In re Investigation to Review the Avoided Costs that Serve as Prices for the Standard-Offer Program in 2020 (Allco Renewable Energy Limited & PLH LLC, Appellants) ( 2021 )

NOTICE: This opinion is subject to motions for reargument under V.R.A.P. 40 as well as formal
revision before publication in the Vermont Reports. Readers are requested to notify the Reporter
of Decisions by email at: JUD.Reporter@vermont.gov or by mail at: Vermont Supreme Court, 109
State Street, Montpelier, Vermont 05609-0801, of any errors in order that corrections may be made
before this opinion goes to press.
2021 VT 28No. 2020-134
In re Investigation to Review the Avoided Costs that Supreme Court
Serve as Prices for the Standard-Offer Program in 2020
(Allco Renewable Energy Limited & PLH LLC, Appellants)
On Appeal from
Public Utility Commission
September Term, 2020
Anthony Z. Roisman, Chair
Thomas Melone of Allco Renewable Energy Limited, New York, New York, for Appellants.
Alexander W. Wing, Special Counsel, Department of Public Service, Montpelier, for Appellee.
PRESENT: Reiber, C.J., Robinson, Eaton, Carroll and Cohen, JJ.
¶ 1. ROBINSON, J. Allco Renewable Energy Limited and PLH, LLC (collectively,
Allco), challenge the Vermont Public Utility Commission’s (PUC) decision establishing the
avoided-cost price caps and parameters of the 2020 standard-offer program. Specifically, Allco
argues that the PUC failed to make a required annual determination that its pricing mechanism
complies with federal law, and that its 2020 standard-offer request for proposal (RFP) was invalid
because the market-based pricing mechanism used in the standard-offer program violates federal
law. We affirm.
I. Background
¶ 2. A general understanding of applicable federal and state law is critical to
understanding the facts and issues in this case.
A. Federal Power Act and “PURPA”
¶ 3. The Federal Power Act (FPA) grants the Federal Energy Regulatory Commission
(FERC) the exclusive power to regulate the sale of electric energy at wholesale in interstate
commerce. 16 U.S.C. § 824(b)(1); see also Federal Power Comm’n v. S. Cal. Edison Co., 376
U.S. 205, 215 (1964) (holding that FPA left no power to the states to regulate licensees’ sales for
resale in interstate commerce).
¶ 4. In 1978, Congress amended the FPA with the Public Utility Regulatory Policies
Act of 1978 (“PURPA”), Pub. L. No. 95-617, 92 Stat. 3117, with the goal of reducing dependence
on fossil fuels, in part by encouraging the development of cogeneration and small power
production facilities,1 Winding Creek Solar LLC v. Peterman (Winding Creek Solar II), 932 F.3d
861, 863 (9th Cir. 2019). One particular barrier to developing alternative energy facilities that
Congress sought to eliminate was traditional electricity utilities’ reluctance to purchase power
from and sell power to nontraditional facilities. FERC v. Mississippi, 456 U.S. 742, 750-51
(1982). To address this barrier, PURPA directs FERC, in consultation with state regulatory
agencies, to promulgate “such rules as it determines necessary to encourage cogeneration and
small power production,” including rules requiring electric utilities to offer to sell electric energy
to and purchase it from certain power production facilities that meet FERC’s requirements, called
“qualifying facilities” (QFs). 16 U.S.C. § 824a-3(a); see also 18 C.F.R. § 292.203 (outlining these
rules). PURPA requires that the rates utilities pay to QFs be “just and reasonable to the electric
consumers of the electric utility and in the public interest,” and “not discriminate against qualifying
cogenerators or qualifying small power producers.” 16 U.S.C. § 824a-3(b). The statute
1
A “cogeneration facility” produces both electric energy and steam or other forms of
useful energy, such as heat, 16 U.S.C. § 796(18)(A), while a “small power production facility” is
one that has no more than eighty megawatts of production capacity and uses biomass, waste,
renewable resources, or geothermal resources to produce electric power, id. § 796(17)(A); 18
C.F.R. § 292.204.
2
specifically states that no rule prescribed to implement the statute may “provide for a rate which
exceeds the incremental cost to the electric utility of alternative electric energy.” Id.
¶ 5. In 1980, FERC promulgated regulations pursuant to PURPA. See 18 C.F.R. pt.
292. These regulations give state regulatory authorities flexibility to determine how to implement
the regulations. See Mississippi, 456 U.S. at 751 (“These [regulations] afford state regulatory
authorities . . . latitude in determining the manner in which the regulations are to be
implemented.”). Under this regulatory scheme, utilities must pay QFs a rate derived from the
utility’s “avoided cost”—that is, “the incremental costs to an electric utility of electric energy or
capacity or both which, but for the purchase from the qualifying facility . . ., such utility would
generate itself or purchase from another source.” 18 C.F.R. § 292.101(b)(6); see also Allco Fin.
Ltd. v. Klee, 805 F.3d 89, 92 (2d Cir. 2015). Put more simply, it is the cost a utility would
otherwise incur in obtaining the same quantity of electricity from a different source.2
¶ 6. PURPA requires that each state regulatory authority implement FERC’s PURPA
regulations, including establishing the avoided cost. See 16 U.S.C. § 824a-3(f)(1).
B. Vermont’s PUC, Rule 4.100, and the Standard-Offer Program
¶ 7. The PUC is the Vermont regulatory authority charged with implementing PURPA
and regulating the sale to electric companies of electricity generated by QFs in Vermont. 30 V.S.A.
§ 209(a)(8). In 1983, the PUC promulgated Rule 4.100 to implement PURPA.3 See Small Power
2
More recently, FERC has clarified that a multi-tiered avoided-cost rate structure can be
consistent with the requirements of PURPA where necessary to take into account obligations
imposed by the state that, for example, require utilities to purchase energy from particular sources
or for a long duration. Order Granting Clarification and Dismissing Rehearing, Cal. Pub. Utils.
