[Federal Register Volume 84, Number 193 (Friday, October 4, 2019)]
[Proposed Rules]
[Pages 53246-53275]
[FR Doc No: 2019-20803]

Vol. 84

Friday,

No. 193

October 4, 2019

Part II

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Parts 292 and 375

 Qualifying Facility Rates and Requirements; Implementation Issues
Under the Public Utility Regulatory Policies Act of 1978; Proposed Rule

Federal Register / Vol. 84 , No. 193 / Friday, October 4, 2019 /
Proposed Rules

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Parts 292 and 375

[Docket Nos. RM19-15-000 and AD16-16-000]

Qualifying Facility Rates and Requirements; Implementation Issues
Under the Public Utility Regulatory Policies Act of 1978

AGENCY: Federal Energy Regulatory Commission, Department of Energy.

ACTION: Notice of proposed rulemaking.

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SUMMARY: In this notice of proposed rulemaking, the Federal Energy
Regulatory Commission proposes to revise its regulations implementing
sections 201 and 210 of the Public Utility Regulatory Policies Act of
1978 in light of changes in the energy industry since 1978.

DATES: Comments are due December 3, 2019.

ADDRESSES: Comments, identified by docket number, may be filed
electronically at http://www.ferc.gov in acceptable native applications
and print-to-PDF, but not in scanned or picture format. For those
unable to file electronically, comments may be filed by mail or hand-
delivery to: Federal Energy Regulatory Commission, Secretary of the
Commission, 888 First Street NE, Washington, DC 20426. The Comment
Procedures Section of this document contains more detailed filing
procedures.

FOR FURTHER INFORMATION CONTACT:
    Lawrence R. Greenfield (Legal Information), Office of the General
Counsel, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426,<PHONE_NUMBER><EMAIL_ADDRESS>    Helen Shepherd (Technical Information), Office of Energy Market
Regulation, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426,<PHONE_NUMBER><EMAIL_ADDRESS>    Thomas Dautel (Technical Information), Office of Energy Policy and
Innovation, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426,<PHONE_NUMBER><EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

Table of Contents

                                                               Paragraph
                                                                 Nos.

I. Background...............................................          15
    A. Circumstances Underlying the Passage of PURPA in 1978          15
     and the Commission's Promulgation of Its PURPA
     Regulations in 1980....................................
    B. Changes in Circumstances Subsequent to the                     19
     Commission's Promulgation of Its PURPA Regulations in
     1980...................................................
    C. Need for Revisions to the Commission's PURPA                   28
     Regulations in Light of Changed Circumstances..........
II. Discussion..............................................          32
    A. QF Rates.............................................          32
        1. Background.......................................          36
        2. LMP as a Permissible Rate for Certain As-                  43
         Available QF Energy Sales..........................
        3. Use of Other Competitive Prices as a Permissible           51
         Rate for Certain As-Available QF Energy Sales......
            a. Background...................................          52
            b. Commission Proposal..........................          55
                i. Market Hub Prices........................          56
                ii. Combined Cycle Prices...................          59
                iii. Other Approaches to Competitive Pricing          60
                 for Certain As-Available QF Energy Sales...
        4. Permitting the Energy Rate Component of a                  61
         Contract To Be Fixed at the Time of the LEO Using
         Forecasted Values of the Estimated Stream of Market
         Revenues...........................................
        5. Providing for Variable Energy Rates in QF                  63
         Contracts..........................................
            a. Background...................................          63
            b. Implementation of the Commission's Proposal..          79
        6. Consideration of Competitive Solicitations To              82
         Determine Avoided Costs............................
    B. Relief From Purchase Obligation in Competitive Retail          89
     Markets................................................
        1. Background.......................................          90
        2. Commission Proposal..............................          91
    C. Evaluation of Whether QFs Are Separate Facilities....          93
        1. Background and Need for Reform...................          95
            a. Ability To Rebut Presumption of Separate               95
             Sites..........................................
            b. Electrical Generating Equipment..............          98
        2. Proposed Changes to Subpart B--Qualifying                 100
         Cogeneration and Small Power Production Facilities.
            a. Rebuttable Presumption of Separate Facilities         100
            b. Electrical Generating Equipment..............         108
        3. Corresponding Changes to the FERC Form No. 556...         111
    D. PURPA Section 210(m) Rebuttable Presumption of                118
     Nondiscriminatory Access to Markets....................
        1. Background.......................................         119
        2. Commission Proposal..............................         126
        3. Reliance on RFPs and Liquid Market Hubs To                131
         Terminate Purchase Obligation......................
    E. Legally Enforceable Obligation.......................         134
        1. Background and Need for Reform...................         137
        2. Commission Proposal..............................         140
    F. QF Certification Process.............................         143
        1. Background and Need for Reform...................         143
        2. Commission Proposal..............................         148
III. Information Collection Statement.......................         153
IV. Environmental Analysis..................................         154
V. Regulatory Flexibility Act Certification.................         156
VI. Comment Procedures......................................         159
VII. Document Availability..................................         163

