always has been implemented. Given PURPA's unique statutory scheme
involving state regulatory authorities, nonregulated electric
utilities, QFs, and the Commission, we therefore reject Allco's
assertion that the rules proposed in the NOPR--and adopted in this
final rule--establish an unconstitutional delegation of authority to a
private entity.\138\ And it is beyond the Commission's purview to
consider whether this statutory grant is constitutional.\139\
Accordingly, when we refer to states in this final rule, we usually are
referring to both state regulatory authorities and nonregulated
electric utilities.
---------------------------------------------------------------------------

    \137\ See Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,864
(``The implementation of these rules is reserved to the State
regulatory authorities and nonregulated electric utilities.'').
    \138\ See Allco Comments at 40.
    \139\ Finnerty v. Cowen, 508 F.2d 979, 982 (2d Cir. 1974)
(explaining that administrative agencies ``have neither the power
nor the competence to pass on the constitutionality of
administrative or legislative action'') (quoting Murray v. Vaughn,
300 F. Supp. 688, 695 (D. R.I. 1969)); see also Gibas v. Saginaw
Mining Co., 748 F.2d 1112, 1117 (6th Cir. 1984) (``[A]dministrative
bodies like the Board do not have the authority to adjudicate the
validity of legislation which they are charged with
administering.''); Spiegel, Inc. v. FTC, 540 F.2d 287, 294 (7th Cir.
1976) (finding that the federal agency erred by making a
constitutional determination); Downen v. Warner, 481 F.2d 642, 643
(9th Cir. 1973) (``Resolving a claim founded solely upon a
constitutional right is singularly suited to a judicial forum and
clearly inappropriate to an administrative board.''); cf. Woodrow v.
FERC, 2020 WL 2198050, at *9 (D.D.C. May 6, 2020) (``When Congress
creates an intricate statutory-review process that incorporates
agency consideration and ultimately an avenue to petition an Article
III court, we assume it wants that scheme to control.'').
---------------------------------------------------------------------------

    95. Regarding Public Interest Organizations assertion that the
Commission failed to comply with PURPA section 210's requirement to
consult with federal and state regulatory agencies with ratemaking
authority, we find that the 2016 Technical Conference's invitation to
the public (including state regulatory authorities) to speak, as well
as the notice and comment process on the NOPR itself, encompasses the
required consultation.\140\ The notices soliciting

comments were open to all state authorities. Indeed, since the
Commission first announced that technical conference and up to our
receipt of comments on the NOPR, representatives from several states
have filed comments expressing their views on how the Commission should
implement PURPA.
---------------------------------------------------------------------------

    \140\ See Notice Inviting Post-Technical Conference Comments,
Implementation Issues Under the Public Utility Regulatory Policies
Act of 1978, Docket No. AD16-16-000 (Sept. 6, 2016); Supplemental
Notice of Technical Conference, Implementation Issues Under the
Public Utility Regulatory Policies Act of 1978, Docket No. AD16-16-
000 (Mar. 4, 2016) (announcing preliminary agenda and inviting
interested speakers).
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B. QF Rates

1. Overview
    96. PURPA requires that the Commission promulgate rules, to be
implemented by the states,\141\ that ``shall insure'' that the rates
electric utilities pay for purchases of electric energy from QFs meet
the statutory criteria described above, including that ``[n]o such rule
. . . shall provide for a rate which exceeds'' the purchasing utility's
``incremental cost . . . of alternative electric energy.'' \142\ Under
PURPA, such rates must: (1) Be just and reasonable to the electric
consumers of the electric utility and in the public interest; (2) not
discriminate against qualifying cogenerators or qualifying small power
producers; \143\ and, as noted above, (3) not exceed ``the incremental
cost to the electric utility of alternative electric energy,'' \144\
which is ``the cost to the electric utility of the electric energy
which, but for the purchase from such cogenerator or small power
producer, such utility would generate or purchase from another
source.'' \145\ The ``incremental cost to the electric utility of
alternative electric energy'' referred to in prong (3) above, which
sets out a statutory upper bound on a QF rate, has been consistently
referred to by the Commission and industry by the short-hand phrase
``avoided cost,'' \146\ although the term ``avoided cost'' itself does
not appear in PURPA.
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    \141\ Nonregulated electric utilities implement the requirements
of PURPA with respect to themselves. An electric utility that is
``nonregulated'' is any electric utility other than a ``state
regulated electric utility.'' 16 U.S.C. 2602(9). The term ``state
regulated electric utility,'' in contrast, means any electric
utility with respect to which a state regulatory authority has
ratemaking authority. 16 U.S.C. 2602(18). The term ``state
regulatory authority,'' as relevant here, means a state agency which
has ratemaking authority with respect to the sale of electric energy
by an electric utility. 16 U.S.C. 2602(17).
    \142\ 16 U.S.C. 824a-3(b).
    \143\ 16 U.S.C. 824a-3(b)(1)-(2).
    \144\ 16 U.S.C. 824a-3(b).
    \145\ 16 U.S.C. 824a-3(d) (emphasis added).
    \146\ See 18 CFR 292.101(b)(6) (defining avoided costs in
relation to the statutory terms); see also Order No. 69, FERC Stats.
& Regs. ] 30,128 at 30,865 (``This definition is derived from the
concept of `the incremental cost to the electric utility of
alternative electric energy' set forth in section 210(d) of PURPA.
It includes both the fixed and the running costs on an electric
utility system which can be avoided by obtaining energy or capacity
from qualifying facilities.'').
---------------------------------------------------------------------------

    97. In addition, the PURPA Regulations currently provide a QF two
options for how to sell its power to an electric utility. The QF may
choose to sell as much of its energy as it chooses when the energy
becomes available, with the rate for the sale calculated at the time of
delivery (frequently referred to as a so-called ``as-available'' sale
and rate).\147\ Alternatively, the QF may choose to sell pursuant to a
legally enforceable obligation or LEO (such as a contract) over a
specified term.\148\
---------------------------------------------------------------------------

    \147\ 18 CFR 292.304(d)(1).
    \148\ 18 CFR 292.304(d)(2)(i)-(ii); see also FLS, 157 FERC ]
61,211 at P 21 (citing 18 CFR 292.304(d)). The LEO or contract is
frequently referred to as a long-term transaction, when contrasted
with an ``as available'' sale and rate.
---------------------------------------------------------------------------

    98. If the QF chooses to sell under the second option, the PURPA
Regulations then provide the QF the further option of receiving, in
terms of pricing, either: (1) The purchasing electric utility's avoided
cost calculated at the time of delivery; \149\ or (2) the purchasing
electric utility's avoided cost calculated and fixed at the time the
LEO is incurred.\150\
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    \149\ 18 CFR 292.304(d)(2)(i).
    \150\ 18 CFR 292.304(d)(2)(ii). Rates calculated at the time of
a LEO (for example, a contract) do not violate the requirement that
the rates not exceed avoided costs if they differ from avoided costs
at the time of delivery. 18 CFR 292.304(b)(5).
---------------------------------------------------------------------------

    99. In implementing the PURPA Regulations, the Commission
recognized that a contract with avoided costs calculated at the time a
LEO is incurred could exceed the electric utility's avoided costs at
the time of delivery in the future, thereby seemingly violating PURPA's
requirement that QFs not be paid more than an electric utility's
avoided costs. But the Commission believed that the fixed avoided cost
rate might also turn out to be lower than the electric utility's
avoided costs over the course of the contract and that, ``in the long
run, 'overestimations' and `underestimations' of avoided costs will
balance out.'' \151\ The Commission's justification for allowing QFs to
fix their rate at the time of the LEO for the entire life of the
contract was that fixing the rate provides ``certainty with regard to
return on investment in new technologies.'' \152\
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    \151\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,880. See
also 18 CFR 292.304(b)(5) (``In the case in which the rates for
purchases are based upon estimates of avoided costs over the
specific term of the contract or other legally enforceable
obligation, the rates for such purchases do not violate this subpart
if the rates for such purchases differ from avoided costs at the
time of delivery.''); Entergy Servs., Inc., 137 FERC ] 61,199, at P
56 (2011) (``Many avoided cost rates are calculated on an average or
composite basis, and already reflect the variations in the value of
the purchase in the lower overall rate. In such circumstances, the
utility is already compensated, through the lower rate it generally
pays for unscheduled QF energy, for any periods during which it
purchases unscheduled QF energy even though that energy's value is
lower than the true avoided cost.'').
    \152\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,880.
---------------------------------------------------------------------------

    100. In the NOPR, the Commission proposed to revise its PURPA
Regulations to permit states to incorporate competitive market forces
in setting QF rates. Specifically, the Commission proposed to revise
its PURPA Regulations with regard to QF rates to provide states with
the flexibility to:
     Require that ``as-available'' QF energy rates paid by
electric utilities located in RTO/ISO markets be based on the market's
LMP, or similar energy price derived by the market, in effect at the
time the energy is delivered.
     require that ``as-available'' QF energy rates paid by
electric utilities located outside of RTO/ISO markets be based on
competitive prices determined by: (1) liquid market hub energy prices;
or (2) formula rates based on observed natural gas prices and a
specified heat rate.
     require that energy rates under QF contracts and LEOs be
based on as-available energy rates determined at the time of delivery
rather than being fixed for the term of the contract or LEO.
     implement an alternative approach of requiring that the
fixed energy rate be calculated based on estimates of the present value
of the stream of revenue flows of future LMPs or other acceptable as-
available energy rates at the time of delivery.
     require that energy and/or capacity rates be determined
through a competitive solicitation process, such as an RFP, with
processes designed to ensure that the competitive solicitation is
performed in a transparent, non-discriminatory fashion.\153\
---------------------------------------------------------------------------

    \153\ NOPR, 168 FERC ] 61,184 at PP 32-33.
---------------------------------------------------------------------------

    101. Although the Commission proposed to modify how the states are
permitted to calculate avoided costs, it did not propose to terminate
the requirement that the states continue to calculate, and to set QF
rates at, such avoided costs.
    102. We adopt these proposals in this final rule, with certain
modifications. Each such proposal, and our final determination, is
discussed further below.
2. Use of Competitive Market Prices To Set As-Available Avoided Cost
Rates
    103. In addition to commenting on the specific methods for
determining as-available avoided cost rates, several

commenters addressed more generally the Commission's proposal in the
NOPR that states be given the flexibility to use competitive market
prices to set such rates. Before discussing the specific methods
proposed in the NOPR, we first discuss the determination that the use
of competitive market prices, however determined, can be an appropriate
approach to determining as-available avoided cost rates.
a. NOPR Proposal
    104. In the NOPR, the Commission proposed to give the states the
flexibility to use competitive market prices to set as-available
avoided cost rates. The Commission stated its belief that consideration
of transparent, competitive market prices in appropriate circumstances
would help to identify an electric utility's avoided costs in a
simpler, more transparent, and more predictable manner that would, in
conjunction with the Commission's other existing and proposed PURPA
Regulations, act to encourage QFs.\154\
---------------------------------------------------------------------------

    \154\ Id. P 13.
---------------------------------------------------------------------------

    105. For those utilities located in RTO/ISO markets, the NOPR
identified LMP as a competitive market price that states could choose
to adopt as representing an as-available avoided energy cost. The
Commission explained that LMP could provide an accurate measure of the
varying actual avoided costs for each receipt point on an electric
utility's system where the utility receives power from QFs.\155\ In
addition to these benefits, the Commission observed that LMPs, in
contrast to the administrative pricing methodologies used to set as-
available QF rates by many states, could promote the more efficient use
of the transmission grid, promote the use of the lowest-cost
generation, and provide for transparent price signals.\156\
---------------------------------------------------------------------------

    \155\ Id. P 45.
    \156\ Id. P 48 (citing Cal. Indep. Sys. Operator Corp., 105 FERC
] 61,140, at PP 48-50 (2003); Cf. Price Formation in Energy and
Ancillary Servs. Mkts Operated by Reg'l Transmission Orgs. and
Indep. Sys. Operators, 153 FERC ] 61,221, at P 2 (2015)).
---------------------------------------------------------------------------

    106. For utilities located outside of RTO/ISO markets, the NOPR
proposed to allow states to use two other potential competitively
priced measures of a utility's as-available avoided cost rates: (1)
Energy rates established at liquid market hubs; or (2) energy rates
determined pursuant to formulas based on natural gas price indices and
a proxy heat rate for an efficient natural gas combined-cycle
generating facility. In each such case, though, the state would need to
find that that price reasonably represents a competitive market price
that represents the avoided costs of the purchasing electric
utility.\157\
---------------------------------------------------------------------------