Comm’n et al. (CPUC II), 133 FERC ¶ 61059, P 26 (2010). In particular, FERC explained that
“where a state requires a utility to procure a certain percentage of energy from generators with
certain characteristics, generators with those characteristics constitute the sources that are relevant
to the determination of the utility’s avoided cost for that procurement requirement.” Id. ¶ 27.
3
Before 2017, the PUC was known as the Public Service Board. We refer to the entity as
the PUC throughout this decision even when describing acts taken prior to 2017.
3
Production and Cogeneration, Code of Vt. Rules 30 000 4100 [hereinafter Rule 4.100],
http://www.lexisnexis.com/hottopics/codeofvtrules. Rule 4.100 “applies to all contracts and
obligations formed pursuant to [the PUC’s PURPA-implementing authority], except standard-
offer contracts formed pursuant to 30 V.S.A. § 8005a.” Id. § 4.102(C). The rule requires
distribution utilities to purchase the generation output of QFs to the extent required by the
regulations implementing PURPA. Id. § 4.104. It establishes the various rates payable to a QF
depending on the type of contract the QF elects. Id.
¶ 8. In 2009, the Legislature established a standard-offer requirement as part of the
Sustainably Priced Energy Enterprise Development (SPEED) Program to promote the rapid
development of renewable energy in Vermont. 2009, No. 45, § 4. In 2012, the Legislature made
significant changes to the standard-offer program, now codified at 30 V.S.A. § 8005a. 2011, No.
170 (Adj. Sess.), § 4. The program is administered by a statewide purchasing agent (standard-
offer facilitator), appointed by the PUC. See 30 V.S.A. § 8005a(a). Under this program, the PUC
issues standard-offer contracts for the construction of renewable energy plants that meet certain
eligibility requirements, and Vermont distribution utilities are required to buy the renewable power
from selected plants at a designated price for a set period of time. Id. § 8005a. Eligible renewable
energy generation plants must be located in Vermont and have a plant capacity no greater than 2.2
megawatts (MW). Id. § 8005a(b).
¶ 9. The standard-offer program provides for standard-offer contracts accounting for a
cumulative capacity of 127.5 MW of electricity, allocated in annual statutorily designated
increments ranging from five MW in 2013-2015 to ten MW in 2019-2022. Id. § 8005a(c)(1)(A).
A portion of each year’s new renewable electricity generation capacity is reserved for plants
proposed by Vermont utilities, called the provider block; the remainder is left for new plants
proposed by others, called the developer block. Id. § 8005a(c)(1)(B).
4
¶ 10. Under the standard-offer program, the PUC is directed to allocate the 127.5-MW
cumulative plant capacity among different categories of renewable-energy technologies,
including: methane derived from a landfill; solar power; wind power with a plant capacity no
greater than 100 kilowatts (kW) (small wind); wind power with a plant capacity greater than 100
kW (large wind); hydroelectric power; and biomass power.4 Id. § 8005a(c)(2). In establishing
annual allocations of capacity among the different technologies, the PUC considers multiple goals
and directives, including supporting a diversity of renewable energy projects, as well as the varying
market interest in developing projects from each technology category. See Investigation into
Programmatic Adjustments to the Standard-Offer Program, No. 8817, 2017 WL 1365063, at *4-5
(Vt. Pub. Util. Comm’n Mar. 2, 2017) [hereinafter 2017 Order]. The PUC calculates avoided costs
to serve as price caps for each technology category. Section 8005a(f)(2)(B) defines avoided costs
as:
[T]he incremental cost to retail electricity providers of electric
energy or capacity, or both, which, but for the purchase through the
standard offer, such providers would obtain from distributed
renewable generation that uses the same generation technology as
the category of renewable energy for which the Commission is
setting the price.
Thus, in contrast to the must-take requirements of Rule 4.100, which define avoided costs without
regard to the specific generation technology involved, the standard-offer program sets technology-
specific avoided-cost caps.
¶ 11. In addition, the PUC is authorized to use a market-based mechanism, “such as a
reverse auction or other procurement tool” to fill the capacity for each category of renewable
energy if it finds that such mechanism is consistent with federal law and “the goal of timely
development at the lowest feasible cost.” 30 V.S.A. § 8005a(f)(1). Since 2013, the PUC has used
4
Farm methane projects are considered outside of the cumulative capacity and thus do not
have to participate in the annual request for proposal. 30 V.S.A. § 8005a(d)(1).
5
such a market-based approach; in particular, it has issued an annual request for proposal (RFP),
defining the program capacity, technology allocations, and the technology-specific avoided costs,
to fill the available capacity for that year under the program. The lowest-priced bidders are
awarded a standard-offer contract at their bid price. See Investigation into Programmatic
Adjustments to the Standard-Offer Program for 2018, No. 17-3935-INV, 2018 WL 1452283, at *1
(Vt. Pub. Util. Comm’n Mar. 16, 2018) [hereinafter 2018 Order].5
¶ 12. Pursuant to its 2017 order, in managing the standard-offer program the PUC
designated a portion of the developer block capacity as the “price-competitive developer block,”
available to projects of any technology category, with contracts awarded to the lowest bidders at
bid price. 2017 Order, at *5. The remainder was designated the “technology diversity developer
block” and allocated on an equal basis to non-solar technology, including small wind and food
waste methane projects, with contracts awarded at bid price to the lowest bidders within each
technology category. Id. In 2018, the PUC recognized that other technology categories were not
able to compete with solar projects based on the fact that the 2017 price-competitive developer
block drew bids only for solar projects; it thus expanded the technology diversity developer block
to include biomass, large wind, small wind, hydroelectric, and food waste methane projects. 2018
Order, at *21, 23. The PUC readopted this mechanism of allocating new standard-offer contract
capacity among various technologies for the 2020 RFP. See Investigation to Review the Avoided
Costs that Serve as Prices for the Standard-Offer Program in 2020, No. 19-4466-INV, 2020 WL
1557388, at *2 (Vt. Pub. Util. Comm’n Mar. 4, 2020) [hereinafter March 2020 Order].