    1. In this notice of proposed rulemaking (NOPR), the Federal Energy
Regulatory Commission (Commission) proposes to revise its regulations
(PURPA Regulations) \1\ implementing sections 201 and 210 of the Public
Utility Regulatory Policies Act of 1978 (PURPA) \2\ in light of changes
in the energy industry since 1978.
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    \1\ 18 CFR part 292. In connection with the proposed revisions
to the PURPA Regulations, the Commission also proposes to revise its
delegation of authority to Commission staff in 18 CFR part 375.
    \2\ 16 U.S.C. 796(17)-(18), 824a-3.
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    2. PURPA was enacted in 1978 as part of a package of legislative
proposals intended to reduce the country's dependence on oil and
natural gas, which at the time were in short supply and subject to
dramatic price increases. PURPA sets forth a framework to encourage the
development of alternative generation resources that do not rely on
fossil fuels and cogeneration facilities that make more efficient use
of the heat produced from the fossil fuels that were then commonly used
in the production of electricity. The Commission issued the PURPA
Regulations to implement PURPA in 1980.
    3. Circumstances have changed considerably since the Commission
implemented its PURPA Regulations in 1980. For one thing, advances in
technology and the discovery of significant new natural gas reserves
have resulted in plentiful supplies of relatively inexpensive natural
gas. As a result, there no longer is the same need to provide
incentives to address shortages of natural gas. Moreover, unlike in
1980, when the electric industry was made up principally of vertically
integrated utilities that were reluctant to purchase power from
independent generators, today the electric industry provides open
access transmission and there are vibrant wholesale electric markets in
much of the country where independent generators can sell their power
at competitive prices. These markets have supported the addition of
significant amounts of new independently-owned generation resources,
including renewable resources. In addition, there are a number of
federal and state programs that provide further incentives for the
development of alternative resources, such as renewable resources.
Consequently, the majority of renewable resources in operation today do
not rely on PURPA.
    4. Congress not only directed the Commission to establish rules to
implement PURPA, but also directed that the Commission revise those
rules ``from time to time thereafter[.]'' \3\ The Commission now is
proposing to revise its PURPA Regulations to rebalance the benefits and
obligations of the Commission's PURPA Regulations in light of the
changes in circumstances since the PURPA Regulations were promulgated
in 1980. As explained more fully herein, the Commission proposes to
grant state regulatory authorities that oversee regulated electric
utilities and nonregulated electric utilities (collectively, for ease
of reference, referred to as states) the flexibility in key respects to
incorporate competitive market pricing in the rates paid by electric
utilities to qualifying small power production facilities and
qualifying cogeneration facilities under PURPA (collectively, QFs).
These proposed changes constitute a package of reforms the Commission
believes will continue to encourage QFs while at the same time
addressing concerns that have been raised regarding the Commission's
current PURPA Regulations.
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    \3\ 16 U.S.C. 824a-3(a).
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    5. First, the Commission proposes to grant states the flexibility
to require that energy rates (but not capacity rates) in QF power sales
contracts and other legally enforceable obligations (LEO) \4\ vary in
accordance with changes in the purchasing electric utility's as-
available avoided costs at the time the energy is delivered. Under this
proposal, if a state exercises this flexibility, a QF would no longer
have the ability to elect to have its energy rate be fixed for the term
of the contract or LEO.\5\
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    \4\ The Commission has held that a LEO can take effect before a
contract is executed and may not necessarily be incorporated into a
contract. JD Wind 1, LLC, 129 FERC ] 61,148, at P 25 (2009), reh'g
denied, 130 FERC ] 61,127 (2010) (``[A] QF, by committing itself to
sell to an electric utility, also commits the electric utility to
buy from the QF; these commitments result either in contracts or in
non-contractual, but binding, legally enforceable obligations.'').
For ease of reference, however, references herein to a contract also
are intended to refer to a LEO that is not incorporated into a
contract.
    \5\ Moreover, any state--whether located in regions where energy
prices are competitively based or whether located in regions where
they are not--would be permitted to require that the fixed energy
rate established at the time of the contract include provisions,
established at the time the contract is established, providing for
revisions to the energy rate at regular intervals, consistent with,
for example, a purchasing electric utility's integrated resource
plan, to reflect updated avoided cost calculations.
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    6. Second, the Commission proposes to grant states additional
flexibility to allow QFs to have a fixed energy rate, but to provide
that such state-authorized fixed energy rate can be based on projected
energy prices during the term of a QF's contract based on the
anticipated dates of delivery.
    7. Third, the Commission proposes to grant states the flexibility
to set ``as-available'' QF energy rates: (1) For QFs selling to
electric utilities located in organized electric markets defined in 18
CFR 292.309(e), (f), or (g),\6\ at the locational marginal price (LMP);
and (2) for QFs selling to electric utilities located outside of
organized electric markets defined in 18 CFR 292.309(e), (f), or (g),
at competitive prices from liquid market hubs or calculated from a
formula based on natural gas price indices and specified heat rates.
Further, states would have the flexibility to set energy and capacity
rates pursuant to a competitive solicitation process conducted pursuant
to transparent and non-discriminatory procedures. In each case, the
Commission's proposal would entail granting the states options to
employ additional approaches in setting QF rates beyond those commonly
employed today. Under the Commission's proposal, the states would have
the flexibility to choose to adopt one or more of these options or to
continue setting QF rates under the existing standards currently set
out in the PURPA Regulations.
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    \6\ These are the markets operated by Midcontinent Independent
System Operator, Inc.; PJM Interconnection, L.L.C.; ISO New England
Inc.; New York Independent System Operator, Inc.; Electric
Reliability Council of Texas; California Independent System
Operator, Inc.; and Southwest Power Pool, Inc.
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    8. Fourth, the Commission proposes to provide that an electric
utility's obligation to purchase from QFs may be reduced to the extent
the purchasing electric utility's supply obligation has been reduced by
a state retail choice program.
    9. Fifth, the Commission proposes to modify its current ``one-mile
rule'' for determining whether generation facilities should be
considered to be part of a single facility for purposes of determining
qualification as a qualifying small power production facility.
Specifically, the Commission proposes to allow electric utilities,
state regulatory authorities, and other interested parties to show that
facilities between one and ten miles apart (i.e., more than one mile
apart and less than ten miles apart) actually are a single facility
(with distances one mile or less still irrebuttably a single facility,
and distances ten miles or more irrebuttably separate and different
facilities). The Commission also proposes to allow an entity seeking QF
status to provide further information in its certification (whether a
self-certification or a Commission certification) to preemptively
defend against subsequent