    \157\ NOPR, 168 FERC ] 61,184 at P 51.
---------------------------------------------------------------------------

b. Comments
    107. Allco argues that the only reason for including the use of
competitive market prices to set as-available energy rates is to create
a menu of prices from which a state regulatory authority or unregulated
electric utility can choose the lowest price. Allco claims this
proposal would not encourage QF generation, would be inconsistent with
the rules of economic dispatch, and would be inconsistent with the
language of PURPA.\158\ BluEarth makes similar arguments.\159\ In
contrast, El Paso Electric argues that state regulatory authorities
should be able to set avoided cost rates based on the lesser of a
market hub price or a combined cycle price.\160\ Similarly, the
California Commission argues that utilities located in organized
markets (not just non-organized markets) should also be expressly
permitted to use any competitive price (whether derived from a market
hub, competitive solicitation, or a combined cycle price) to set
avoided cost rates. The California Commission also argues that states
should have the ability to use competitive prices for not just as-
available energy pricing, but also for capacity pricing, and proposes
minor modifications to the relevant regulation text proposed in the
NOPR in order to clarify these points.\161\
---------------------------------------------------------------------------

    \158\ Allco Comments at 8.
    \159\ BluEarth Comments at 2.
    \160\ El Paso Electric Comments at 3-4.
    \161\ California Commission Comments at 23-27.
---------------------------------------------------------------------------

    108. The California Commission argues that the proposed regulations
should be modified to: (1) Define the newly permissible avoided cost
methodologies within the definitions section of Part 292; (2) eliminate
any perception that the new methodologies can only be used to set
avoided costs for as-available energy; (3) allow any appropriate
market-based methodology to set avoided-cost rates for energy, capacity
or both; and (4) define ``Organized Electric Market.'' \162\ The
California Commission believes that the new regulations should
indicate: (1) That they do not provide states any more flexibility than
they already have; (2) that utilities located in organized markets may
use any Market Hub Price, Competitive Solicitation Price, or Combined
Cycle Price to establish avoided-cost rates; and (3) that a price based
on LMP or a Competitive Price is just and reasonable and
nondiscriminatory.\163\
---------------------------------------------------------------------------

    \162\ Id. at 11-14.
    \163\ Id. at 23-25.
---------------------------------------------------------------------------

    109. Some commenters object to the use of competitive markets
prices on the grounds that these competitive prices represent only
short-term, or spot prices that do not reflect the long-term marginal
costs and other costs avoided by purchasing utilities.\164\ Similarly,
some commenters assert that competitive prices cannot support the
financing of QFs.\165\
---------------------------------------------------------------------------

    \164\ IdaHydro Comments at 11; Southeast Public Interest
Organizations Comments at 19; NIPPC, CREA, REC, and OSEIA Comments
at 52, 55 (citing Exelon Wind I, LLC, 140 FERC ] 61,152, at P 52
(2012)); Union of Concerned Scientists Comments at 6.
    \165\ BluEarth Renewables Comments at 2; Biological Diversity at
8; Covanta Comments at 9; Public Interest Organization Comments at
43-44.
---------------------------------------------------------------------------

    110. Public Interest Organizations argue that using competitive
prices to set as-available energy avoided cost rates is discriminatory
because non-QF generators are not limited to competitive prices and
utilities can, and regularly do, pay effective prices for energy that
exceed the price determined by competitive prices.\166\ Several other
commenters express concern about setting QF prices by referencing
short-term liquid hub prices while allowing utilities to rate base and
recover their long-term investments.\167\ Industrial Energy Consumers
argue that, if the Commission implements the liquid market hub
proposal, there must be assurances that utilities' self-builds face the
same market risk exposure as QFs. For example, they argue, if states
expose QFs to variable rates for their energy output, utility-owned
generation should also be exposed to variable rates for their energy
output.\168\
---------------------------------------------------------------------------

    \166\ Public Interest Organizations Comments at 64.
    \167\ IdaHydro Comments at 11; Industrial Energy Consumers
Comments at 12-13.
    \168\ Industrial Energy Consumers Comments at 12-13.
---------------------------------------------------------------------------

    111. Several commenters assert that QF rates should reflect
benefits other than the avoided cost of energy.\169\ For example,
Biogas and Biomass Power state that non-energy benefits, like waste
reduction and economic development must be incorporated into avoided
cost determinations.\170\ Biogas and Resources for the Future state
that locational values should be incorporated into avoided cost
calculations.\171\ American Dams states that utilities' avoided

transmission charges should be included in avoided cost
determinations.\172\ Xcel states that hidden integration and utility
planning costs should also be incorporated into avoided cost
calculations.\173\ American Dams argues that for high capital projects
like hydro, the Commission should consider longer-term public benefits
and not just short-term market pricing.\174\
---------------------------------------------------------------------------

    \169\ Biogas Comments at 1-2; Biomass Power Comments at 1; EPSA
Comments at 14-16; Resources for the Future Comments at 4; Xcel
Comments at 3-5.
    \170\ Biogas Comments at 2; Biomass Power Comments at 1.
    \171\ Biogas Comments at 1; Resources for the Future Comments at
4.
    \172\ American Dams Comments at 4.
    \173\ Xcel Comments at 3-5.
    \174\ American Dams Comments at 2.
---------------------------------------------------------------------------

    112. Solar Energy Industries asserts that payments based on the LMP
should not relieve the purchasing utility of the requirement to
compensate the QF for any values in addition to electricity (e.g.,
renewable energy credits, frequency response capabilities, pro-rated
capacity value, etc.).\175\
---------------------------------------------------------------------------

    \175\ Solar Energy Industry Comments at 27-28.
---------------------------------------------------------------------------

    113. California Utilities request that the Commission clarify that
states may but are not required to consider state policies when
establishing avoided costs.\176\ Harvard Electricity Law requests that
the Commission clarify its rule allowing states to set tiered
rates.\177\
---------------------------------------------------------------------------

    \176\ California Utilities Comments at 18-19.
    \177\ Harvard Electricity Law Comments at 32-33.
---------------------------------------------------------------------------

c. Commission Determination
    114. As an initial matter, we observe that some of the concerns
raised by commenters about the use of competitive market prices to set
as-available energy rates for QFs are based on the incorrect assumption
that the NOPR proposal would permit states to use competitive market
prices to set as-available energy rates for QFs even when competitive
market prices are below the purchasing utility's avoided costs. In
fact, however, the use of competitive market prices to set QF rates is
explicitly subject to the requirement that such prices are equal to the
purchasing utility's avoided energy costs.\178\ As the Supreme Court
noted in API, the full avoided cost rate requirement represents the
maximum rate permitted under PURPA, and thereby provides important
encouragement to QFs.\179\ And as the Supreme Court also noted in the
same decision, ``the full-avoided-cost rule plainly satisfies the
nondiscrimination requirement.'' \180\ Further, in requiring full
avoided cost rates, ``[t]he Commission did not ignore the interest of
electric utility consumers `in receiving electric energy at equitable
rates.' '' \181\
---------------------------------------------------------------------------

    \178\ Arguments that the various competitive market prices
identified in this final rule do not represent avoided energy costs
are addressed below with respect to each such specific market price.
    \179\ API, 461 U.S. at 413.
    \180\ Id.
    \181\ Id. at 415 (quoting Conf. Rep. at 97).
---------------------------------------------------------------------------

    115. For this reason, Allco is incorrect when it claims that the
competitive price proposal represents a menu of prices that a state can
select to choose the lowest rate. In the event that more than one
competitive price option potentially could apply, the state would be
required to select the option that reasonably reflects the purchasing
utility's avoided costs, which is what PURPA requires.\182\
---------------------------------------------------------------------------

    \182\ In a competitive market, the transportation costs between
any such two hubs and a QF would be such that they would make the QF
rate the same, no matter which hub was selected. See FERC, Energy
Primer, A Handbook of Market Basics, at 64 (June 2020), https://www.ferc.gov/market-assessments/guide/energy-primer-2020.pdf (Energy
Primer) (``If there are no transmission constraints, or congestion,
LMPs will not vary significantly across the RTO footprint. However,
when transmission congestion occurs, LMPs will vary across the
footprint because operators are not able to dispatch the least-cost
generators across the entire region and some more expensive
generation must be dispatched to meet demand in the constrained
area.'').
---------------------------------------------------------------------------

    116. Further, the record supports the conclusion that the use of
transparent, competitive market prices provides encouragement to QFs,
represents the avoided cost, and can ensure that the rate does not
exceed the incremental cost to the purchasing electric utility. In
addition to the testimony to this effect presented at the technical
conference and cited in the NOPR,\183\ the conclusion is further
supported by comments submitted in response to the NOPR. For example,
NIPPC, CREA, REC, and OSEIA cite to a report by Fitch, which explains
how Fitch evaluates the financial strength of renewable energy
projects. In this report, Fitch states that it gives a ``stronger''
evaluation to projects with power sales contract prices that are
``indexed using simple, broad-based publicly available indexation
formulas.'' \184\ In addition, Solar Energy Industries notes the
difficulties QFs face in expending large sums to develop their projects
``[f]or states that do not publish the avoided costs, or for utilities
that treat their avoided cost methodologies as confidential trade
secrets.'' \185\
---------------------------------------------------------------------------

    \183\ See American Forest & Paper Association Comments, Docket
No. AD16-16-000, at 8 (filed June 8, 2016) (``To the extent
possible, these determinations [of avoided costs] should not be made
in a `black box', but rather, as part of an open and transparent
method and process.''); EEI Comments, Docket No. AD16-16-000, at 3
(filed June 30, 2016) (``Where transparent competitive markets with
day ahead prices exist, there is no reason to adhere to second-best
avoided cost pricing mechanisms.'').
    \184\ NIPPC, CREA, REC, and OSEIA Comments at 37-38 (citing
FitchRatings, Global Infrastructure & Project Finance, Renewable
Energy Project Rating Criteria, at 3 (Feb. 26, 2019), https://www.fitchratings.com/site/re/10061770).
    \185\ Solar Energy Industries Comments at 41.
---------------------------------------------------------------------------

    117. We agree with commenters who assert that competitive market
prices represent only short-run spot prices that do not reflect
electric utilities' long-run costs that QFs can displace. However, we
are authorizing states to use competitive market prices only to
establish as-available energy rates for QFs. The comments misunderstand
the fundamental difference between the value to a purchasing utility of
such as-available energy and the value to a purchasing utility of
capacity.
    118. A QF has no obligation under the as-available avoided cost
rate provisions to deliver any set amount of electric energy at any
point in the future, but merely is paid for the amount of electric
energy actually delivered. Therefore, the delivery of as-available
energy does not displace any long-term energy the purchasing electric
utility would generate itself or purchase from another source but
rather allows the purchasing utility to reduce the amount of energy it
otherwise would generate itself or purchase from another entity at the
time the QF delivers the energy. Because the QF has no obligation to
deliver any energy in the future, the utility is unable to avoid
constructing or contracting for capacity to meet its future needs as a
consequence of the delivery of energy by the QF. As-available energy
rates therefore appropriately reflect only the short-run value of
energy delivered at the particular moment in time when and if the QF
has energy available to be delivered to the utility.
    119. A QF can displace an electric utility's own generation or
purchases from alternative sources over the long-run when a QF sells
capacity to a utility in addition to as-available energy. In contrast
to as-available energy, a sale of capacity would typically compensate
the QF for maintaining the capability to deliver a set amount of energy
in the future (i.e., capital costs),\186\ and thus allows the
purchasing utility to avoid the cost of making alternative
arrangements, either through a self-build or an alternative purchase,
to obtain that amount of energy. Consequently, the price of capacity
purchased from a QF would reflect this long-run avoided cost. And this
final rule does not alter a purchasing utility's

existing obligation to pay QFs for any avoided capacity benefit that
allows the utility to avoid acquiring capacity.\187\
---------------------------------------------------------------------------

    \186\ See Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,885
(``Energy costs are the variable costs associated with the
production of electric energy (kilowatt-hours). They represent the
cost of fuel, and some operating and maintenance expenses. Capacity
costs are the costs associated with providing the capability to
deliver energy; they consist primarily of the capital costs of
facilities.'').
    \187\ See Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,881-
86 (describing how states must calculate avoided capacity costs).
---------------------------------------------------------------------------

    120. For these reasons, we decline to grant the California
Commission's request to allow using competitive prices for not just as-
available energy pricing, but also for capacity pricing.\188\ We also
reject the California Commission's request to permit all electric
utilities, both those located in organized markets and those located in
non-organized market areas, to use any competitive price (whether a
Market Hub Price or Combined Cycle Price, or alternatively a
Competitive Solicitation Price) to set avoided cost rates. The Market
Hub Price and Combined Cycle Price, as well as the Competitive
Solicitation Price are options that should generally reflect a
purchasing electric utility's avoided as-available energy costs in non-
RTO/ISO areas, while the LMP should generally reflect a purchasing
electric utility's avoided as-available energy costs in RTO/ISO market
areas.
---------------------------------------------------------------------------