5
When the program was first established, eligible projects selected through a lottery
received a standard-offer contract with a contract price based on technology-specific avoided costs.
See 2018 Order, at *1.
6
II. The PUC Proceedings in this Case
¶ 13. In November 2019, the PUC opened an investigation pursuant to 30 V.S.A.
§ 8005a(f)(3) to conduct a review of the avoided costs to serve as price caps on the standard-offer
contracts solicited in the 2020 RFP. In its order opening the investigation, the PUC indicated that
based on its review of the 2018 and 2019 RFP results, it would retain the technology allocations
from those prior years. Order Opening Investigation, Establishing Schedule, and Notice of
Workshop, No. 19-4466-INV, at 2 (Vt. Pub. Util. Comm’n Nov. 7, 2019),
https://epuc.vermont.gov/?q=node/64/145668/FV-BDIssued-PTL. Thus, its investigation was
“limited to the review of the standard-offer prices.” Id. The PUC did not follow contested-case
procedures under the Vermont Administrative Procedure Act. Id.; see also 30 V.S.A. § 8005a(f)
(“The [PUC] shall not be required to make [the determinations required by this subsection] as a
contested case under 3 V.S.A. chapter 25.”). However, interested parties had an opportunity to
participate through a workshop and written filings. Allco participated in the workshop but did not
submit comments until after the hearing officer issued a proposal for decision.
¶ 14. The hearing officer’s proposal for decision following the workshop recommended
no changes to the 2019 standard-offer price caps in the developer and provider blocks. In
particular, it noted that the results from the 2019 RFP indicated that the solar price cap was at a
level that encouraged participation and resulted in competitively priced bids.
¶ 15. In the March 2020 Order, the PUC adopted the hearing officer’s conclusions and
recommendations. In its order, the PUC also addressed comments Allco filed after the hearing
officer issued the proposal for decision. Allco argued, among other things, that the proposal for
decision failed to review the validity of the PUC’s reverse-auction pricing mechanism as required
by statute, and that the market-based pricing scheme violates federal law. In its decision adopting
the hearing officer’s recommendations, the PUC concluded that Allco’s concerns were “outside
the scope of [the] proceeding,” which was limited to reviewing possible adjustments to the avoided
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cost caps for standard-offer projects. March 2020 Order, at *7. Citing a number of its prior
decisions, the Commission also noted that it had previously addressed the standard-offer program’s
consistency with federal law, and the market-based pricing mechanism in particular, and stated
that none of Allco’s arguments warranted revisiting the matter. Id. In its order, the PUC directed
the standard-offer facilitator to issue a request for proposals consistent with the PUC’s order.
¶ 16. Allco filed a notice of appeal in April 2020, and in May 2020 moved to stay the
2020 RFP pending this appeal. In requesting a stay, Allco again argued that the PUC failed to
make the finding required by § 8005a(f)(1) that its pricing mechanism complied with federal law,
and asserted that the market-based mechanism violated federal law because it compels wholesale
sales of electricity in violation of PURPA where the reverse-auction based prices are less than the
avoided costs as defined by PURPA. Due to delays caused by the ongoing COVID-19 pandemic,
the PUC extended the RFP bid submission deadline to July 2020. In June, the PUC denied Allco’s
motion to stay, concluding that it was not likely to succeed on the merits. In particular, the PUC
stated that it had satisfied the requirements of § 8005a(f)(3) with respect to its annual review of its
pricing mechanism and the standard-offer prices. The PUC explained that while § 8005a(f)(3)
requires annual review of the pricing mechanism, it does not require the PUC to open an
investigation and conduct a hearing in performing that review. The PUC explained that it did not
include review of its pricing mechanism in this investigation because it had already concluded that
the market-based mechanism was consistent with federal law. Further, the PUC stated that it did
address Allco’s objection on this point in the March 2020 Order by citing a host of relevant prior
PUC decisions, including the March 2013 order in which the PUC first concluded that “the use of
a market-based mechanism, if it is reasonably implemented is consistent with federal law.”
Programmatic Changes to the Standard-Offer Program & Investigation into the Establishment of
Standard-Offer Prices under the Sustainably Priced Energy Enter. Dev. (“SPEED”) Program
[hereinafter 2013 Order], Nos. 7873 & 7874, 2013 WL 840116, at *14 (Vt. Pub. Util. Comm’n
8
Mar. 1, 2013). Finally, on the merits, the PUC explained that its market-based pricing mechanism
complied with PURPA because Vermont offers a PURPA-compliant alternative to the standard-
offer program for Allco to seek a contract at avoided-cost rates for its qualifying facility. In
particular, under Rule 4.100, qualifying facilities have the opportunity to enter into long-term,
legally enforceable contracts at avoided-cost rates; this satisfies the requirements of PURPA, so
the standard-offer program is not constrained by the PURPA restrictions on pricing.
¶ 17. Allco renews its arguments in this appeal. Specifically, it argues that pursuant to
30 V.S.A. § 8005a(f)(3), the PUC is required to annually review its determination that its pricing
mechanism complies with federal law. Had it done so in this case, Allco contends, it would have
concluded that the market-based component of the PUC’s standard-offer pricing violates PURPA.
We consider Allco’s challenge to the PUC’s process, and the merits of its challenge to the market-
based pricing mechanism below.