challenges by identifying factors affirmatively demonstrating that its
facility is indeed a separate facility at a separate site from other
facilities. The Commission further proposes to add a definition of the
term ``electrical generating equipment'' to the PURPA Regulations and
to clarify how the distance between facilities is to be calculated.
    10. Sixth, the Commission proposes to revise its regulations
implementing PURPA section 210(m), which provide for the termination of
an electric utility's obligation to purchase from a QF with
nondiscriminatory access to certain markets. Currently, there is a
rebuttable presumption that QFs with a net capacity at or below 20 MW
do not have nondiscriminatory access to such markets. The Commission
proposes to reduce the rebuttable presumption for small power
production facilities (but not cogeneration facilities) from 20 MW to 1
MW.
    11. Seventh, the Commission proposes to clarify that a QF must
demonstrate commercial viability and financial commitment to construct
its facility pursuant to objective and reasonable state-determined
criteria before the QF is entitled to a contract or LEO.
    12. Finally, the Commission proposes to allow a party to protest a
self-certification or self-recertification of a facility without being
required to file a separate petition for declaratory order and to pay
the associated filing fee.
    13. The Commission believes these proposed changes will enable the
Commission to continue to fulfill its statutory obligations under
sections 201 and 210 of PURPA, as explained in more detail in the
relevant sections below. In particular, 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. Allowing energy prices, but not capacity prices,
to vary in QF contracts would protect consumers without materially
affecting QF financing and, indeed, likely would make it easier for QFs
to obtain longer-term contracts that support financing.\7\ Further, the
proposed revisions to the PURPA Regulations relating to the one-mile
rule and PURPA section 210(m) would better implement the Commission's
understanding of Congress' intent in enacting those provisions in light
of current circumstances.
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    \7\ As explained below, some states have established limited
contract durations as a way of limiting long-term price risk from
fixed energy rate purchases from QFs. The Commission considers that,
by addressing the concern that has led to the imposition of short-
term contracts, the changes proposed herein will provide
opportunities for longer-term contracts, which will encourage the
development of QFs.
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    14. The Commission seeks comment on these proposed reforms 60 days
from the date of publication of this NOPR in the Federal Register.