    \188\ See infra sections IV.B.3-5. We note that states may use
competitive solicitations to set both energy and capacity avoided
cost rates. See infra section IV.B.8.
---------------------------------------------------------------------------

    121. With respect to the discrimination claims, our decision to
give states the flexibility to use competitive prices is driven by the
fact that the competitive market price represents the purchasing
utility's avoided costs. And, as explained in Section IV.A.2 above, a
rate set at full avoided costs by definition cannot be discriminatory
and, in any event, the Commission is without authority under PURPA
section 210(b) to require a rate above avoided costs.
    122. Further, Industrial Energy Consumers are incorrect when they
suggest that public utility energy rates do not vary with costs in the
same way that the competitive market prices potentially applicable to
QFs under the final rule vary. To the contrary, the Commission and most
states provide for fuel adjustment clauses applicable to rates, which
allow utility rates to adjust automatically with changes in utility
fuel and purchased power costs.\189\ And even utilities whose rates do
not include fuel and purchased power adjustment clauses nevertheless
typically must charge their retail customers cost-based rates, which
means that their energy charges will vary from one rate case to the
next as their fuel and purchased power costs vary from year to year.
These mechanisms for ensuring that utility rates vary with the cost of
energy result in variances in utility energy rates that are similar to
the variance in QF energy rates for those states that elect a
Competitive Price option (either a Market Hub Price or a Combined Cycle
Price) for as-available avoided cost rates.
---------------------------------------------------------------------------

    \189\ See 18 CFR 35.14 (Fuel Cost and Purchased Economic Power
Adjustment Clauses); ELCON, Fuel Adjustment Clauses & Other Cost
Trackers, https://elcon.org/fuel-adjustment-clauses-cost-trackers
(``Fuel adjustment clauses are in effect in almost all states.'');
NARUC, Staff Subcommittee on Accounting and Finance, Fuel and
Purchased Power Survey Results (Sept. 23, 2015), https://pubs.naruc.org/pub/4AA28D50-2354-D714-5149-B773EFC3EFEF (stating
that only one state surveyed said that it did not employ a fuel
adjustment clause).
---------------------------------------------------------------------------

    123. Finally, although we are sympathetic to the claims of certain
QFs that they provide non-energy benefits (such as environmental
benefits, waste reduction benefits, and economic development benefits)
that are not reflected in avoided cost rates, PURPA section 210(b)
prohibits the Commission from requiring QF rates to be set above full
avoided costs. Because the Commission already requires states to set QF
rates at full avoided costs, it is barred from requiring QF rates set
higher than that based on the non-energy benefits that QFs may also
provide. However, nothing in PURPA, the PURPA Regulations as they
currently exist, or this final rule would prevent states from rewarding
QFs for such non-energy benefits so long as that is done outside of
PURPA, such as is now done for renewable energy credits (RECs) to
compensate QFs for providing unique environmental or other non-PURPA
benefits.\190\ We address in the sections below each type of
competitive price that could be used as an acceptable energy avoided
cost.
---------------------------------------------------------------------------

    \190\ See, e.g., American Ref-Fuel Co., 105 FERC ] 61,004, at PP
22-24 (2003), denying reh'g, 107 FERC ] 61,016 at PP 12, 15-16
(2004), dismissing pet. for review sub nom. Xcel Energy Servs. Inc.
v. FERC, 407 F.3d 1242 (D.C. Cir. 2005).
---------------------------------------------------------------------------

3. LMP as a Permissible Rate for Certain As-Available Avoided Cost
Rates
a. NOPR Proposal
    124. The Commission proposed to revise 18 CFR 292.304 to add
subsections (b)(6) and (e)(1). In combination, these subsections would
permit a state the flexibility to set the as-available energy rate paid
to a QF by an electric utility located in an RTO/ISO at LMPs calculated
at the time of delivery.
    125. The Commission explained that RTO/ISO markets calculate a LMP
at each location on the RTO/ISO-controlled grid, and that all sellers
receive the LMP for their location and all buyers pay the market
clearing price for their location. The Commission further recognized
that LMPs reflect the true marginal cost of production, taking into
account all physical system constraints, and these prices would fully
compensate all resources for the variable cost of providing
service,\191\ and explained that prices in such an LMP-based rate
structure are designed to reflect the least-cost of meeting an
incremental megawatt-hour of demand at each location on the grid in
each period, and thus such prices can vary based on location and
time.\192\
---------------------------------------------------------------------------

    \191\ Offer Caps in Mkts Operated by Reg'l Transmission Orgs.
and Independent Sys. Operators, Order No. 831, 157 FERC ] 61,115, at
P 7 (2016), order on reh'g and clarification, Order No. 831-A, 161
FERC ] 61,156 (2017).
    \192\ Sacramento Mun. Util. Dist. v. FERC, 616 F.3d 520, 524
(D.C. Cir. 2010) (SMUD); see also FERC v. Elec. Power Supply Ass'n,
136 S. Ct. 760, 768-69 (2016) (describing how LMP is typically
calculated).
---------------------------------------------------------------------------

    126. The Commission therefore preliminarily found that LMP is an
accurate measure of avoided costs. Unlike, for example, average system-
wide cost measures of avoided cost used by many states, LMP could
provide an accurate measure of the varying actual avoided costs for
each receipt point on an electric utility's system where the utility
receives power from QFs; LMP is the per MWh cost of obtaining
incremental supplies at each point. Further, the Commission explained
that these prices are not rigid, long-lasting prices as tends to be the
case currently for administratively-determined avoided costs, but
prices that are calculated daily (for the day-ahead markets) and/or
every five minutes (for real-time markets) and they vary to reflect
changing system conditions (e.g., they tend to rise as demand increases
and the system operator dispatches increasingly expensive supplies to
meet that higher demand). In addition, the Commission observed that
LMPs, in contrast to the administrative pricing methodologies used to
set as-available QF rates by many states, could promote the more
efficient use of the transmission grid, promote the use of the lowest-
cost generation, and provide for transparent price signals.\193\
Finally, the Commission also noted that Congress, through enactment of
PURPA section 210(m), appears to have recognized that RTO/ISO LMP
pricing provides sufficient encouragement for QFs.
---------------------------------------------------------------------------

    \193\ See, e.g., Cal. Indep. Sys. Operator Corp., 105 FERC ]
61,140, at PP 48-50 (2003); cf. Price Formation in Energy and
Ancillary Servs. Mkts Operated by Reg'l Transmission Orgs. and
Indep. Sys. Operators, 153 FERC ] 61,221, at P 2.
---------------------------------------------------------------------------

    127. The Commission requested comment on whether the real-time
prices established in the CAISO-administered Energy Imbalance Market

(EIM) \194\ are similar for these purposes to the LMP in RTOs/ISOs. In
this regard, the Commission requested comment on whether ``prices
developed in the EIM similarly `reflect the least-cost of meeting an
incremental megawatt-hour of demand at each location on the grid,' as
the Commission has found to be the case with LMP rates.'' \195\
---------------------------------------------------------------------------

    \194\ The Commission noted that, by seeking comment regarding
the Western EIM prices, the Commission did not mean to imply that
real-time energy prices established by CAISO within its balancing
authority area do not already satisfy the requirement for setting
as-available QF rates.
    \195\ NOPR, 168 FERC 61,184 at P 47 (quoting SMUD, 616 F.3d at
524). Use of real time prices in the Western EIM was addressed at
the Technical Conference, but only in the context of whether that
market could satisfy the requirements for termination of the
mandatory purchase obligation under PURPA section 210(m)(1)(C). See
Supplemental Notice of Technical Conference, Implementation Issues
Under the Public Utility Regulatory Policies Act of 1978, Docket No.
AD16-16-000 (May 9, 2016). The Commission here requested comments on
whether it would be appropriate to use the Western EIM price to
develop an as-available energy rate.
---------------------------------------------------------------------------

    128. The Commission understood that some states already use LMP to
establish avoided cost energy rates under the existing PURPA
Regulations.\196\ The Commission thus proposed also to clarify that,
while a state in the past may have been able to conclude that LMP was
an appropriate measure of the energy component of avoided costs,\197\ a
state would, under the proposal in the NOPR, be able to adopt LMP as a
per se appropriate measure of the as-available energy component of
avoided costs.\198\
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    \196\ See Exelon Wind 1, LLC, 140 FERC ] 61,152, at P 11,
reconsideration denied, 155 FERC ] 61,066 (2016) (recognizing that
the Texas Public Utility Commission has permitted Southwestern
Public Service Company to set avoided costs at LMP); Xcel Energy
Services Inc., Request for Reconsideration, Docket No. EL12-80-001,
at 13 & n.23 (filed Sept. 27, 2012) (stating that Maryland, New
Jersey, North Carolina, Virginia, Connecticut, New Hampshire,
Kentucky, and Michigan have set avoided costs at LMP).
    \197\ See 18 CFR 292.304(e).
    \198\ The Commission recognized in the NOPR that this proposal
could be seen as a departure from the Commission's statement in
Exelon Wind 1, LLC, 140 FERC ] 61,152 at P 52, reconsideration
denied, 155 FERC ] 61,066 (``The problem with the methodology
proposed by [Southwestern Public Service Company] and adopted by the
Texas Commission is that it is based on the price that a QF would
have been paid had it sold its energy directly in the [Energy
Imbalance Service] Market, instead of using a methodology of
calculating what the costs to the utility would have been for self-
supplied, or purchased, energy `but for' the presence of the QF or
QFs in the markets, as required by the Commission's regulations.'').
The Commission has since found that this statement was overtaken by
events, namely SPP's evolution from an energy imbalance service
market into an Integrated Marketplace, with day-ahead and real-time
energy and operating reserve markets and the Texas Commission's
approving a separate request from Southwestern Public Service
Company to substitute LMP for Locational Imbalance Prices in
calculating avoided costs. Exelon Wind 1, LLC, 155 FERC ] 61,066 at
P 11. The Commission also has acknowledged that, if adopted in a
final rule, the reasoning in the NOPR supported a departure from
precedent. See Cal. Pub. Utils. Comm'n v. FERC, 879 F.3d 966, 977
(9th Cir. 2018) (``When an agency changes policy, the requirement
that it provide a reasoned explanation for its action demands, at a
minimum, that the agency `display awareness that it is changing
position.''') (citing FCC v. Fox Television Stations, Inc., 556 U.S.
502, 515 (2009)).
---------------------------------------------------------------------------

b. Comments
i. Comments in Opposition
    129. Several commenters oppose the NOPR's LMP proposal.\199\
American Biogas asserts that, by definition, LMP rates assume that
generating facilities are receiving other compensation to fund their
operations and that the marginal rate reflects only the value of the
energy. American Biogas asserts that LMP ignores biogas facilities'
unique municipal infrastructure role and multiple benefits to the
community.\200\ Covanta argues that avoided costs paid to small
baseload QFs should incorporate all long-run avoided costs for capacity
and energy and include other externalities such as the value of
renewable baseload energy, greenhouse gas mitigation, landfill
diversion, reliable and resilient power and other benefits of small
baseload QFs.\201\ Biological Diversity argues that LMP pricing ignores
variability across the country and is inappropriate in regions like the
Southeast which lack RTOs and ISOs and are instead still dominated by
vertically-integrated monopolies.\202\
---------------------------------------------------------------------------

    \199\ Biogas Comments at 2; Covanta Comments at 8-9; Biological
Diversity Comments at 8-9; CA Cogeneration Comments at 8-9; ELCON
Comments at 23-25; ENGIE Comments at 4; New England Small Hydro
Comments at 8-11; NIPPC, CREA, REC, and OSEIA Comments at 53-60;
Public Interest Organizations Comments at 52-64; Union of Concerned
Scientists Comments at 4-9; Southeast Public Interest Organizations
Comments at 21-25.
    \200\ Biogas Comments at 2.
    \201\ Covanta Comments at 8.
    \202\ Biological Diversity Comments at 8-9.
---------------------------------------------------------------------------

    130. CA Cogeneration argues that LMP may not represent a truly
competitive price for electricity because, in California, the majority
of supply is through bilateral contracts, not through competitive
bidding in the market. CA Cogeneration states that rooftop solar
distorts LMP by reducing load and not bidding in its full long-term
marginal cost.\203\ CA Cogeneration states that LMPs can be well below
the operating cost of conventional generation and combined heat and
power, and even negative, especially when there is an abundance of
procured resources such as hydro, solar, and wind.\204\ CA Cogeneration
asserts that combined heat and power can survive only if: (1) Fixed
capacity prices are sufficiently high to cover the energy price risk;
(2) the market price reflects the full cost of contracted power and
includes all sources of supply; or (3) 18 CFR 292.304(f)(1) is modified
to provide QF operations first priority, except in special
circumstances related to reliability.\205\
---------------------------------------------------------------------------