¶ 18. In reviewing decisions of the PUC, we “defer[] to the [PUC’s] expertise and
informed judgment,” and “apply a strong presumption of validity to [its] orders.” In re Verizon
New Eng., Inc., 173 Vt. 327, 334, 795 A.2d 1196, 1202 (2002). We thus defer to the PUC’s
“interpretation of statutes it implements and its rules,” In re SolarCity Corp., 2019 VT 23, ¶ 9, 210
Vt. 51, 210 A.3d 1255 (quotation omitted), and will affirm its findings and conclusions “unless
they are clearly erroneous,” In re Constr. & Operation of a Meteorological Tower, 2019 VT 20,
¶ 9, 210 Vt. 27, 210 A.3d 1230 (quotation omitted). However, our “paramount goal” in construing
a statute is to give effect to the Legislature’s intent, and thus “we do not abdicate our responsibility
to examine a disputed statute independently and ultimately determine its meaning.” In re
Programmatic Changes to Standard-Offer Program, 2014 VT 29, ¶ 9, 196 Vt. 175, 95 A.3d 999(quotations omitted).
9
III. Analysis
A. Compliance with § 8005a(f) Annual Review Requirement
¶ 19. The PUC is authorized to use a market-based mechanism to fill the capacity
allocated to each category of renewable-energy technology only if it finds that such “mechanism
is consistent with: (A) applicable federal law[,] and (B) the goal of timely development at the
lowest feasible cost.” 30 V.S.A. § 8005a(f)(1). If, on the other hand, the PUC concludes that its
market-based pricing is inconsistent with federal law or would lead to higher prices than
administratively set avoided-cost based prices, then the Legislature has directed that the PUC use
administratively determined avoided costs in setting the standard-offer contract prices. Id.
§ 8005a(f)(2).
¶ 20. With respect to the establishment and modification of a specific pricing mechanism,
§ 8005a(f)(3) provides:
The Commission shall take all actions necessary to determine the
pricing mechanism and implement the pricing requirements of this
subsection (f) no later than March 1, 2013 for effect on April 1,
2013. Annually thereafter, the Commission shall review the
determinations previously made under this subsection to decide
whether they should be modified in any respect in order to achieve
the goal and requirements of this subsection.
¶ 21. Allco argues that in its annual review pursuant to § 8005a(f)(3), the PUC is required
to consider its pricing mechanism as well as its actual price determinations. Allco contends that
because the PUC failed to make a determination, as required under § 8005a(f), that the market-
based mechanism it used for the 2020 RFP is consistent with federal law, the PUC must proceed
with the 2020 RFP “using only the administratively determined price” and not the market-based
mechanism. Appellee Department of Public Service (DPS) argues that the PUC found the use of
market-based pricing consistent with federal law in 2013, before implementing the market-based
mechanism, and that the PUC has reasonably and consistently concluded that it is not required to
annually review that determination when it establishes the avoided costs.
10
¶ 22. We need not decide whether the PUC is required to annually evaluate whether its
market-based pricing mechanism is consistent with federal law because we conclude that the
remedy for any failure to conduct the federal-compliance evaluation would be to remand for the
PUC to conduct the evaluation. Because the PUC ultimately engaged in that analysis and made
its position on the question clear in the context of an order in this case, this remedy would be
pointless.
¶ 23. Allco’s argument rests on the inaccurate assumption that the remedy for the PUC’s
claimed failure to specifically address the federal compliance issue before proceeding with the
2020 RFP would be to compel the PUC to set standard-offer contract prices on the basis of
administratively determined avoided costs pursuant to § 8005a(f)(2). But the Legislature did not
establish the administratively determined avoided-cost pricing as the default that the PUC must
use in the absence of a finding that a market-based mechanism complies with federal law; rather,
it required that the PUC use the avoided-cost pricing method only if it finds, among other things,
that a market-based mechanism “is inconsistent with applicable federal law.” Id. § 8005a(f)(2).
Either kind of pricing mechanism—market-based or administratively determined based on avoided
costs—is predicated on an affirmative finding by the PUC. The Legislature did not establish a
default pricing mechanism in the event of no finding at all on the federal compliance question.
¶ 24. Given this statutory structure, if the statute does require the PUC to determine that
its pricing mechanism complies with federal law before it issues each annual RFP—a question we
need not decide—then the remedy for its failure to do so would be to remand with instructions to
make the required determination. Although the PUC stated in the March 2020 Order that the
question whether its pricing mechanism complied with federal law was beyond the scope of this
proceeding, in its subsequent denial of Allco’s motion to stay the RFP, the PUC set forth the legal
analysis supporting its conclusion that its market-based pricing mechanism is consistent with
federal law. In the face of the PUC’s discussion of the merits of the federal compliance question
11
in its decision denying Allco’s request for a stay, a remand to allow the PUC to consider the federal
compliance question, assuming without deciding that it was required to do so, would be pointless.
Thus, we conclude that the PUC ultimately satisfied any requirement that it determine that its
market-based pricing mechanism complies with federal law before proceeding with its 2020 RFP.
B. Compliance with Federal Law
¶ 25. The more challenging question is whether the PUC’s determination that its pricing
mechanism comports with federal law was correct. Allco argues that in light of the broad
preemptive effect of the Federal Power Act, a state may only regulate wholesale electricity sales
if the regulation is authorized by PURPA. Because, Allco contends, PURPA does not authorize
market-based pricing mechanisms, the PUC’s determination that its pricing mechanism complies
with federal law is wrong. DPS disputes Allco’s arguments on the merits, but also argues that this
Court has no jurisdiction to determine whether the market-based pricing mechanism in Vermont’s
standard-offer program complies with federal law.