I. Background

A. Circumstances Underlying the Passage of PURPA in 1978 and the
Commission's Promulgation of Its PURPA Regulations in 1980

    15. PURPA was part of a legislative package Congress enacted in
1978 to address the energy crisis then facing the country.\8\ As the
Supreme Court explained in FERC v. Mississippi, in passing PURPA
Congress was aware that domestic oil production had lagged behind
demand, and the country had become increasingly dependent on foreign
oil--which could jeopardize the country's economy and undermine its
independence.\9\ Roughly a third of the nation's electricity was
generated using oil and natural gas,\10\ and Congress concluded that
increased reliance on cogeneration and small power production could
significantly contribute to conserving this energy.\11\ The Fuel Use
Act, another part of that legislative package with the same ultimate
goal in mind, similarly required federal agencies to ``carry out
programs designed to prohibit or discourage the use of natural gas and
petroleum as a primary energy source and by taking such actions as lie
within their authorities to maximize the efficient use of energy and
conserve natural gas and petroleum.'' \12\ In short, as recognized by
the Supreme Court, Congress passed PURPA to address the consequences of
shortages of oil and natural gas (and electric utilities' decreasing
efficiency in their generating capacities), which adversely impacted
rates to customers and the economy as a whole.\13\
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    \8\ See Public Law 95-617, 92 Stat. 3117. In addition to PURPA,
the package included: the Energy Tax Act of 1978, Public Law 95-618,
92 Stat. 3174; the National Energy Conservation Policy Act, Public
Law 95-619, 92 Stat. 3206; the Powerplant and Industrial Fuel Use
Act of 1978, Public Law 95-620, 92 Stat. 3289; and the Natural Gas
Policy Act of 1978, Public Law 95-621, 92 Stat. 3351.
    \9\ FERC v. Miss., 456 U.S. 742, 756 (1982).
    \10\ Id. at 745.
    \11\ Id. at 757.
    \12\ 42 U.S.C. 8301(b)(7) (emphasis added).
    \13\ FERC v. Miss., 456 U.S. at 745-46.
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    16. Congress enacted PURPA section 210 in 1978 to address the
energy crisis by encouraging the development of QFs and thereby
reducing the country's demand for traditional fossil fuels.\14\ To
accomplish this, section 210(a) directed that the Commission
``prescribe, and from time to time thereafter revise, such rules as
[the Commission] determines necessary to encourage cogeneration and
small power production,'' \15\ including rules requiring electric
utilities to offer to sell electricity to, and purchase electricity
from, QFs. Section 210(f) required each state regulatory authority and
nonregulated electric utility to implement the Commission's rules.
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    \14\ Id. at 750.
    \15\ 16 U.S.C. 824a-3(a).
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    17. In 1980, the Commission issued Order Nos. 69 and 70, which
promulgated the required rules that, with minor exceptions, remain in
effect today.\16\ The Commission explained that, at the time of the
passage of PURPA, QFs faced three major obstacles: (1) Electric
utilities were not required to purchase their electric output or to
make purchases at an appropriate rate; (2) electric utilities sometimes
charged discriminatorily high rates for backup services; and (3) QFs
ran the risk of being considered public utilities themselves and thus
being subject to state and federal regulation as utilities.\17\
Further, at that time, there was no open access transmission and
essentially no competition in electric wholesale markets. Electric
utilities were vertically-integrated and held dominant