    \203\ CA Cogeneration Comments at 8-9.
    \204\ Id.
    \205\ Id.
---------------------------------------------------------------------------

    131. ELCON argues that allowing utilities to use LMP and other
competitive market prices would allow states to ignore long-standing
factors established by Commission regulation in determining the avoided
cost rates, including: (1) Availability of capacity or energy from a QF
during the system daily and seasonal peak periods; (2) dispatchability
and reliability; (3) the relationship of the availability of energy or
capacity from the QF to the ability of the utility to avoid costs; (4)
costs or savings from variations in line losses; and (5) application of
technology-specific avoided cost rates.\206\ ENGIE argues that allowing
states to set energy rates at LMP, while also allowing them to set
capacity rates at zero if it is determined that a utility has no need
for capacity, could allow traditional utilities to corner the market on
capacity, leaving smaller independent QFs to fill energy-only contracts
at LMP.\207\
---------------------------------------------------------------------------

    \206\ ELCON Comments at 23-24.
    \207\ ENGIE Comments at 4.
---------------------------------------------------------------------------

    132. New England Small Hydro states that the Commission has not
supported the NOPR's assertion that LMP is an accurate measure of
avoided costs because the NOPR: (1) Inappropriately relies on the
Energy Policy Act of 2005's changes in PURPA section 210(m) to support
its proposed changes to calculation of the avoided cost rate; (2)
ignores the costs that the utility pays to procure power (i.e., RFPs,
other power contracts, planned retirements); and (3) ignores the fact
that LMP and the default service rates that exist in ISO-NE-based
states are quite different.\208\ In addition, New England Hydro states
that, for the avoided cost calculation, the appropriate LMP is the day-
ahead LMP, not the real-time LMP, because utilities primarily purchase
energy in the day-ahead market pursuant to bilateral contracts or RFPs,
not in the real-time market.\209\ New England Hydro also believes that
utilities or state regulatory bodies should be required to establish
and maintain long-term avoided energy forecasts upon which

QF PURPA power purchase rates would be based.\210\
---------------------------------------------------------------------------

    \208\ New England Small Hydro Comments at 8-10.
    \209\ Id. at 10.
    \210\ Id. at 11.
---------------------------------------------------------------------------

    133. NIPPC, CREA, REC, and OSEIA claim that LMPs only promote more
efficient use of the transmission grid in the short-term because
factors such as temporary outages, equipment failures, weather
extremes, and the like can cause LMPs to spike, but these have no
impact on long-term transmission availability.\211\ NIPPC, CREA, REC,
and OSEIA believe that, while LMPs are a useful tool for developers to
identify points on the grid where transmission is relatively more or
less congested, developers have strong incentives to avoid congestion,
and they will generally be guided to areas of low congestion during the
transmission interconnection process, whether or not they face LMP-
based contract prices. NIPPC, CREA, REC, and OSEIA claim that if
transmission constraints prevent a generator from delivering power to a
specific node, the LMP at that node cannot be an appropriate measure of
costs avoided by purchase of power from that generator. NIPPC, CREA,
REC, and OSEIA argue that LMP or Western EIM prices at the time of
delivery are not a true measure of the long-term avoided costs of
incumbent utilities unless those utilities are relying on those markets
as a means to obtain long-term resources.\212\
---------------------------------------------------------------------------

    \211\ NIPPC, CREA, REC, and OSEIA Comments at 57-59.
    \212\ Id. at 55 (citing Exelon Wind I, 140 FERC ] 61,152 at P
52).
---------------------------------------------------------------------------

    134. NIPPC, CREA, REC, and OSEIA assert that the NOPR proposal
fails to recognize: (1) the Commission's struggle to develop effective
capacity markets in the RTO/ISO regions; (2) the fact that the merchant
generation model is now in serious question; and (3) that the
Commission's claim that Congress endorsed the use of LMP to set avoided
cost rates by adoption of section 210(m) cannot be squared with the
plain language of the statute.\213\ NIPPC, CREA, REC, and OSEIA argue
that there is substantial evidence that LMP prices are distorted by
certain practices, such as zero-cost bids, so that plants operate
uneconomically.\214\ NIPPC, CREA, REC, and OSEIA further maintain that
the 2000-01 California market demonstrated that these volatile short-
term markets can reach extreme and unpredictable highs under stress
conditions.\215\
---------------------------------------------------------------------------

    \213\ Id. at 57-59.
    \214\ Id. at 55.
    \215\ Id. at 57.
---------------------------------------------------------------------------

    135. Similarly, Public Interest Organizations cite to studies by
the Sierra Club \216\ and Bloomberg New Energy Finance,\217\ for the
proposition that the use of LMP as the QF price discriminates against
QFs where utility-owned generation and non-QF generators are not
limited to the LMP for recovery of their costs, and where utilities
depress LMP through uneconomic dispatch of their own generation
facilities.\218\ Union of Concerned Scientists states that LMPs are not
an accurate measure of avoided costs and should not be used to set QF
rates because the practice of providing utility-owned generation with
out-of-market cost-recovery in areas like MISO, PJM, SPP, the SERC
Reliability Corporation, and the Western Electricity Coordinating
Council suppresses the clearing prices in the markets where this is
allowed.\219\
---------------------------------------------------------------------------

    \216\ Public Interest Organizations Comments at 53-56 (citing
Jeremy Fisher, Sierra Club, Playing with Other People's Money, How
Non-Economic Coal Operations Distort Energy Markets, Sierra Club,
Oct. 2019, at 4).
    \217\ Id. at 57 (citing William Nelson & Sophia Liu, Half of
U.S. Coal Fleet on Shaky Economic Footing; Coal Plant Operating
Margins Nationwide, Bloomberg New Energy Finance, March 26, 2018).
    \218\ Id. at 52-64.
    \219\ Union of Concerned Scientists Comments at 3-8.
---------------------------------------------------------------------------

    136. Southeast Public Interest Organizations argue that the NOPR's
proposed avoided cost methodology does not take into account: (1) Long-
term or seasonal purchases made from third parties or affiliates; (2)
adjustments for transmission and distribution losses; (3) capacity
deferrals; (4) avoided environmental compliance costs; or (5) a QF's
dispatchability.\220\ Southeast Public Interest Organizations state
that LMP-based rates for QFs in Virginia have enticed little-to-no QF
development in Virginia.\221\ Southeast Public Interest Organizations
urge the Commission either to rescind the NOPR's LMP provisions or at
least to implement this provision on a case-by-case basis.\222\
---------------------------------------------------------------------------

    \220\ Southeast Public Interest Organizations Comments at 22.
    \221\ Id. at 23.
    \222\ Id. at 24.
---------------------------------------------------------------------------

(a) Utilizing Western EIM To Establish Avoided Costs
    137. Solar Energy Industries argues that, because as-available QF
resources are not eligible to participate in the Western EIM (also
known as the CAISO EIM), either directly or through the purchasing
utility, it would be inappropriate to use the Western EIM price as a
proxy because that market does not factor in the participation of the
QF resource.\223\ ELCON asserts that the Western EIM is not a complete
measure of avoided energy costs because the Western EIM merely covers
imbalance conditions, and therefore does not capture the vast majority
of unit commitment and dispatch scheduling cost parameters.\224\ Union
of Concerned Scientists asserts that allowing a state to adopt real-
time prices established in the Western EIM as an accurate measure of
avoided costs will be discriminatory.\225\
---------------------------------------------------------------------------

    \223\ Solar Energy Industries Comments at 27.
    \224\ ELCON Comments at 24.
    \225\ Union of Concerned Scientists Comments at 9.
---------------------------------------------------------------------------

ii. Comments in Support
    138. Several commenters support the Commission's proposal to permit
a state the flexibility to use LMPs to set the as-available energy rate
paid to a QF by an electric utility located in an RTO/ISO.\226\
---------------------------------------------------------------------------

    \226\ APPA Comments at 11; Arizona Public Service Comments at 5;
CA Utilities Comments at 17; Conn. Authority Comments at 13; DTE
Electric Comments at 4; EEI Comments at 22-24; Comments at 4-5;
Idaho Commission Comments at 3-4; Indiana Municipal Comments at 5;
Kentucky Commission Comments at 4-5; NorthWestern Comments at 4-7;
NRECA Comments at 6-7; Ohio Commission Energy Advocate Comments at
4-5; Pennsylvania Commission Comments at 7-9; South Dakota
Commission Comments at 2; US Chamber of Commerce Comments at 4; We
Stand Comments at 1; Xcel Comments at 5.
---------------------------------------------------------------------------

    139. CA Utilities state that the NOPR's LMP proposal is a return to
the Commission's policy as expressed in Winding Creek,\227\ and will
facilitate payments to QFs that more accurately represent a utility's
actual avoided costs. CA Utilities assert that the NOPR's LMP proposal
affirms that a formula energy price contract complies with PURPA if
coupled with a fixed capacity price. CA Utilities state that a formula
energy price contract will have the additional benefit of avoiding the
need to develop and administer a new PURPA contract.\228\
---------------------------------------------------------------------------

    \227\ CA Utilities Comments at 15-17 (citing Winding Creek Solar
LLC, 151 FERC ] 61,103, at P 6 (2015)).
    \228\ Id. at 17.
---------------------------------------------------------------------------

    140. NRECA supports the Commission's proposal because many
utilities that participate in the RTO/ISO markets offer the entirety of
their generation into the market, and purchase all of their
requirements to serve load from that market, at LMP prices.\229\
---------------------------------------------------------------------------

    \229\ NRECA Comments at 6.
---------------------------------------------------------------------------

    141. The Pennsylvania Commission supports the NOPR proposal because
LMP prices vary through the day based on changing system conditions,
such as changes in electricity demand, supply, congestion, and line
losses. The Pennsylvania Commission asserts that, because some
utilities in Pennsylvania

(and other states) have already incorporated LMP elements in their as-
available energy rates, a corresponding revision to the Commission's
regulations that incorporates such practices and harmonizes state and
federal regulations would bring greater predictability to suppliers,
electric utilities and customers.\230\
---------------------------------------------------------------------------

    \230\ Pennsylvania Commission Comments at 7-8.
---------------------------------------------------------------------------

    142. The Ohio Commission Energy Advocate believes that, in the
parts of the country with organized nodal wholesale electricity
markets, LMP is an appropriate and fair means by which to calculate
avoided costs because electricity supply and demand must be balanced in
real time. The Ohio Commission Energy Advocate notes that Ohio has
nodal LMPs that reflect the true value of energy at the place and the
time it is produced or delivered, and this value can change
dramatically, even within a day or an hour. The Ohio Commission Energy
Advocate concludes that reflecting the dynamic nature of electricity
pricing in avoided cost calculations will send the most accurate price
signals to QFs and will appropriately and fairly value the energy they
produce.\231\
---------------------------------------------------------------------------

    \231\ Ohio Commission Energy Advocate Comments at 4-5.
---------------------------------------------------------------------------

    143. The South Dakota Commission supports using LMP for certain as-
available QF energy sales because using LMP will increase states'
flexibility. The South Dakota Commission regulates six vertically
integrated electric utilities, five of which are RTO members, and five
of which are multi-jurisdictional.\232\
---------------------------------------------------------------------------

    \232\ South Dakota Commission Comments at 2.
---------------------------------------------------------------------------

    144. Xcel submits that compensating QFs based on LMPs at the time
of delivery will not impair QFs' ability to obtain financing because
other factors can drive the ability to obtain financing, including
other project options, location, size, interconnection costs,
experience of the developer, current economic conditions,
creditworthiness of the developer, economies of scale, and other
factors. Xcel states that some resource specific information generally
suggests that the right project in the right location can obtain
financing if the project receives hourly payment based on LMPs.\233\
---------------------------------------------------------------------------

    \233\ Xcel Comments at 5-7.
---------------------------------------------------------------------------

(a) Utilizing Western EIM To Establish Avoided Costs
    145. NorthWestern and EIM Entities agree that the Western EIM real-
time prices are similar to LMPs and reflect the least cost of meeting
an incremental megawatt-hour of demand at each location on the
grid.\234\ Xcel asserts that prices in the Western EIM are calculated
using the same methodology as LMPs because, in both cases, units are
dispatched on a least-cost basis that respects applicable transmission
constraints. Xcel requests that the Commission allow avoided costs to
be based on Western EIM prices at the time of delivery absent a showing
that prices would be suppressed in comparison to an LMP-style-
market.\235\ Arizona Public Service states that it is a participant in
the Western EIM, and requests that states be given flexibility to set
the as-available energy rate to be paid to a QF by an electric utility
that participates in the Western EIM at the LMP.\236\
---------------------------------------------------------------------------