¶ 26. We consider DPS’s jurisdictional argument first and conclude that we do have
authority to address the federal-compliance issue because the Legislature has incorporated the
federal-compliance question into state law. On the merits, we acknowledge that Allco presents a
close question, but conclude that the market-based standard-offer pricing mechanism does not run
afoul of federal law because QFs like Allco retain the option to compel utilities to enter into power-
purchase contracts at a generic avoided-cost price pursuant to Rule. 4.100, and the market-based
pricing mechanism, combined with the technology-specific avoided-cost caps, are permissible
under PURPA.
i. Jurisdictional Question
¶ 27. DPS argues that pursuant to 16 U.S.C. § 824a-3(h)(2)(B), a QF seeking to enforce
a state’s compliance with PURPA must first petition FERC to bring an enforcement action; if
FERC does not initiate an enforcement action within sixty days of the petition, the petitioner is
12
entitled to bring an action in “the appropriate United States district court.” DPS acknowledges a
number of circumstances in which state courts do have jurisdiction to review the actions of a state
regulatory agency implementing PURPA—such as “as-applied” challenges to a state regulatory
agency’s application of PURPA-compliant regulations to an individual petitioner. See id. § 824a-
3(g). But it argues that a broad facial challenge to the regulations themselves must proceed through
the path outlined in § 824a-3(h)(2)(B)—a petition to FERC and, in the absence of a timely
enforcement action, a complaint in federal district court. DPS cites a Second Circuit opinion in a
different Allco case in support of its argument. See Klee, 805 F.3d at 96-97 (affirming dismissal
of Allco’s challenge to Connecticut’s process for awarding contracts to purchase electricity where
claims at their heart were an attempt to enforce § 824a-3(f), which requires state to implement
FERC’s rules promulgated under § 824a-3(a), so that Allco was required to pursue administrative
exhaustion requirement of § 824a-3(h)(2)(B)). DPS argues that because federal law provides the
exclusive means for considering claims that a state regulatory framework does not comply with
PURPA, this Court cannot address the question in the context of Allco’s appeal.
¶ 28. DPS’s argument fails to account for the fact that the Vermont Legislature has
expressly baked the federal compliance question into the state standard-offer price-setting process,
making the question one of state law. In particular, under 30 V.S.A. § 8005a(f)(1)(A), the PUC
must use the market-based mechanism only “if it first finds that use of the mechanism is consistent
. . . with applicable federal law.” (Emphasis added). And under § 8005a(f)(2), the PUC must use
an administratively determined avoided-cost pricing structure if it finds that a market-based
structure “is inconsistent with applicable federal law.” The Legislature thereby chose to hinge the
PUC’s choice of a pricing mechanism on a threshold determination that market-based pricing
either does or does not comply with federal law. In doing so, the Vermont Legislature has
essentially made the question whether federal law authorizes the use of a market-based pricing
13
structure a question of state law, intrinsic to our review of the PUC’s establishment of a pricing
mechanism and setting of standard-offer contract prices.
¶ 29. Here, Allco is not challenging compliance with federal law as a matter of federal
imperative under PURPA, but rather is challenging compliance with state law, which itself requires
a determination of compliance with federal law, pursuant to § 8005a(f)(1)(A). For that reason,
even if DPS is correct that a direct challenge under federal law to Vermont’s framework for
implementing PURPA must begin with a petition to FERC, followed by a suit in federal court if
FERC declines to enforce—a question we do not decide—that conclusion does not preclude us
from addressing the merits of Allco’s state law claim in the context of this appeal.
¶ 30. We are, however, mindful that because the Legislature has incorporated a question
of federal law into Vermont’s statute, in considering the federal law question, we owe deference
to the federal agency charged with enforcing the federal statute and regulations at issue. See infra,
¶ 44 & n.8. This deference may shape the way we conduct our review, but does not defeat our
jurisdiction to address the question of state law presented by Allco’s appeal.
ii. Compliance with Federal Law
¶ 31. As noted above, Allco argues that the state cannot regulate wholesale power
purchase contracts in interstate commerce unless its regulation complies with PURPA. Relying
largely on a Ninth Circuit decision, Allco argues that the market-based mechanism, which results
in standard-offer contract prices below the PUC-determined avoided cost on a per-technology
basis, violates PURPA. See Winding Creek Solar II, 932 F.3d at 862 (holding that pricing scheme
in California program regulating terms under which electric utilities purchase power from QFs
violated PURPA because it set a market-based rate rather than one based on the utilities’ avoided
cost).
¶ 32. In denying Allco’s motion for stay, the PUC explained that the standard-offer
program complies with PURPA, given the availability of Rule 4.100 contracts for qualifying
14
facilities. In contrast to the California program the Ninth Circuit considered in Winding Creek
Solar II, “Vermont offers a PURPA-compliant alternative to the standard-offer program for Allco
to seek a contract for its qualifying facility.” In the same vein, DPS asserts that Vermont’s
standard-offer program is an allowable auxiliary program to PURPA that in no way supersedes or
replaces the Rule 4.100 program. The standard-offer program gives Vermont QFs an option, if
they so choose, to sell at rates they find acceptable, even if those rates differ from the rates required
pursuant to PURPA’s avoided-cost requirement.
¶ 33. In addition to challenging DPS’s premise, Allco responds that the program
established by Rule 4.100 itself fails to comply with the requirements of PURPA. Thus, even if
DPS is correct that the standard-offer program need not adhere to PURPA’s pricing requirements
if Vermont offers some other program to satisfy PURPA, Vermont does not, in fact, offer any other
program that implements the requirements of PURPA.
¶ 34. We consider in turn the two questions raised by the parties’ positions: whether, if
Rule 4.100 complies with the pricing and other minimum requirements in PURPA, Vermont may
apply a market-based pricing mechanism in its standard-offer program; and whether Rule 4.100
complies with the pricing and other minimum requirements of PURPA.
a. Can the Standard-Offer Program Use Market-Based Pricing if
Rule 4.100 Satisfies PURPA?
