Cities' witness Mr. Brazell will be addressing this issue as to
5 whether the Commission has authority to impact a FERC established tariff. However, to
6 the extent that the Commission believes it has authority to address this issue, I
7 recommend the retention of the $0-level of decommissioning expense revenue
8 requirements.
9
10 Q. WHAT DOES THE COMPANY REQUEST REGARDING DECOMMISSIONING
11 REVENUE REQUIREMENTS?
12 A. Mr. Gillam states that the Company is requesting $2.8 million of annual
13 decommissioning expense. 278 lbis represents a $2.8 million increase from the existing
14 $0-level of expense.
15
16 Q. WHAT IS THE COMPANY'S BASIS FOR REQUESTING A $2.8 MILLION
17 REVENUE REQUIREMENT FOR DECOMMISSIONING ACTIVITIES?
18 A. The existing $0-level of decommissioning expense is predicated on Item 9 of the
I 19 Settlement Term sheet in Docket No. 34800. Item 9 states that nuclear depreciation and
20 decommissioning amounts reflect the life extension of River Bend. In other words, while
21 the Company has not formally received the 20-year life extension from the NRC for
22 River Bend, it did recognize the impact of such extension for ratemaking purposes in its
23 settlement of Docket No. 34800. Now in this case, Mr. Gillam bases his analysis for
24 decommissioning revenue requirements on the initial 40-year life span versus a 60-year
279
25 life span for River Bend.
26
27 Q. IS THE COMPANY'S REVERSAL OF POSITION APPROPRIATE?
28 A. No. The industry as a whole has embarked on and received approval for 20-year license
29 extensions for various nuclear power plants. Indeed, Entergy Corporation has already
278
Direct Testimony of Mr. Gillam at page 3.
279
Gillam Exhibit PEG-3.
145
1 received 20-year license extensions for nuclear units and is in the process of seeking 20-
2 year license extensions for several other nuclear generating facilities. In addition, the
3 NRC has been given a formal notice that a license extension will be requested for the
4 River Bend station. Thus, the industry, the Company's parent, and the Company all
5 recognize the change in life expectancy for nuclear generating facilities such as River
6 Bend.
7
8 Q. HOW DID MR. GILLAM DEVELOP ms $2.8 MILLION ESTIMATE?
9 A. Mr. Gillam developed an analysis that reflected estimation of future decommissioning
10 costs, earning rates for different types of external funds, cost escalation rates,
11 management fee levels, as well as other variables. Mr. Gillam estimated these variables
12 through the year 2034, or approximately 25 years into the future. 280
13
14 Q. HOW DOES THE 20-YEAR LIFE EXTENSION AFFECT THE CALCULATION
15 EMPLOYED BY MR. GILLAM?
16 A. Given that the Company's earnings rate for its trust funds are higher than its estimated
17 cost escalation rates yields the straightforward conclusion that a 20-year life extension
18 will reduce the need for additional customer funding of the external trust funds
19 requirements. In other words, estimated earning rates of 4.51 % and higher are greater
20 than the assured 4.25% cost escalation rate. Therefore, the further out into the future the
21 decommissioning process is moved the lesser is the need for further customer
22 contribution to the external funds.
I
I
280
Direct Testimony of Mr. Gillam at pages 4-6, and Exhibit PBG-3 .
146
'
1 Q. ARE THERE PROBLEMS WITH MR. GILLAM'S ANALYSES PRIOR TO
2 RECOGNITION OF A 20-YEAR LIFE EXTENSION FOR RIVER BEND?
3 A. Yes. Mr. Gillam relies on an excessive Texas retail allocation factor (i.e., 42.73% versus
4 42.5%). 281 Mr. Gillam's analysis also understates the starting balance of both external
5 funds by millions of dollars. 282 In addition, Mr. Gillam only addresses future assumed
6 cost escalation for decommissioning activities and fails to address productivity gains or
7 other cost reduction factors.
8
9 Q. HAVE YOU ANALYZED THE IMPACT ON THE EXPECTED
10 DECOMMISSIONING REVENUE REQUIREMENT FUNDS FOR A 20-YEAR
11 LIFE EXTENSION?
12 A. Yes. Recognition of a 20-year life extension for the River Bend station would eliminate
13 the Company's $2.8 million requested revenue requirements for decommissioning.
14 Recognition of the 20-year life extension in conjunction with the correction noted above
15 would further result in the fact that Texas retail customers have already overpaid their
16 annual decommissioning funding requirements.
17
18 Q. HAVE TEXAS CUSTOMERS BEEN TREATED FAIRLY IN THE
19 DECOMMISSIONING FUNDING PROCESS?
20 A. No. Even though ETI is responsible for approximately 42.5% of River Bend and EGSL is
21 responsible for approximately 57.5%, the same situation does not exist for the
I 22 decommissioning fund balance. As of December 31, 2009, Texas retail customers' trust
23 fund balance was $101 million out of the total $153.5 million balance. 283 Thus, while
24 Texas retail customers have only 42.5% of the plant they have contributed 66% of the
25 total decommissioning fund balance. In other words, Texas retail customers have
26 historically done what was thought to be the "right thing" and contributed to the fund in a
27 responsible, but excessive, manner.