market positions. As a result of their control over transmission
access, it was virtually impossible for third parties--whether
independent power producers or other electric utilities--to compete
with them to make sales of electricity.
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    \16\ Small Power Production and Cogeneration Facilities;
Regulations Implementing Section 210 of the Public Utility
Regulatory Policies Act of 1978, Order No. 69, FERC Stats. & Regs. ]
30,128 (cross-referenced 10 FERC ] 61,150), order on reh'g, Order
No. 69-A, FERC Stats. & Regs. ] 30,160 (1980) (cross-referenced at
11 FERC ] 61,166), aff'd in part & vacated in part sub nom. Am.
Elec. Power Serv. Corp. v. FERC, 675 F.2d 1226 (D.C. Cir. 1982),
rev'd in part sub nom. Am. Paper Inst. v. Am. Elec. Power Serv.
Corp., 461 U.S. 402 (1983) (API); Small Power Production and
Cogeneration Facilities--Qualifying Status, Order No. 70, FERC
Stats. & Regs. ] 30,134 (cross-referenced at 10 FERC ] 61,230),
orders on reh'g, Order No. 70-A, FERC Stats. & Regs. ] 30,159
(cross-referenced at 11 FERC ] 61,119) and FERC Stats. & Regs. ]
30,160 (cross-referenced at 11 FERC ] 61,166), order on reh'g, Order
No. 70-B, FERC Stats. & Regs. ] 30,176 (cross-referenced at 12 FERC
] 61,128), order on reh'g, FERC Stats. & Regs. ] 30,192 (1980)
(cross-referenced at 12 FERC ] 61,306), amending regulations, Order
No. 70-D, FERC Stats. & Regs. ] 30,234 (cross-referenced at 14 FERC
] 61,076), amending regulations, Order No. 70-E, FERC Stats. & Regs.
] 30,274 (1981) (cross-referenced at 15 FERC ] 61,281).
    \17\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,863.
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    18. Given the Congressional mandate described above, the Commission
determined in Order No. 69 to set rates for sales by QFs equal to the
purchasing electric utilities' avoided costs.\18\ The Commission also
directed that electric utilities provide backup electric energy to QFs
on a non-discriminatory basis and at just and reasonable rates,\19\ and
that utilities interconnect with QFs.\20\ Pursuant to section 210(e) of
PURPA,\21\ the Commission further provided exemptions from many
provisions of the Federal Power Act (FPA) and state laws governing
utility rates and financial organization.\22\
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    \18\ 18 CFR 292.304(a)(2); see API, 461 U.S. at 412-18.
    \19\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,887-90;
see also 18 CFR 292.305.
    \20\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,874; see
also 18 CFR 292.303(c).
    \21\ 16 U.S.C. 824a-3(e).
    \22\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,864;
accord id. at 30,863, 30,894-96; see also 18 CFR 292.601-.602.
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B. Changes in Circumstances Subsequent to the Commission's Promulgation
of Its PURPA Regulations in 1980