¶ 35. As set forth more fully below, FERC has issued two decisions declining to initiate
enforcement actions that provide some support for DPS’s position that if Vermont offers another
PURPA-compliant avenue for QFs to secure contracts to sell power to utilities at avoided-cost
prices, the standard-offer program would also comply with PURPA. We agree with Allco that
states that have implemented the requirements of PURPA are not free to establish other must-take
programs that are not authorized by PURPA. But, we conclude for several reasons that in this case
the PUC did not exceed its discretion where it relied on FERC’s interpretation of PURPA in
15
concluding that to the extent that Rule 4.100 properly implements PURPA, the standard-offer
program, and its market-based pricing mechanism coupled with technology-specific avoided-cost
caps, are also authorized under PURPA.
¶ 36. DPS relies on two FERC notices of intent not to act to support its argument that the
standard-offer program is “an allowable auxiliary program to PURPA.” First, in Otter Creek Solar
LLC (Otter Creek I), FERC declined to initiate an action against the PUC under 16 U.S.C. § 824a-
3(h)(2)(A) to enforce the requirements of PURPA. 143 FERC ¶ 61282, at P 2 (June 27, 2013).
Otter Creek Solar LLC, a QF, had argued that various aspects of the first generation of Vermont’s
standard-offer program—the SPEED Program—violated PURPA. FERC concluded that the
SPEED Program was “an optional program available to certain small renewable QFs,” that the
longstanding Rule 4.100 program offered Vermont QFs the opportunity to participate in a program
that is consistent with PURPA, and that nothing in FERC’s regulations limits the authority of an
electric utility or a QF to agree to rates or terms relating to any purchases that differ from the rates
or terms that would otherwise be required by FERC’s regulations. Id.
¶ 37. In requesting reconsideration, Otter Creek argued that the SPEED Program was
voluntary for QFs, but that it forced utilities to pay more than the avoided-cost rate, in violation of
PURPA, and that it sanctioned the establishment of two different avoided-cost rates under the
respective programs. FERC denied the request, explaining that it declined to exercise its
discretionary enforcement authority where there was no harm to Otter Creek. Otter Creek Solar
LLC (Otter Creek II), 146 FERC ¶ 61192, at P 6 (Mar. 20, 2014). It reiterated that Otter Creek
could avail itself of the Rule 4.100 program, and that “the SPEED program is simply an option
offered by Vermont to QFs like Otter Creek in addition to, but not as a replacement for, the Rule
4.100 program.” Id. at P 7-8. Further, FERC rejected Otter Creek’s argument that there could not
be two rates, noting that it had “long allowed QFs to agree to rates that they find acceptable—even
rates that ‘differ from the rate . . . which would otherwise be required.’ ” Id. at P 8 (alteration in
16
original) (quoting 18 C.F.R. § 292.301(b)(1) (2013)). Although that case did not deal with a
market-based mechanism, FERC’s reasoning suggested that as long as the state meets its
obligations to QFs under PURPA in some way, it may have auxiliary programs to promote
PURPA’s goals with different pricing structures.6
¶ 38. In a formal declaratory order in a subsequent case, Winding Creek Solar LLC
(Winding Creek Solar I), FERC repeated its conclusion that as long as a state has one PURPA-
compliant program, other programs established to create opportunities for QFs to sell the power
they generate are not constrained by the PURPA pricing requirements.7 151 FERC ¶ 61103, at P 6
(May 8, 2015). In that case, California had two programs. The first, Re-MAT, was a feed-in tariff
program with a competitive pricing mechanism, which petitioners argued violated PURPA
because it placed caps on the amount utilities had to purchase from QFs. The second program was
a standard contract program with no cap, through which a QF could obtain a long-term avoided-
cost contract from a utility. FERC recognized that “as long as a state provides QFs the opportunity
to enter into long-term legally enforceable obligations at avoided-cost rates, a state may also have
alternative programs that QFs and electric utilities may agree to participate in.” Id. (citing Otter
Creek I, 143 FERC ¶ 61282, at P 4). Because the state had an existing PURPA-compliant
6
FERC has issued a declaratory order explaining that a Notice of Intent Not to Act, in the
absence of an associated declaratory order, cannot be read to suggest that FERC has accepted or
rejected any argument made by any party. Great Divide Wind Farm, 166 FERC ¶ 61090, at P 20
(Feb. 4, 2019). Absent an accompanying declaratory order, the notice means nothing more than
what it says—FERC declines to initiate an enforcement action under PURPA in response to the
petition for enforcement. Id. In contrast to the declaratory orders in the Great Divide and Winding
Creek Solar I cases, infra, ¶ 38, the Otter Creek I notice cited above, supra, ¶ 36, does not expressly
state that it is a declaratory order. Moreover, in responding to Otter Creek Solar’s request for
reconsideration, FERC relied heavily on its discretion to choose when to pursue enforcement,
rather than on a conclusion that their claims lacked merit. For these reasons, the precedential
impact of FERC’s Otter Creek I analysis is unclear.
7
Because the Winding Creek Solar I order states on its face that it is a declaratory ruling,
we conclude that it is a precedential statement of FERC’s interpretation of PURPA as it applies to
programs, such as Vermont’s standard-offer program, that provide a means for some QFs to secure
contracts to sell power to utilities.
17
program—the standard-contract program—FERC concluded that Re-MAT was permissible
because it was an “alternative program” that QFs could choose to participate in. Id.
¶ 39. Following FERC’s Notice of Intent Not to Act, Winding Creek Solar filed suit in
federal court. The Ninth Circuit disagreed with FERC’s analysis and held that both California
programs violated PURPA and were thus preempted by federal law. Winding Creek Solar II, 932
F.3d at 865-66. The court said, “The Standard Contract violates PURPA because it fails to give
QFs the option to calculate avoided cost at the time of contracting. This infirmity is plain from
the face of the regulations, so we do not defer to FERC’s unreasoned conclusion to the contrary.”