    \234\ EIM Entities Comments at 2-3, 7-13; NorthWestern Comments
at 4-5.
    \235\ Xcel Comments at 7-8.
    \236\ Arizona Public Service Comments at 5-6.
---------------------------------------------------------------------------

iii. Comments in Support With Requested Modifications/Clarifications
    146. APPA urges the Commission to clarify that nothing in the
proposed rule is intended to call into question state regulatory
authorities' existing implementation of PURPA's avoided cost
requirements, such as their existing use of LMP.\237\
---------------------------------------------------------------------------

    \237\ APPA Comments at 9.
---------------------------------------------------------------------------

    147. Industrial Energy Consumers do not object to the use of LMP as
the avoided cost rate for electric utilities' purchases of QF energy in
RTO/ISO regions,\238\ but they maintain that in non-RTO/ISO regions,
there must be assurance that utilities' self-builds face the same
market risk exposure as QFs.\239\
---------------------------------------------------------------------------

    \238\ Industrial Energy Consumers Comments at 11.
    \239\ Id. at 12.
---------------------------------------------------------------------------

    148. The Kentucky Commission supports the NOPR's LMP proposal but
prefers that the Commission in the final rule allow states to determine
whether the LMP calculation should use the generator LMP or the load
LMP on a case-by-case basis.\240\
---------------------------------------------------------------------------

    \240\ Kentucky Commission Comments at 4-5.
---------------------------------------------------------------------------

    149. Solar Energy Industries assert that, where the purchasing
utility has demonstrated that it procures its marginal energy from an
LMP market, the utility may use the LMP price as a proxy for avoided
energy costs calculated at the time the obligation is incurred, so long
as there are published prices at the location.\241\ Solar Energy
Industries request that the Commission make clear that: (1) The
flexibility to set QF payment rates for as-available energy at the
applicable LMP requires an on-the record determination that the
purchasing utility procures incremental energy from the identified LMP
market at those prices; (2) payments based on an LMP do not relieve the
purchasing utility of the requirement to compensate the QF for any
values in addition to electricity (e.g., renewable energy credits,
frequency response capabilities, pro-rated capacity value, etc.); and
(3) the state's flexibility to allow utilities to set QF payment rates
for as-available energy at the applicable LMP does not in any way limit
QFs' rights to establish a LEO or contract for a longer-term sale at
fixed, full avoided costs.\242\
---------------------------------------------------------------------------

    \241\ Solar Energy Industries Comments at 25-26.
    \242\ Id. at 27-28.
---------------------------------------------------------------------------

    150. NorthWestern believes that as-available rates based on LMPs
should accurately capture current events impacting prices, including
times when there is a high saturation of energy available causing
prices to be negative. However, NorthWestern believes that it is
appropriate to deduct from the avoided cost rate the cost for ancillary
services to balance and integrate energy resources.\243\
---------------------------------------------------------------------------

    \243\ NorthWestern Comments at 4-5.
---------------------------------------------------------------------------

c. Commission Determination
    151. We affirm with one modification the NOPR proposal to allow LMP
to be used as a measure of as-available energy avoided costs for
electric utilities located in RTO/ISO markets for the reasons set forth
in the NOPR \244\ and those provided by various commenters.
---------------------------------------------------------------------------

    \244\ NOPR, 168 FERC ] 61,184 at PP 44-45.
---------------------------------------------------------------------------

    152. We recognize that an LMP selected by a state to set a
purchasing utility's avoided energy cost component might not always
reflect a purchasing utility's actual avoided energy costs.
Accordingly, we find that it is appropriate to modify the option for a
state to set avoided energy costs using LMP from a per se appropriate
measure of avoided cost to a rebuttable presumption that LMP is an
appropriate means to determine avoided cost. While a state could rely
on the presumption, an aggrieved entity (such as a QF) may attempt to
rebut the presumption that LMP reflects the purchasing electric
utility's avoided costs. The aggrieved entity would be able to
challenge the state's decision to rely on LMP in the appropriate forum,
which could include any one or more of the following: (1) Initiating or
participating in proceedings before the relevant state commission or
governing body; (2) filing for judicial review of any state regulatory
proceeding in state court (under PURPA section 210(g)); or,
alternatively (3)) filing a petition for enforcement against the state
at the Commission and, if the Commission declines to act, later filing
a petition against the state in U.S.

district court (under PURPA section 210(h)(2)(B)).\245\
---------------------------------------------------------------------------

    \245\ See Policy Statement Regarding the Commission's
Enforcement Role Under Section 210 of the Public Utility Regulatory
Policies Act of 1978, 23 FERC ] 61,304.
---------------------------------------------------------------------------

    153. Commenters have not persuaded us that LMP may not
presumptively reflect a purchasing electric utility's avoided energy
costs. LMP sets day-ahead and real-time energy prices through
competitive auctions in RTOs/ISOs that optimally dispatch resources to
balance supply and demand, while taking into account actual system
conditions including congestion on the transmission system. We continue
to find that: (1) LMPs reflect the true marginal cost of production of
energy, taking into account all physical system constraints; (2) these
prices would fully compensate all resources for their variable cost of
providing service; (3) LMP prices are designed to reflect the least-
cost of meeting an incremental megawatt-hour of demand at each location
on the grid, and thus prices vary based on location and time; and (4)
unlike average system-wide cost measures of the avoided energy cost
used by many states, LMP should provide a more accurate measure of the
varying actual avoided energy costs, hour by hour, for each receipt
point on an electric utility's system where the utility receives power
from QFs.\246\
---------------------------------------------------------------------------

    \246\ See NOPR, 168 FERC ] 61,184 at PP 44-45 (citing SMUD, 616
F.3d at 524; FERC v. Elec. Power Supply Ass'n, 136 S. Ct. at 768-69
(describing how LMP is typically calculated); Order No. 831, 157
FERC ] 61,115, at P 7, order on reh'g and clarification, Order No.
831-A, 161 FERC ] 61,156).
---------------------------------------------------------------------------

    154. Various commenters have provided additional reasons for
supporting the NOPR proposal concerning LMP. NRECA explains that LMP
rates for energy are appropriate because many utilities that
participate in the RTO/ISO markets offer the entirety of their
generation into the market at LMP prices and buy all of their load
requirements from the market at LMP prices.\247\ This scenario
described by NRECA is a common one, and it demonstrates that the market
itself, with its LMP pricing, can be the electric utility resource that
would be displaced by a QF purchase. Furthermore, as argued by
Pennsylvania Commission, because some utilities in Pennsylvania and
other states have already incorporated LMP in their as-available energy
rates, a corresponding revision to the Commission's regulations that
incorporates such practices and harmonizes state and federal
regulations would bring greater predictability to suppliers, electric
utilities and customers.\248\
---------------------------------------------------------------------------

    \247\ NRECA Comments at 6.
    \248\ Pennsylvania Commission Comments at 7-8.
---------------------------------------------------------------------------

i. Arguments Against the NOPR Proposal
    155. Commenters have not offered persuasive arguments for rejecting
the use of LMP for avoided cost energy rate determination. We disagree
with the argument made by Union of Concerned Scientists,\249\ NIPPC,
CREA, REC, and OSEIA,\250\ and Public Interest Organizations \251\ that
LMP should not be used as a measure of avoided energy costs because LMP
prices are depressed in many markets where self-scheduling rights and
state cost-recovery mechanisms for fuel and operating costs create the
opportunity for market participation at a loss. We recognize that, all
other things being equal, self-scheduling of resources may impact
market clearing prices. This potential price effect, however, does not
mean that the LMP is not an accurate measure of avoided energy costs.
The Commission's regulations, using language from PURPA section 210(d),
define avoided costs as ``the incremental costs to an electric utility
of electric energy or capacity or both which, but for the purchase from
the qualifying facility or qualifying facilities, such electric utility
would generate for itself or purchase from another source.'' \252\
---------------------------------------------------------------------------

    \249\ Union of Concerned Scientists Comments at 3-8.
    \250\ NIPPC, CREA, REC, and OSEIA Comments at 52.
    \251\ Public Interest Organizations Comments 52-64.
    \252\ 18 CFR 292.101(b)(6) (emphasis added).
---------------------------------------------------------------------------

    156. In organized wholesale electric market areas, the electric
utility purchases that would be displaced by QF purchases would, as
NRECA explains, in all likelihood be priced at the relevant LMP. These
LMPs are impacted by many factors, such as self-scheduling, generator
outages, and transmission outages, that may result in LMPs that are
lower or higher than they might otherwise have been. Thus, while self-
scheduling or other factors may impact LMPs, in any case, an electric
utility's purchases during periods when these price impacts are
occurring would be made at the resulting LMPs, whatever those LMPs may
be. Therefore, LMPs meet the Commission's long-standing definition of
avoided costs for a purchasing electric utility, even if they happen to
reflect price impacts from self-scheduling or other factors.
    157. Furthermore, while commenters discuss the possibility that
utility-owned coal-fired resources are self-scheduling only because
retail ratepayers are subsidizing such activities, even if such claims
were true they would not alter the above analysis. The LMPs that result
from a market that includes self-scheduled resources still represent
the price of purchases in the market that would be displaced by the QF
purchase.
    158. In addition, we reject the related request for clarification
made by Solar Energy Industries,\253\ i.e., that the flexibility to set
QF payments for as-available energy at the applicable LMP should
require an on-the-record determination that the purchasing utility
procures incremental energy from the identified LMP market at those
prices. Unless an aggrieved entity seeks to rebut this presumption in a
state avoided cost adjudication, rulemaking, legislative determination,
or other proceeding, that state would not need to make such an on-the-
record determination before it decides to use LMP.
---------------------------------------------------------------------------

    \253\ Solar Energy Industry Comments at 27-28.
---------------------------------------------------------------------------

    159. Entities may seek to rebut the presumption in particular
cases, as described earlier, and whether the utility actually procures
energy from the identified LMP market or from resources with prices
tied to the identified LMP may be a relevant factor in such rebuttal
arguments. Consistent with the reasons described above for why there
should be such a rebuttable presumption in favor of LMP, this
delineation of rights appropriately places the initial burden on
entities seeking to rebut the presumption, rather than on the states
who wish to rely on LMP for setting avoided cost rates for as-available
energy. The Commission could consider such issues if and when they may
arise in individual cases appropriately brought to the Commission,
including whether the state has adequately justified its use of that
rebuttable presumption.
    160. We reject the arguments made by NIPPC, CREA, REC, and OSEIA
that, more generally, prices for long-term QF contracts should be set
by reference to long-term price indices or other indicators that
genuinely reflect the long-term costs of generation avoided by the
purchasing utility.\254\ This final rule only addresses as-available
energy, and as-available energy prices by definition are short term, as
explained below in Section IV.B.7.c.
---------------------------------------------------------------------------

    \254\ NIPPC, CREA, REC, and OSEIA Comments at 53.
---------------------------------------------------------------------------

    161. We also reject the arguments made by NIPPC, CREA, REC, and
OSEIA that, while the NOPR is correct that LMPs are intended to promote
more efficient use of the transmission grid,

that is true only in the short term since factors such as temporary
outages, equipment failures, weather extremes, and the like can cause
LMPs to spike, but these have no impact on long-term transmission
availability. LMPs promote efficient use of the transmission grid in
the long term as well as the short term. Persistence of significant
price separation between different LMP nodes provides an indication of
the value of various possible transmission system upgrades and can show
transparently how system efficiencies may be improved by such
transmission system upgrades. Developers may have some incentive to
avoid congestion without LMPs, but LMPs provide an important price
signal as to how economic or uneconomic a particular production site
may be. In any event, the potential for more efficient use of the
transmission grid is merely an additional benefit of using LMP for
avoided energy cost determinations. Our adoption of LMP as a measure of
avoided energy costs in the RTO/ISO markets is based principally on the
fact that, in RTO/ISO markets, LMP accurately represents the purchasing
electric utility's avoided energy cost at the time the energy is
delivered, for the reasons described earlier.
    162. We also are not persuaded by arguments that, if transmission
constraints prevent a generator from delivering power to a specific
node, the LMP at that node cannot be an appropriate measure of costs
avoided by purchase of power from that generator. As discussed above,
an avoided cost rate should reflect not only the cost of energy that
was avoided by the purchasing electric utility, but also the cost to
deliver the QF energy to the purchasing electric utility's load, such
that the total cost avoided is reflected in the rate. In an RTO/ISO
market, a state appropriately is entitled to consider whether the cost
of delivery from the QF node to the load node (including any redispatch
costs necessary to facilitate such delivery over a system that is
otherwise constrained between those nodes) should be reflected in the
LMP at the QF supply node. In instances commenters refer to where
transmission constraints prevent a generator from delivering power to a
specific node, we disagree that such delivery is actually
``prevented.'' Rather, redispatch of system resources would be
necessary to facilitate the delivery, and the respective LMPs reflect
those redispatch costs.
    163. We also reject the argument made by NIPPC, CREA, REC, and
OSEIA that the 2000-01 California market demonstrated that volatile
short-term markets can reach extreme and unpredictable highs under
stress conditions.\255\ First we note that, in the wake of the 2000-
2001 California energy crisis, all RTO/ISO markets developed more
comprehensive ex ante market power mitigation measures than existed in
CAISO at that time, including offer caps and reference level
replacement offers, meant in part to moderate such extremes.\256\ In
any event, any price volatility that may currently exist in LMP
markets, regardless of the reason for the price volatility, and
regardless of whether the volatility causes LMPs to be lower or higher,
nevertheless accurately represents the avoided cost of the purchasing
electric utilities in those markets in those hours, as explained
elsewhere in this final rule.
---------------------------------------------------------------------------