    19. In the past 40 years, there have been three important changes
in the circumstances that prompted Congress to pass PURPA in 1978.
First, the situation with respect to the availability of natural gas
has changed completely. The Commission recently outlined the sweeping
changes that have taken place in the natural gas industry, and the
resulting greater availability of natural gas.\23\ As the Commission
explained, over the last decade, the United States has seen an
unprecedented change in the dynamics of the natural gas market and the
relevant supply and demand. Led by advancements in production
technologies, primarily in accessing shale reserves, natural gas
supplies have increased dramatically. Domestic natural gas production,
which appeared to peak in the early 1970s at 21.7 Tcf per year, has
recently increased from 18.1 Tcf in 2005 to 30.4 Tcf in 2018.\24\ The
U.S. Energy Information Administration's (EIA) Annual Energy Outlook
2019 forecasts continued supply growth over the next 25 years,
increasing to nearly 40 Tcf by 2035 and 43 Tcf by 2050.\25\ In short,
there no longer are shortages of natural gas supply.
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    \23\ Certification of New Interstate Natural Gas Facilities, 163
FERC ] 61,042 (2018).
    \24\ EIA, Monthly Energy Review, Aug. 27, 2019 (in table 4.1 see
column labeled ``Natural Gas Production (Dry)'' on the Annual tab of
the xls version) https://www.eia.gov/totalenergy/data/monthly/.
    \25\ EIA, Annual Energy Outlook 2018, at tbl.13 (Jan. 24, 2019)
(in table see row labeled ``Dry Gas Production'' under the reference
case) (Annual Energy Outlook 2019), https://www.eia.gov/outlooks/aeo/data/browser/#/?id=13-AEO2019&cases=ref2018&sourcekey=0.
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    20. Second, since 1978, the outlook for the development of
alternatives to natural gas and oil-fired resources, such as renewable
resources, has changed equally dramatically. The once-nascent
renewables industry has grown and matured over the past 40 years, and
has only accelerated subsequent to the 2005 amendment of PURPA.
Renewable resources likewise benefit from the availability of federal
tax credits \26\ and from state-mandated renewable portfolio standards
(RPS) that require electric utilities to procure electric energy from
renewable resources.\27\ The cost of renewable facilities, including
solar, also has dropped substantially,\28\ to the point that the
levelized cost of electricity (LCOE) from solar facilities is now or is
shortly expected to approach the LCOE from traditional electric
generation.\29\ Similarly, a recent report from Lawrence Berkeley
National Lab finds that wind power purchase agreements are being
executed at around $0.02/kWh, which compares favorably to projected
future fuel costs for natural gas-fired generation.\30\
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    \26\ Although Congress has reauthorized the federal production
tax credit, the federal production tax credit is still currently
scheduled to phase out over the next several years. See U.S. Dep't
of Energy, Renewable Energy Production Tax Credit, https://www.energy.gov/savings/renewable-electricity-production-tax-credit-ptc (``Wind facilities commencing construction by December 31, 2019,
and all other qualifying facilities commencing construction by
January 1, 2018 can qualify for this credit. The value of the credit
for wind steps down in 2017, 2018 and 2019. . . . For all other
technologies, the credit is not available for systems whose
construction commenced after December 31, 2017.'').
    \27\ As of February 1, 2019, 29 states, Washington, DC, and
three territories had adopted mandatory renewable portfolio
standards, while eight states and one territory had set renewable
energy goals. See National Conference of State Legislatures, State
Renewable Portfolio Standards and Goals, http://www.ncsl.org/research/energy/renewable-portfolio-standards.aspx.
    \28\ According to the EIA, the ``overnight'' (interest excluded)
capital costs for utility-scale onshore wind and fixed tilt
photovoltaic systems decreased by approximately 25 percent and 67
percent respectively, just during the period from 2013 to 2017. See
EIA, Updated Capital Cost Estimates for Utility Scale Electricity
Generating Plants, https://www.eia.gov/analysis/studies/powerplants/capitalcost/.
    \29\ EIA, Levelized Cost and Levelized Avoided Cost of New
Generation Resources in the Annual Energy Outlook 2019 (Feb. 2019),
https://www.eia.gov/outlooks/aeo/pdf/electricity_generation.pdf.
However, EIA cautions against directly comparing the costs of
dispatchable and nondispatchable generation: ``Because load must be
continuously balanced, generating units with the capability to vary
output to follow demand (dispatchable technologies) generally have
more value to a system than less flexible units (nondispatchable
technologies) such as those using intermittent resources to operate.
The LCOE values for dispatchable and non-dispatchable technologies
are listed separately in the tables because comparing them must be
done carefully. See EIA, Cost and Performance Characteristics of New
Generating Technologies, Annual Energy Outlook 2019 (Jan. 2019),
https://www.eia.gov/outlooks/aeo/assumptions/pdf/table_8.2.pdf.
    \30\ See Lawrence Berkeley National Lab, Wind Technologies
Market Report, https://emp.lbl.gov/wind-technologies-market-report/.
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    21. According to EIA, in the first 5 months of 2019, renewable
resources (including hydro) provided a significant share (approximately
20 percent) of the net electricity generated in the United States.\31\
The Commission's monthly Energy Infrastructure Update Report shows
that, as of July of 2019, the installed nameplate capacity of renewable
resources, again including hydro, represented approximately 22 percent
of the entire available installed capacity in the United States.\32\
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    \31\ See EIA, August 2019 Monthly Energy Review at Figure 7.2a,
https://www.eia.gov/totalenergy/data/monthly.
    \32\ Office of Energy Projects, Energy Infrastructure Update For
July2019 at 4 (July 2019), https://www.ferc.gov/legal/staff-reports/2019/july-energy-infrastructure.pdf.
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    22. Furthermore, EIA projects that approximately 65 percent of
capacity additions in 2019 will come from renewable resources.\33\
Although almost 100 percent of all renewable resources in 1995 were
QFs, since 2005 QFs have made up only 10 to 20 percent of all renewable
resource capacity in service in the United States. Consequently, today
most renewable resources are not relying on PURPA in order to develop
and operate. This decreasing reliance on PURPA suggests that some
generation capacity that might otherwise qualify as and be built as
small power productions under PURPA is being built, through wholesale
market constructs that have developed since the Commission first
implemented PURPA.
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    \33\ EIA, Today in Energy, New electric generating capacity in
2019 will come from renewables and natural gas (Jan. 10, 2019),
https://www.eia.gov/todayinenergy/detail.php?id=37952 (Form EIA-
860M, Preliminary Monthly Electric Generator Inventory).
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    23. Another development pursued by regions (such as the Regional
Greenhouse Gas Initiative) or states (like California and New York) has
been state-initiated efforts to promote carbon reduction and through
RPS programs require electric utilities to supply a specified
percentage of their customers' loads from renewable resources or
through the establishment of