Id. at 865 (emphasis added). Although Allco makes much of the court calling FERC’s conclusion
“unreasoned,” we understand that characterization to refer specifically to FERC’s conclusion that
California’s standard contract program did not violate PURPA—which it overrode—not FERC’s
conclusion that an alternative program is permissible as long as a state otherwise satisfies its
minimum obligations under PURPA. The court in fact recognized FERC’s position “that an
alternative program may exist if a state otherwise satisfies its obligations to QFs under PURPA,”
but expressly said that it need not decide whether this interpretation was due deference “because,
either way, the result is the same” where both programs violate PURPA. Id.
¶ 40. We agree with Allco that Vermont has no authority to compel wholesale sales of
electricity other than as authorized by PURPA. The FPA grants exclusive power to FERC to
regulate the wholesale sale of electric energy in interstate commerce, while PURPA creates a
limited exception through which states may regulate such sales. If a state program regulating the
wholesale sale of electric energy is not authorized by PURPA, the program would run head on into
the preemptive effect of the FPA. See Klee, 805 F.3d at 91 (“States may not act in [the regulation
of wholesale sales of electricity in interstate commerce] unless Congress creates an exception.”).
Although states may offer voluntary programs, they generally cannot compel wholesale
18
transactions unless authorized under PURPA. See FPA § 201(b)(1); Cal. Pub. Utils. Comm’n
(CPUC I), 132 FERC ¶ 61047 (July 15, 2010).
¶ 41. But we conclude that, assuming Rule 4.100 fully satisfies Vermont’s obligations
under PURPA to give QFs an opportunity to sell power on a must-take basis at avoided-cost rates,
the standard-offer program here is itself authorized by PURPA. We base this conclusion on several
considerations. First, in rolling out its regulations implementing PURPA, FERC suggested that
PURPA contemplates that states may establish auxiliary programs to promote the goals of PURPA
in addition to their core programs implementing PURPA, and that those programs may depart from
some of the parameters PURPA requires of the state’s core program implementing PURPA.
Second, we do not understand the PUC to take the position that because Rule 4.100 satisfies
Vermont’s obligations under PURPA, its management of the standard-offer program is
unconstrained by PURPA. Rather, we understand the PUC to take the position that for a number
of reasons, PURPA itself authorizes the standard-offer program. Finally, in the face of differing
reasonable interpretations of PURPA and its implementing regulations, our deference to FERC
impels us to embrace FERC’s interpretation of PURPA.
¶ 42. The PUC’s, and more importantly, FERC’s interpretation of PURPA have some
support in the regulatory history. In adopting regulations implementing 16 U.S.C. § 824a-3, FERC
recognized that states themselves had enacted legislation requiring state electric utilities “to
purchase the electrical output of facilities which may be qualifying facilities under [FERC]’s rules
at rates which may differ from the rates required under [FERC]’s rules implementing [§ 824a-3].”
Small Power Production and Cogeneration Facilities; Regulations Implementing Section 210 of
the Public Utility Regulatory Policies Act of 1978, 45 Fed. Reg. 12,214, 12,221 (Feb. 25, 1980).
Noting that the rules it was adopting were subject to the statutory parameters of § 824a-3, FERC
said “[s]tates are free, under their own authority, to enact laws or regulations providing for rates
which would result in even greater encouragement of these technologies.” Id. This suggests that
19
from the outset, FERC interpreted PURPA to authorize states to establish or maintain additional
programs compelling electric utilities to purchase electricity from QFs at rates other than the
avoided-cost rates defined by PURPA.
¶ 43. Consistent with this, we understand the PUC to take the position that PURPA
authorizes states to supplement their implementation of the basic requirements of PURPA with
programs like the standard-offer program. In particular, states may offer QFs voluntary
opportunities to secure contracts for limited increments of generating capacity when those
programs offer QFs more favorable terms than the generic avoided-cost pricing required by
PURPA and are otherwise “just and reasonable to the electric consumers of the electric utility and
in the public interest” and do not “discriminate against qualifying cogenerators or qualifying small
power producers.” 16 U.S.C. § 824a-3(b); see also CPUC II, 133 FERC ¶ 61059, P 27 (“[W]here
a state requires a utility to procure a certain percentage of energy from generators with certain
characteristics, generators with those characteristics constitute the sources that are relevant to the
determination of the utility’s avoided cost for that procurement requirement.”). The PUC has
concluded that the standard-offer program, which offers some QFs the opportunity to secure
contracts to sell new capacity at prices that exceed generic avoided-cost rates, but are capped by
technology-specific avoided costs, is such a program authorized by PURPA as a complement to
Rule 4.100. The PUC does not claim, as Allco suggests, a “free pass” to ignore PURPA.
¶ 44. Finally, we owe due deference to FERC’s interpretation of PURPA.8 See Levine
v. Wyeth, 2006 VT 107, ¶ 30, 183 Vt. 76, 944 A.2d 179 (considering FDA’s interpretation of
8
Although we defer to an administrative agency’s interpretation of its own statutes, we do
not typically defer to a state agency’s interpretation of federal law where the state agency is
charged with administering a federal program at the local level. See In re Stormwater NPDES
Petition, 2006 VT 91, ¶ 13, n.2, 180 Vt. 261, 910 A.2d 824; Hogan v. Dep’t of Social & Rehab.