    \255\ NIPPC, CREA, REC, and OSEIA Comments at 57. Curiously,
these commenters here essentially take the position that higher LMPs
and resulting higher avoided cost energy rates, which would normally
seem to be beneficial to QFs, are instead now anathema.
    \256\ See generally Wholesale Competition in Regions with
Organized Elec. Mkts., Order No. 719, 125 FERC ] 61,071 (2008),
order on reh'g, Order No. 719-A, 128 FERC ] 61,059, order on reh'g,
Order No. 719-B, 129 FERC ] 61,252 (2009).
---------------------------------------------------------------------------

    164. Finally, we remain convinced that Congress recognized that
RTO/ISO LMP pricing provides sufficient encouragement for QFs through
the enactment of PURPA section 210(m) with its directive that,
essentially, the mandatory purchase obligation can be lifted upon QFs
having non-discriminatory access to RTO/ISO markets. As noted earlier,
however, our decision to grant states the flexibility to rely on a
rebuttable presumption that RTO/ISO LMP pricing is an appropriate
measure of avoided energy costs (and thus set as-available energy rates
in reliance on LMPs) reflects our view that, in RTO/ISO markets, as a
general matter LMP indeed accurately represents the purchasing electric
utility's avoided energy costs.
    165. We also disagree with ELCON's \257\ argument that LMP should
not be used to measure avoided costs because that would allow states to
ignore long-standing factors established by the Commission that should
be used to determine avoided costs. The factors referenced by ELCON are
relevant to the traditional administrative determination of avoided
cost, and our revisions to the regulations preserve these factors for
that purpose and for avoided capacity costs. If a state chooses instead
to rely on LMP to set avoided energy cost rates, then it will
necessarily not be using those administrative means of determining
avoided costs, and these factors thus will not be relevant.
---------------------------------------------------------------------------

    \257\ ELCON Comments at 23-24.
---------------------------------------------------------------------------

    166. We are not persuaded by the arguments of various commenters
that LMP cannot be used for avoided cost rates because it ignores the
unique municipal infrastructure role and the multiple benefits of the
community of biogas facilities,\258\ including the value of renewable
baseload energy, greenhouse gas mitigation, landfill diversion,
reliable and resilient power and other benefits of small baseload
QFs.\259\ PURPA frames the determination of QF rates in terms of
avoided cost and does not authorize the Commission in determining QF
rates, particularly as-available energy rates, to consider non-energy-
related factors such as a generator's unique municipal infrastructure
role, greenhouse gas mitigation, and landfill diversion.
---------------------------------------------------------------------------

    \258\ Biogas Comments at 2.
    \259\ Covanta Comments at 8.
---------------------------------------------------------------------------

    167. We also are not persuaded by the argument of CA Cogeneration
that LMP may not represent a truly competitive price for electricity in
California since the majority of California supply is through bilateral
contracts, not through competitive bidding in the market, and that
other factors also distort LMP such as roof top solar. CA Cogeneration,
in essence, objects to the state of California's decision to award
preferred resource status to some resources, such as solar and wind,
and not others, such as cogeneration. These are procurement decisions
made at the state level in connection with resource planning and retail
ratemaking. Even if those decisions impact the resulting LMPs, as CA
Cogeneration claims, that impact would not invalidate the arguments
made above for why LMP is presumptively an appropriate measure of as-
available energy avoided costs in RTO/ISO markets. The aggrieved entity
would be able to challenge the state's decision to rely on LMP in the
appropriate forum, which could include any one or more of the
following: (1) Initiating or participating in proceedings before the
relevant state commission or governing body; (2) filing for judicial
review of any state regulatory proceeding in state court (under PURPA
section 210(g)); or, alternatively (3) filing a petition for
enforcement against the state at the Commission and, if the Commission
declines to act, later filing a petition against the state in U.S.
district court (under PURPA section 210(h)(2)(B)).\260\
---------------------------------------------------------------------------

    \260\ See Policy Statement Regarding the Commission's
Enforcement Role Under Section 210 of the Public Utility Regulatory
Policies Act of 1978, 23 FERC ] 61,304.

---------------------------------------------------------------------------

    168. We reject the argument made by New England Small Hydro that
the Commission has not supported its view that LMP is an accurate
measure of avoided costs since LMP ignores the costs that the utility
pays to procure power, including through competitive solicitations,
other power contracts, planned retirements and other factors that are
considered in a utility's long-term plans; and ignores the fact that
LMP and the default service rates that exist in ISO-NE-based states are
quite different.\261\ The costs that a purchasing utility pays to
procure power, including through competitive solicitations, other power
contracts, planned retirements and other factors that are considered in
a utility's long-term plans may be relevant to the utility's purchase
of capacity using long-term contracts, but not to the determination of
the proper as-available energy avoided cost rate to be paid to QFs,
which rates will necessarily vary as system conditions vary over time,
as reflected by variances in LMP over time. The fact that LMP and the
default service rates that exist in ISO-NE-based states may diverge is
to be expected because the latter, unlike the as-available energy rates
charged by QFs in RTO/ISO markets that LMP is being used to price,
normally include transmission and distribution costs (and possibly firm
supplier capacity costs) necessary to ensure that firm supply is
continually available to residential customers.\262\ While utilities or
state regulatory authorities continue to have the authority to
establish and maintain long-term avoided energy forecasts upon which QF
PURPA power purchase rates may be based, and to recognize the actual
future energy costs incorporated in new power contracts that are being
signed by New England utilities, elsewhere in this final rule the
Commission explains why the use of variable prices can be appropriate
for long-term energy contracts.
---------------------------------------------------------------------------

    \261\ New England Small Hydro Comments at 8-10.
    \262\ Compare ISO-NE, Transmission, Markets, and Services
Tariff, LMPs and Real-Time Reserve Clearing Prices Calculation,
Sec.  III.2.5 (describing how nodal real-time prices are calculated
in ISO-NE at each node using energy offers and bids, transmission
constraints, and other factors) with National Grid, Investigation as
to the Propriety of Proposed Tariff Changes, Docket No. DPU 18-150,
Exh. NG-HSG-1, Gorman Test. 3:18-4:6 (Nov. 15, 2018), https://fileservice.eea.comacloud.net/FileService.Api/file/FileRoom/10043215
(``The Company's filing is based on its investments and costs
incurred to provide distribution service to its customers. An
[Allocated Cost of Service Study] directly assigns or allocates each
element of the revenue requirement, including plant and other
investments, operating expenses, depreciation and taxes, among the
rate classes, in order to determine the costs of providing service
to each rate class. Each element of the total revenue requirement is
analyzed and assigned to or allocated among the rate classes, so the
utility can establish rates that, subject to assumptions such as
kilowatt-hour (`kWh') delivery volumes and the number of customers,
provide it with a fair opportunity to recover its costs and to earn
an appropriate return.'').
---------------------------------------------------------------------------

    169. We are not persuaded by the argument of Southeast Public
Interest Organizations that the NOPR does not establish a framework for
just and reasonable and nondiscriminatory rates because the proposed
avoided cost methodology does not take into account any long-term or
seasonal purchases made from third parties or affiliates, adjustments
for transmission and distribution losses, capacity deferrals, avoided
environmental compliance costs, or dispatchability of the QF.\263\ LMP
pricing, in fact, does reflect transmission and distribution losses.
The other factors that the Southeast Public Interest Organizations
mention here, such as environmental compliance costs, dispatchability,
long-term or seasonal purchases and capacity deferrals, are factors
that are more applicable to the pricing of capacity and long-term
contracts, not the pricing of as-available energy, which is what the
Commission's NOPR proposal as adopted in this final rule addresses.
---------------------------------------------------------------------------

    \263\ Southeast Public Interest Organizations Comments at 22.
---------------------------------------------------------------------------

    170. The Commission rejects the argument made by Biological
Diversity \264\ that LMP pricing ignores the variability of conditions
across the country. LMP prices by definition vary as supply, demand,
and system conditions change across the country. In any event, the
Commission agrees that LMP pricing would not currently be applicable in
regions like the Southeast that lack RTOs and ISOs and thus that do not
use LMP.
---------------------------------------------------------------------------

    \264\ Biological Diversity Comments at 8-9.
---------------------------------------------------------------------------

    171. We further reject the argument made by ENGIE that allowing
states to set energy rates using LMPs combined with the ability to set
capacity rates at zero if it is determined that a utility has no need
for capacity has the potential to allow traditional utilities to corner
the market on capacity, leaving smaller independent QFs to provide only
energy-only service.\265\ PURPA does not direct the Commission to
guarantee that QF sales make up some specified share of utilities'
capacity needs nor does it require that each QF receive compensation
for providing capacity. PURPA instead focuses on the purchasing
electric utility's avoided costs and provides that the Commission
cannot require that prices charged by a QF exceed the purchasing
electric utility's avoided cost, if a purchasing electric utility has
no need for additional capacity (and thus the purchasing utility's
avoided cost for capacity would be zero),\266\ the only service that
QFs (and other suppliers) would need to provide that utility is energy.
However, a utility's ability to ``corner the market'' on capacity
depends not uniquely on the pricing of QF sales to the utility, but on
a host of factors including the utility's analysis of its need for
capacity and, without a specific inquiry into the circumstances of each
utility, it cannot be concluded that any utility's decision will always
be deficient or that it has been adversely and inappropriately affected
by the Commission's action here.
---------------------------------------------------------------------------

    \265\ ENGIE Comments at 4.
    \266\ See, e.g., NOPR, 168 FERC ] 61,184 at P 33 n.58; see also
City of Ketchikan, Alaska, 94 FERC ] 61,293 at 62,061 (2001)
(``[A]voided cost rates need not include the cost for capacity in
the event that the utility's demand (or need) for capacity is zero.
That is, when the demand for capacity is zero, the cost for capacity
may also be zero.'').
---------------------------------------------------------------------------

    172. Several commenters maintain that reliance on LMP will make it
difficult for QFs to obtain financing.\267\ This argument is addressed
below in section IV.B.7 of this final rule.
---------------------------------------------------------------------------

    \267\ Biogas Comments at 2; BluEarth Renewables Comments at 2;
Biological Diversity at 8; Covanta Comments at 9; Distributed Sun
Comments at 1-2; New England Small Hydro Comments at 10; NIPPC,
CREA, REC, and OSEIA Comments at 53.
---------------------------------------------------------------------------

ii. Requests for Modification or Clarification of the NOPR
    173. We will not provide the clarifications requested by New
England Small Hydro that the Commission require the use of the day-
ahead LMP for QF rates set at LMP, or Southeast Public Interest
Organizations' request to require the use of real-time LMP rather than
average LMP. States that choose to use LMP will determine the LMP most
representative of the avoided cost of the relevant purchasing utility.
    174. While the Kentucky Commission requests that the Commission
allow the use of the LMP at a delivery (load) node rather than a
receipt (generator or QF) node, we find that this decision should be
made by the state as it determines which particular LMP best reflects
the avoided cost of the purchasing electric utility.
    175. We grant APPA's request for clarification that, while the NOPR
provides greater clarity as to states' entitlement to rely on
competitively-set prices as a measure of avoided cost rates, nothing in
the final rule is intended to call into question any particular state's
existing implementation of PURPA's avoided cost requirements, such as
their existing use of LMP.\268\ While in the past a state

may have been able to conclude that LMP was an appropriate measure of
the avoided cost for energy, a state can now also rely on a rebuttable
presumption that LMP is an appropriate measure of the as-available
avoided cost for energy to be used in determining a QF's as-available
avoided cost energy rate.
---------------------------------------------------------------------------

    \268\ APPA Comments at 9.
---------------------------------------------------------------------------