28
281
Id., at Exhibit PBG-3.
282
Response to Rose City 10-3.
283
Response to Rose City 10-3 and 10-2.
147
1 Q. HAVE TEXAS RETAIL CUSTOMERS BEEN REWARDED FOR DOING THE
2 "RIGHT TIIlNG"?
3 A. No. As stated elsewhere in my testimony, the nation as well as the world experienced a
4 financial meltdown in the second half of 2008. Due to the dramatic declines in the equity
5 markets Texas retail customers lost more money than their counterparts in Louisiana.
6 Indeed, Company witness Mr. Caruso stated that ''the jurisdiction that has accumulated
7 the most balance [Texas retail customers] is going to have a bigger share of the gain or
8 loss."284 Mr. Caruso was right, Texas retail customers have suffered to date much more
9 than their counterparts in Louisiana. First they paid more, then lost more in the
10 worldwide financial meltdown in 2008, and now are being asked to make up for those
11 losses. The Company's decommissioning trust fund treatment of Texas retail customers
12 has not been equitable compared to Louisiana customers.
13
14 Q. WHAT DO YOU RECOMMEND?
15 A. I recommend the retention of the current $0-level of decommissioning expense. The 20-
16 year life extension and correction of certain errors would eliminate the Company's
17 request. Additional factors must also be considered. First, even slight increase in the
18 earnings rates or slight decline in the cost escalation factor would further eliminate the
19 need for any current contribution. Indeed, EGSL employs a 2.5% decommissioning cost
20 escalation factor in Louisiana and a 5.7% earnings growth rate. 285 If either of these
21 factors were employed in Texas, the result would be further support for a $0-level of
22 decommissioning accrual. Next, any recognition of gains in productivity would also
23 reduce the need for any further decommissioning contributions. This concept is
24 significant given the decommissioning cost estimate have a built in contingency factor.
25 The only necessary contingency factor is time itself. As more time passes, and there is I
26 more than 35 years until the 20-year life extension expires, costs, productivity, earnings
27 and other factors will be known with greater certainty. Another consideration for totally I
28 eliminating the requested revenue requirements is the fact that if the actual
29 decommissioning process were delayed for a short period, after retirement, it would result
284
Deposition of Mr. Caruso on April 29, 2010 at TR 54.
28
s Entergy Corporation August 13, 2009 letter to the NRC regarding the "Decommissioning Funding Assurance
Plans."
148
1 in the current fund levels being even more excessive. Therefore, there is no reason to
2 change the current contribution level at this time.
3 SECTION VIII: RIVER BEND DEPRECIATION RATES
4
5 Q. WHAT IS THE ISSUE IN TIDS PORTION OF YOUR TESTIMONY?
6 A. The Company has included a River Bend depreciation analysis in its filing. City witness
7 Mr. Brazell will address whether the Commission has authority to set a depreciation rate
8 for the River Bend station. However, to the extent the Commission does set depreciation
9 rate, the rate proposed by the Company must be reduced to reflect the elimination of
IO interim retirements and a 20-year license extension.
11
12 Q. WHAT DEPRECIATION RATE DOES THE COMPANY REQUEST FOR RIVER
13 BEND?
14 A. As set forth in Company witness Mr. Spanos' Exhibit JJS-2, the Company seeks a
15 composite depreciation rate for its nuclear plant investment of 3.6%. This rate is
16 comprised of individual rates for the individual plant accounts and reflects the
17 recognition of interim retirements, an ELG calculation procedure, and a 40-year life span
18 rather than a 60-year life span.
19
20 Q. ARE THE RATES PROPOSED BY THE COMPANY APPROPRIATE AND
I 21
22 A.
REASONABLE?
No. As previously noted under the depreciation section of my testimony, the Commission
23 has historically denied the inclusion of interim retirements. The current rates for River
24 Bend do not reflect the impact of interim retirements. In addition, also discussed in the
25 depreciation section of my testimony, the use of the ELG depreciation procedure is
26 inappropriate. Finally, the life span proposed by the Company is artificially short based
27 on the available facts.
149
1 RIVER BEND DEPRECIATION RATES
Account ETI Cities
321 2.99% 1.33%
322 3.67% 1.53%
323 4.24% 1.66%
324 3.14% 1.32%
325 5.03% 2.10%
Total 3.36% 1.42%
2 As can be seen in the table above, the 20-year life extension and elimination of interim
3 retirements significantly reduces the necessary depreciation rates and depreciation
4 expense requested by the Company by $26,671,803 for the Texas jurisdiction based on
5 plant as of December 31, 2008.
6
7 Q. DOES TillS CONCLUDE YOUR TESTIMONY?
8 A. Yes. However to the extent I have not addressed an issue, method, procedure, etc., that
9 should not be construed that I am in agreement with the Company's issue, method,
10 procedure, etc.
I
150