Servs., 168 Vt. 615, 617, 727 A.2d 1242, 1243-44 (1998) (mem.). Whether PURPA authorizes
states to establish programs like the standard-offer program as long as they also maintain programs
20
federal law and noting that “[w]e are ordinarily required to defer to an agency’s interpretation of
a statute it administers”), aff’d, 555 U.S. 555 (2009); Hogan v. Dep’t of Social & Rehab. Servs.,
168 Vt. 615, 617, 727 A.2d 1242, 1244 (1998) (mem.) (recognizing that “[w]e defer to an
administrative agency’s interpretation of its own statutes and rules” and deferring to federal
agency’s interpretation as to how federal statutory criteria apply); see also In re Brett, 2014 VT
20, ¶¶ 21, 24, 196 Vt. 1, 93 A.3d 120 (deferring to federal agency where interpretation of federal
law conflicted as between federal agency and state agency).
¶ 45. In the face of reasonable support for FERC’s interpretation of PURPA, our
deference to FERC is determinative in this case. Consistent with FERC’s own interpretation of
PURPA, we accept the PUC’s conclusion that if Rule 4.100 satisfies the requirements of PURPA,
its use of a market-based mechanism in the standard-offer program is authorized by PURPA,
provided that its standard-offer pricing is otherwise “just and reasonable to the electric consumers
of the electric utility and in the public interest, and . . . [does] not discriminate against [QFs].” 16
U.S.C. § 824a-3(b).
with PURPA-compliant pricing is a question of federal law; for that reason, any deference on this
question runs to FERC, not the PUC.
We may defer to an administrative agency’s permissible construction of a statute “when
[the] statute is ‘silent or ambiguous with respect to the specific issue’ the agency has considered;
otherwise, ‘the court, as well as the agency, must give effect to the unambiguously expressed intent
of Congress.’ ” Levine v. Wyeth, 2006 VT 107, ¶ 31, 183 Vt. 76, 944 A.2d 179 (quoting Chevron,
U.S.A., Inc. v. Nat. Res. Def. Council, 467 U.S. 837, 842-43 (1984)). The relevant statute here
authorizes FERC to prescribe “rules as it determines necessary to encourage cogeneration and
small power production . . . which rules require electric utilities to offer to . . . purchase electric
energy from such facilities.” 16 U.S.C. § 824a-3(a)(2). The statute further provides that rules
requiring electric utilities to purchase electric energy from a QF be at rates that are “just and
reasonable to the electric consumers of the electric utility and in the public interest, and . . . not
discriminate against [QFs].” Id. § 824a-3(b). The statute prohibits a must-take rate that exceeds
the incremental cost to the electric utility of alternative electric energy. Id. It is silent, however,
as to whether the rules may allow QFs to voluntarily enter into must-take contracts with electric
utilities at rates that are lower than the electric utility’s technology-specific, administratively
determined incremental cost, but higher than the utility’s generic administratively determined
incremental cost. For that reason, we conclude that deference to FERC’s reasonable interpretation
is warranted.
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b. Rule 4.100
¶ 46. Finally, Allco contends that Rule 4.100 does not satisfy PURPA’s requirements in
two ways. First, the program improperly “caps” the amount of energy that an electric utility must
purchase by limiting the term of a mandatory contract for a utility to purchase electricity from a
QF to a period of seven years. Second, the mandated purchase price is discriminatory because it
is not consistent with the avoided-cost calculation used for the standard-offer program.
¶ 47. As noted above, in its order denying Allco’s motion for stay, the PUC held that
Rule 4.100 complies with PURPA, and satisfies Vermont’s obligation to establish a program to
implement PURPA and its associated regulations. We conclude on this record that the PUC did
not abuse its discretion in concluding that the seven-year must-take contract term was consistent
with PURPA, and we reject Allco’s argument that there cannot be multiple avoided-cost rates
within different programs.
¶ 48. PURPA and its enabling regulations do not require contracts for a particular number
of years, and the record in this case is insufficient to support a conclusion that the seven-year
contract term is inadequate under FERC precedent. FERC’s regulations under PURPA require
that a utility purchase all the energy a QF produces. 18 C.F.R. § 292.303(a) (“Each electric utility
shall purchase . . . any energy and capacity which is made available from a qualifying facility.”).
A state may not place a cap on the amount of energy a utility must purchase. See Winding Creek
Solar II, 932 F.3d at 865. However, states can and do place durational limits on an electric utility’s
obligation to purchase electricity at a set price. FERC has said that, while a legally enforceable
obligation to purchase electricity from a QF “should be long enough to allow QFs reasonable
opportunities to attract capital from potential investors,” its regulations do not specify a particular
number of years for such contracts. Windham Solar LLC & Allco Fin. Ltd., 157 FERC ¶ 61134,
P 8 & n.13 (Nov. 22, 2016) (citing 18 C.F.R. § 292.304(d)(2)). An argument that the seven-year
contract period is inadequate to allow QFs in Vermont reasonable opportunities to attract capital
22
requires more evidence than Allco’s passing assertion in its briefing. On this record, we cannot
conclude that the PUC has exceeded its discretion under PURPA in setting the seven-year term.
¶ 49. We also reject Allco’s argument that the pricing framework in Rule 4.100 is
discriminatory because it is inconsistent with the technology-specific avoided-cost calculations
used in the standard-offer program. FERC has squarely rejected the argument that there cannot be
multiple avoided-cost rates available for QFs. See CPUC II, 133 FERC ¶ 61059, P 29 (affirming
that multi-tiered avoided-cost rate structure, involving multiple avoided-cost calculations
regulations may be valid under PURPA). The technology-specific avoided-cost price calculations
in the standard-offer program provide enhanced incentives to some QFs for a limited increment of
new generation capacity. The source-agnostic avoided-cost price calculation pursuant to Rule
4.100 is calculated consistent with the requirements of PURPA and its implementing regulations.
As set forth above, we defer to FERC’s conclusion that the state is empowered to establish a
program like the standard-offer program to give QFs like Allco a limited opportunity to secure
higher rates for a limited amount of new generation capacity.
Affirmed.
FOR THE COURT:
Associate Justice
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