    176. We provide the following clarification in response to the
Solar Energy Industries' request that the Commission make clear that
payments based on LMP do not relieve the purchasing utility of the
requirement to compensate the QF for any values in addition to
electricity (e.g., RECs, etc.), and that the state's flexibility to
allow utilities to set QF payment rates for as-available energy at the
applicable LMP does not in any way limit QFs' rights to establish a LEO
or contract for a longer-term sale at fixed, full avoided costs.\269\
In Windham Solar LLC,\270\ the Commission summarized its precedent
concerning RECs. The Commission stated that the states have the
authority to determine who owns RECs in the initial instance and how
they are transferred, and that the automatic transfer of RECs within a
sale of power at wholesale must find its authority in state law, not
PURPA. But the Commission also held that a state may not assign
ownership of RECs to utilities based on a logic that the avoided cost
rates in PURPA contracts already compensate QFs for RECs in addition to
compensating QFs for energy and capacity, because under PURPA the
avoided cost rates are, in fact, compensation just for energy and
capacity.\271\ We see no reason to disturb that precedent in this final
rule. With regard to the right of QFs to establish a LEO, that right is
neither limited nor expanded by a state's choice of LMP as the measure
of avoided costs for energy.
---------------------------------------------------------------------------

    \269\ Solar Energy Industry Comments at 27-28.
    \270\ 156 FERC ] 61,042 (2016).
    \271\ Id. P 4.
---------------------------------------------------------------------------

iii. Western EIM
    177. We hereby find that the Western EIM prices, like other LMP
prices, may presumptively be used as a measure of as-available energy
avoided costs for utilities able to participate in the Western EIM
market. As Xcel points out, ``prices in the EIM are calculated using
the same methodology as LMPs'' since, ``in both cases, units are
dispatched on a least-cost basis that respects applicable transmission
constraints (i.e., congestion),'' and ``[t]he formula for price
calculation involves determination of the system marginal energy cost,
which is the cost of providing the next increment of energy to the
system, minus congestion costs, minus losses, and, in some cases, minus
the cost of carbon.'' \272\ As with LMP, these Western EIM price
components presumptively reflect the avoided cost of as-available
energy incurred by purchasing electric utilities that are able to
participate in the Western EIM region.
---------------------------------------------------------------------------

    \272\ Xcel Comments at 7-8.
---------------------------------------------------------------------------

    178. We reject arguments that Western EIM prices should not be used
to establish as-available avoided cost energy rates for sales by QFs.
With respect to the unit commitment and dispatch scheduling cost
parameters ELCON refers to, it is true that the Western EIM is a real-
time imbalance market built on a decentralized unit commitment that may
not result in exactly the same real-time dispatch and LMP as would
result from an RTO market with centralized day-ahead unit commitment
and co-optimized energy and reserves. Nonetheless, Western EIM prices
represent quite precisely the avoided cost of as-available energy for
utilities operating in that market structure since those prices show
the cost of obtaining an additional unit of energy at any particular
place and time. With regard to the argument of Union of Concerned
Scientists concerning the cost recovery mechanisms available to
utility-owned and -affiliated generation,\273\ as discussed above with
respect to the rebuttable presumption that LMP may be used for avoided
cost rate determination, we do not find these unproven allegations of
use of retail cost recovery mechanisms to subsidize wholesale RTO/ISO
market participation at a loss sufficient to make a blanket finding
prohibiting the use of Western EIM prices to set as-available avoided
cost energy rates for sales by QFs.
---------------------------------------------------------------------------

    \273\ Union of Concerned Scientists Comments at 9.
---------------------------------------------------------------------------

    179. With regard to the argument concerning the ability to
participate in the Western EIM raised by Solar Energy Industries,\274\
for PURPA rate purposes, it is not relevant whether QFs are able to
participate in the Western EIM. The rates at issue here are intended,
per the statute, to reflect the costs of alternative electric energy
that the purchasing utility is avoiding. In this context, all that
matters is whether the Western EIM's prices accurately reflect a
purchasing electric utility's avoided costs for energy. Thus, as long
as the purchasing electric utility is able to participate in the
Western EIM, a rebuttable presumption should apply that Western EIM
prices reflect the purchasing electric utility's avoided costs for
energy.
---------------------------------------------------------------------------

    \274\ Solar Energy Industry Comments at 27.
---------------------------------------------------------------------------

4. Use of Market Hub Prices as a Permissible Rate for Certain As-
Available QF Energy Sales
a. NOPR Proposal
    180. In the NOPR, the Commission recognized that competitive
bilateral energy markets have arisen outside of the RTO/ISO energy
markets. Particularly in the Western United States, price hubs such as
the Mid-Columbia (Mid-C) and Palo Verde hubs are liquid markets with
prices the Commission has recognized as representing competitive market
prices at those hubs.\275\ For the same reasons that LMPs could
represent an appropriate avoided cost energy rate for QFs selling to
electric utilities located in RTO/ISO markets, the Commission proposed
to find that liquid market hubs can represent appropriate rates for QFs
selling to electric utilities located outside of RTO/ISO markets. Like
LMP, liquid market hubs would rely on competition to derive an avoided
cost. From a price determination perspective, liquid market hub prices
differ from LMP mainly in that they measure price at only one or a few
points, whereas RTOs/ISOs derive unique LMPs for all receipt and
delivery points on a specific area of the system.\276\
---------------------------------------------------------------------------

    \275\ NOPR, 168 FERC ] 61,184 at P 52 (citing Price Discovery in
Nat. Gas and Elec. Mkts., 109 FERC ] 61,184, at P 66 (2004)
(approving the use of published prices at market hubs with
sufficient liquidity to set prices charged in tariffs); El Paso
Elec. Co., 148 FERC ] 61,051, at P 7 (2014) (approving the use of
the Palo Verde price to set imbalance charges); Idaho Power Co., 121
FERC ] 61,181 at P 27 (2007) (approving use of Mid-Columbia prices
to set energy imbalance charge); PacifiCorp, 95 FERC ] 61,467, at
62,676 (2001) (approving setting energy imbalance rate at average of
four market hub prices); Pinnacle West Energy Corp., 92 FERC ]
61,248, at 61,791 (2000) (accepting the use of the Palo Verde price
to set prices for affiliate transactions because the Palo Verde
Index is a recognized market hub with competitive prices)).
    \276\ NOPR, 168 FERC ] 61,184 at P 53.
---------------------------------------------------------------------------

    181. Consequently, the Commission proposed in the NOPR to revise
the PURPA Regulations in 18 CFR 292.304 to add a subsection (b)(7)
which, in combination with new subsection (e)(1), would permit a state
to set the as-available energy rate paid to a QF by electric utilities
located outside of RTO/ISO markets at energy rates established at
liquid market hubs. The Commission proposed to define Market Hub Prices
as prices determined at a liquid market hub to which the purchasing
electric utility has reasonable access. States electing to set QF
energy rates using a Market Hub Price also would identify the
particular market hub used to set the

price. Such determination would require the state to find that the
prices at such hub are competitive prices that reflect the costs an
electric utility would avoid but for the purchase from the QF.\277\
---------------------------------------------------------------------------

    \277\ Id. P 56.
---------------------------------------------------------------------------

b. Comments
i. Comments in Support
    182. Arizona Public Service and El Paso Electric state that the
Palo Verde/Hassayampa hub represents a regional liquid market hub that
could be used to set as-available energy avoided costs.\278\ Portland
General likewise asserts that the Mid-C price hub should be approved as
appropriate for use in establishing as-available energy avoided
costs.\279\
---------------------------------------------------------------------------

    \278\ Arizona Public Service Comments at 6-8; El Paso Electric
Comments at 2-3.
    \279\ Portland General Comments at 6-7.
---------------------------------------------------------------------------

    183. Xcel provides two additional factors to support the liquid
market hub proposal. First, Xcel cites to the 2018 State of the Market
report issued by the Commission's Office of Enforcement's Division of
Energy Market Oversight, which states that trading hub prices generally
align with energy prices associated with competitive, market-based
sales. Second, Xcel cites to wholesale power sales contracts providing
for the purchase of excess energy based on a combination of day-ahead
prices at Palo Verde and at Four Corners, which Xcel asserts
demonstrates that prices at Palo Verde and Four Corners are reasonably
representative of the value of energy.\280\
---------------------------------------------------------------------------

    \280\ Xcel Comments at 8.
---------------------------------------------------------------------------

ii. Comments in Opposition
    184. Several commenters argue that liquid market hubs are short-
term spot markets and do not represent long-term energy rates or the
other costs associated with that energy including, but not limited to,
congestion, transmission, and capacity costs.\281\ Other commenters
express concern with setting QF prices at short-term liquid hub prices
while allowing utilities to rate base and recover their long-term
investments.\282\
---------------------------------------------------------------------------

    \281\ IdaHydro Comments at 11; Southeast Public Interest
Organizations Comments at 19.
    \282\ IdaHydro Comments at 11; Industrial Energy Consumers
Comments at 12-13.
---------------------------------------------------------------------------

    185. Public Interest Organizations assert that the liquid market
hub proposal is discriminatory because non-QF generators are not
limited to the liquid market hub price and utilities can, and regularly
do, pay effective prices for energy that exceed the price determined by
regional trading.\283\ Union of Concerned Scientists similarly asserts
that liquid market hub prices are distorted by the participation of
integrated utilities that submit bids below their total costs.\284\
---------------------------------------------------------------------------

    \283\ Public Interest Organizations Comments at 64.
    \284\ Union of Concerned Scientists Comments at 8.
---------------------------------------------------------------------------

    186. Industrial Energy Consumers oppose the liquid market hub
pricing proposal because such markets are not sufficiently competitive,
nondiscriminatory, and transparent to be used as the basis for
calculating a utility's avoided cost payment.\285\ Industrial Energy
Consumers urge the Commission not to assume that non-competitive
markets are, in fact, competitive.\286\ Southeast Public Interest
Organizations state that no southeast state could credibly identify a
particular market hub that is reasonably accessible and has competitive
prices that actually relate to the costs an electric utility would
avoid but for the purchase from the QF.\287\ Southeast Public Interest
Organizations also assert that the liquid market hub proposal does not
require states to determine whether liquid market hub prices represent
a utility's avoided costs, and therefore the proposal would allow
liquid market hubs to set avoided energy prices even when they do not
represent avoided energy costs.\288\
---------------------------------------------------------------------------

    \285\ Industrial Energy Consumers Comments at 12.
    \286\ Id.
    \287\ Southeast Public Interest Organizations Comments at 18.
    \288\ Id. at 19.
---------------------------------------------------------------------------

    187. ELCON asserts that a liquid regional hub does not necessarily
imply liquidity at a more granular level.\289\ According to ELCON, the
basis spread resulting from transmission congestion outside of RTO/ISOs
is often opaque in real time and poorly documented in hindsight, and
this is a clear indication that discriminatory treatment and barriers
to the bulk transmission system persist under current conditions
outside of RTO/ISOs.\290\ ELCON states that for these and other
reasons, bilateral markets alone are insufficient to serve as complete
avoided cost measures.\291\
---------------------------------------------------------------------------

    \289\ ELCON Comments at 25.
    \290\ Id.
    \291\ Id.
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    188. Allco states that prices at liquid market hubs would suffer
from shortcomings with respect to small QFs connected to the
distribution system, because purchases from such QFs also allow the
purchasing utility to avoid transmission costs, including line
losses.\292\
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    \292\ Allco Comments at 7-8.
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iii. Commission Determination
    189. We adopt the proposal in the NOPR to give the states
flexibility to set as-available avoided cost energy rates using prices
from a liquid market hub to which the purchasing electric utility has
reasonable access. For the reasons explained in the NOPR, we find that
liquid market hubs can represent appropriate as-available avoided cost
energy rates for QFs selling to electric utilities located outside of
RTO/ISO markets. However, as the Commission also found in the NOPR,
before relying on prices from liquid market hubs, a state must find
that the liquid market hub price in question represents the purchasing
utility's avoided cost for as-available energy.\293\
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    \293\ See NOPR, 168 FERC ] 61,184 at PP 53, 56.
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    190. Examples of factors a state reasonably could consider in
making this determination (in addition to the core finding that the
liquid market hub represents the purchasing utility's avoided cost for
as-available energy) are: (1) Whether the hub is sufficiently liquid
that prices at the hub represent a competitive price; \294\ (2) whether
the prices developed at the hub are sufficiently transparent; (3)
whether the electric utility has the ability to deliver power from such
hub to its load, even if its load is not directly connected to the hub;
and (4) whether the hub represents an appropriate market to derive an
energy price for the electric utility's purchases from the relevant QFs
given the electric utility's physical proximity to the hub. These
factors are not intended to be exhaustive, and states reasonably could
consider other factors in identifying a relevant liquid market hub for
setting as-available QF energy rates.
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    \294\ In considering whether a hub is sufficiently liquid,
states could, for example, consider such factors as those identified
by the Commission in Price Discovery in Nat. Gas and Elec. Mkts.,
109 FERC ] 61,184, at P 66.
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    191. In order for prices at market hubs to represent a purchasing
electric utility's avoided costs, the market hub price may need to be
subject to adjustments to account for transmission costs the electric
utility would incur before such prices could serve as a factor in
determining appropriate QF rates.\295\ In addition, market prices in a
region may be determined based on a formula that includes adjustments
to the market hub price or that incorporates prices at more than one
market hub located in the region, when such prices represent standard
pricing practice in the region where the purchasing electric utility is
located.\296\ Such adjustments may be necessary to ensure that the

competitive market price reflects a purchasing utility's actual avoided
costs for as-available energy.
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    \295\ Other adjustments also may be necessary in other
situations in order for the adjusted hub price to reasonably reflect
the purchasing electric utility's avoided cost.
    \296\ NOPR, 168 FERC ] 61,184 at P 58.
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    192. Arguments regarding the short-term nature of liquid market
hubs and claims that use of such prices is discriminatory are addressed
in Section IV.B.2 above.
    193. We will not address in this final rule arguments about whether
particular market hubs should be found to represent avoided costs or,
to the contrary, that particular market hubs may be too illiquid or
insufficiently granular, or that prices at particular market hubs may
not reflect avoided costs. We are not making any determination in this
final rule that the prices at any specific market hub do or do not
represent the avoided costs of any specific utility. Rather, we are
allowing the states the flexibility to rely on prices at liquid market
hubs to set as-available avoided cost energy rates for QF sales in
regions outside RTO/ISO markets upon a state finding that it is
appropriate to do so given the specific circumstances governing a
particular market hub and the purchasing utility involved. The
aggrieved entity would be able to challenge the state's decision to use
a liquid market hub price in the appropriate forum, which could include
any one or more of the following: (1) Initiating or participating in
proceedings before the relevant state commission or governing body; (2)
filing for judicial review of any state regulatory proceeding in state
court (under PURPA section 210(g)); or, alternatively (3) filing a
petition for enforcement against the state at the Commission and, if
the Commission declines to act, later filing a petition against the
state in U.S. district court (under PURPA section 210(h)(2)(B)).\297\
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    \297\ See Policy Statement Regarding the Commission's
Enforcement Role Under Section 210 of the Public Utility Regulatory
Policies Act of 1978, 23 FERC ] 61,304.
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    194. With respect to Southeast Public Interest Organizations'
assertion that the liquid market hub proposal in the NOPR does not
require states to determine whether liquid market hub prices represent
a utility's avoided costs, the Commission intended to impose such a
requirement as a prerequisite before a liquid market hub may be relied
on as a measure of a purchasing utility's avoided cost of as-available
energy. However, we acknowledge that the regulatory text in the NOPR
was ambiguous in that regard. Therefore, the regulatory text of 18 CFR
292.304(b)(7)(i) in the final rule has been revised to make this more
clear.
c. Proposed Modifications
i. Comments
    195. APPA requests that the Commission clarify that, in addition to
liquid market hubs, as-available energy avoided costs could be
determined based on prices of comparable competitive quality.\298\ APPA
states that amending the proposed regulation in this fashion would also
enable utilities proximate to (or embedded within) RTO/ISO markets to
reference prices in those markets as viable alternatives in
establishing avoided costs.\299\
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    \298\ APPA Comments at 13.
    \299\ Id. at 13.
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    196. The California Commission requests that the Commission clarify
that states previously were permitted to use liquid market hub prices
under the current PURPA Regulations and that the proposed revisions
simply codify and confirm the validity of this past practice.\300\ The
California Commission and Massachusetts DPU further request that the
proposed rules be modified to permit states to use competitive prices
to set both energy and capacity costs, and to not be limited to using
such mechanisms only for as-available energy prices.\301\
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    \300\ California Commission Comments at 24.
    \301\ California Comments at 25; Massachusetts DPU Comments at
8-10.
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    197. EEI notes that some states may be located in regions with
access to more than one market hub and those states should have the
flexibility to use an average of market hub prices or develop a formula
correlated to the appropriate market hubs to develop the electric
utility's avoided cost.\302\ EEI notes that this proposal is not new,
but its inclusion in the Commission's regulations will provide
certainty to states.\303\
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    \302\ EEI Comments at 26.
    \303\ Id. at 27.
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    198. NIPPC, CREA, REC, and OSEIA assert that the liquid market hub
proposal should not be adopted without making significant changes.\304\
For example, they argue, only long-term contract prices reported at
market hubs should be used.\305\ Even with respect to market-hub prices
for long-term contracts, they assert that the Commission should include
safeguards to ensure that prices are set based on liquid trading with a
sufficient number of competitors to assure effective price discovery,
that prices are not subject to manipulation, and that reported price
indices are accurate and not subject to mis-reporting or other forms of
manipulation.\306\ Finally, they argue that the Commission should
require avoided costs to include the costs of transmission to and from
such hubs except in cases where the utility's system directly
interconnects with that hub.\307\ Resources for the Future makes
similar arguments.\308\
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    \304\ NIPPC, CREA, REC, and OSEIA Comments at 60.
    \305\ Id.
    \306\ Id.
    \307\ Id.
    \308\ Resources for the Future Comments at 8.
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    199. In contrast, NorthWestern asserts that liquid market hub
prices should be adjusted downward by a transmission differential to
reflect the cost of getting energy from the market to load.\309\
NorthWestern states that reliance on the market hub to establish
avoided costs only remains a valid option if the prices are less than
what it would cost a utility to build a resource to supply its
customers' needs.\310\
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    \309\ NorthWestern Comments at 5.
    \310\ Id.
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ii. Commission Determination
    200. We clarify that, in adopting a rule allowing states to use
liquid market hubs to determine as-available avoided energy costs, we
are not finding that the use of liquid market hubs for this purpose
prior to the issuance of this final rule was not permitted. Depending
on the specific circumstances, a state may appropriately have
determined, prior to the final rule, that a liquid market hub price
represented a purchasing utility's as-available avoided energy cost.
After the effective date of this final rule, an aggrieved entity may
seek review of a state's determination to use liquid market hubs in the
appropriate forum.\311\
---------------------------------------------------------------------------

    \311\ See Policy Statement Regarding the Commission's
Enforcement Role Under Section 210 of the Public Utility Regulatory
Policies Act of 1978, 23 FERC ] 61,304.
---------------------------------------------------------------------------

    201. We confirm that: (1) States located in regions with access to
more than one market hub have the flexibility to use an appropriate
average of market hub prices or to develop an appropriate formula that
relies on data from relevant market hubs to develop an electric
utility's as-available avoided energy cost, so long as doing so yields
a price that accurately reflects the purchasing electric utility's as-
available avoided energy cost; \312\ (2) states must determine that a
liquid market hub is sufficiently liquid that its prices represent a
competitive price; \313\ and (3) the market hub price may need to be
subject to adjustments to account for transmission costs the electric
utility would incur.\314\
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    \312\ NOPR, 168 FERC ] 61,184 at P 58.
    \313\ Id. P 57.
    \314\ Id. P 58.

---------------------------------------------------------------------------

    202. Finally, we find that the general ruling requested by APPA
regarding the use of ``prices of comparable competitive quality'' to
set as-available avoided cost rates is beyond the scope of this
rulemaking in that here we were proposing only particular discrete
changes to our regulations for setting as-available avoided cost energy
rates charged by QFs.
5. Use of Formulas Based on Natural Gas Prices To Establish a
Permissible Rate for Certain As-Available QF Energy Sales
a. NOPR Proposal
    203. The Commission observed in the NOPR that, in regions where
there are no RTOs/ISO or liquid market hubs, the price of electricity
generated by efficient combined-cycle natural gas generation facilities
would appear to represent a reasonable measure of a competitive energy
price.\315\
---------------------------------------------------------------------------

    \315\ Id. P 59.
---------------------------------------------------------------------------

    204. The Commission therefore proposed to revise the PURPA
Regulations in 18 CFR 292.304 to add a subsection (b)(7) which, in
combination with new subsection (e)(1), would permit a state to set the
as-available energy rate paid to a QF by electric utilities located
outside of RTO/ISO markets at Combined Cycle Prices, defined as a
formula rate established by the state using published natural gas price
indices and a proxy heat rate for an efficient natural gas combined-
cycle generating facility. The state would need to determine that the
resulting Combined Cycle Price represents an appropriate approximation
of the purchasing electric utility's avoided costs. This determination
would involve consideration of such factors as, for example: (1)
Whether the cost of energy from an efficient natural gas combined-cycle
generating facility represents a reasonable approximation of a
competitive price in the purchasing electric utility's region; (2)
whether natural gas priced in accordance with a particular proposed
natural gas price index would be available in the relevant market; (3)
whether there should be an adjustment to the natural gas price to
appropriately reflect the cost of transporting natural gas to the
relevant market; and (4) whether the proxy heat rate used in the
formula should be updated regularly to reflect improvements in
generation technology. The Commission described the above factors as
not exhaustive and proposed providing states the flexibility to apply
other factors that also might be appropriate for consideration.\316\
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    \316\ Id.
---------------------------------------------------------------------------

    205. The Commission stated that natural gas price indices coupled
with the heat rate of an efficient natural gas combined-cycle
generating facility may be a reasonably accurate measure of avoided
cost, at least in those markets where natural gas-fired resources are
commonly the marginal units. In such markets, the Commission stated
that it would expect that new supplies of energy would need to be
offered at a price equal to or less than the incremental cost of using
these efficient gas units in order to displace them economically. Thus,
the Commission found preliminarily that using natural gas price indices
and the heat rate of an efficient combined-cycle natural gas generating
facility to establish an avoided cost energy rate relies on competitive
market forces, in this case competitive forces in natural gas markets
for the fuel used by natural gas combined-cycle generating facilities
that the purchasing electric utility, but for the purchase from the QF,
would generate itself or purchase from another source.\317\
---------------------------------------------------------------------------

    \317\ Id. P 54.
---------------------------------------------------------------------------

b. Comments
    206. Several entities oppose the NOPR's Combined Cycle Prices
proposal.\318\ Allco asserts that this is exactly the type of
administrative avoided cost determination about which NARUC and
utilities have complained.\319\ Allco also argues that the only reason
for including the Combined Cycle Prices proposal in the Commission's
regulations is to create a menu of prices from which a state commission
or unregulated utility can choose the lowest price, which Allco claims
would not encourage QF generation, and would be inconsistent with the
rules of economic dispatch and the language of PURPA.\320\ Public
Interest Organizations argue that the Combined Cycle Price proposal is
discriminatory to QFs for all the same reasons that restricting QF
rates to LMP is discriminatory (i.e., because utilities can, and
allegedly do, pay effective prices for energy that exceed the
calculation from natural gas prices and assumed combined cycle heat
rates).\321\ Southeast Public Interest Organizations argue that the
Combined Cycle Prices proposal does not require states to include
variable O&M costs in the proxy combined cycle plant or an adjustment
for natural gas transportation, even though a utility-owned combined
cycle gas plant would be allowed to recover both types of costs.\322\
---------------------------------------------------------------------------

    \318\ Allco Comments at 8; BluEarth Comments at 1-2; ELCON
Comments at 25-26; Industrial Energy Consumers Comments at 10-11;
Public Interest Organizations Comments at 64; R Street Comments at
5; Southeast Public Interest Organizations Comments at 19-20.
    \319\ Allco Comments at 8.
    \320\ Id.
    \321\ Public Interest Organizations Comments at 64.
    \322\ Southeast Public Interest Organizations Comments at 19-20.
---------------------------------------------------------------------------

    207. In contrast, R Street opposes the proposal because using
natural gas combined cycle plants as the basis for QF rates in non-RTO/
ISO regions could lead to the overpayment of a QF. R Street argues that
regions without organized wholesale markets should instead price QF
rates at the lowest cost resource based on an administratively
determined avoidable cost.\323\
---------------------------------------------------------------------------

    \323\ R Street Comments at 5.
---------------------------------------------------------------------------

    208. Similarly, ELCON argues that the proposal is complicated by
the fact that natural gas units are not always marginal, especially in
export-constrained subregions when renewables output is high. ELCON
believes this proposal would be subject to extensive forecasting error,
and therefore argues that careful assessment should precede its
adoption.\324\
---------------------------------------------------------------------------

    \324\ ELCON Comments at 26.
---------------------------------------------------------------------------

    209. Other entities support the NOPR's Combined Cycle Price
proposal.\325\ The California Commission and EEI argue that states
already had this flexibility under the current regulations, and request
that the Commission acknowledge this fact in a final rule.\326\
Similarly, other supporters of the Combined Cycle Price proposal argue
that states should have the ability to develop as-available energy
price formulas based on technologies other than combine cycle gas
plants, if doing so would more accurately reflect the relevant
purchasing utility's avoided cost.\327\