requirements to purchase renewable energy certificates (RECs).
Presently, 29 states and the District of Columbia have mandatory RPS
programs.\34\ This trend has further influenced increasing investment
in renewables in the United States.
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    \34\ Galen Barbose, Lawrence Berkeley National Laboratory, U.S.
Renewable Portfolio Standards 2018 Annual Status Report at 6 (Nov.
2018), http://eta-publications.lbl.gov/sites/default/files/2018_annual_rps_summary_report.pdf.
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    24. Unlike renewable generation, cogeneration is a technology that
is imbedded in an industrial process.\35\ Record evidence suggests that
cogeneration has not achieved recent increases in penetration similar
to renewable generation, and also remains more dependent on PURPA. For
example, from 2008--2017, over 67 percent of industrial cogeneration
additions obtained QF status.\36\ However, energy produced by
cogeneration in 2008 equaled 304.5 TWh, decreasing to 293.9 TWh in
2018.\37\ Furthermore, this trend of decreasing cogeneration output
goes back even further; for example in 2005 cogeneration output equaled
321.6 TWh.\38\
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    \35\ See American Forest & Paper Association and Electricity
Consumers Resource Council Supplemental Comments, Docket No. AD16-
16-000, at 5 (Nov. 30, 2018).
    \36\ Id.
    \37\ This data was taken from EIA's Electricity Data Browser,
www.eia.gov/electricity/data/browser (the total of net generation by
independent power producers cogeneration, commercial cogeneration,
and industrial cogeneration).
    \38\ Id.
---------------------------------------------------------------------------

    25. Third, the introduction of QFs as competing sources of
electricity to the incumbent electric utilities has led to the
development of significant non-QF independent power production.
Development of independent power production, in turn, has been a major
factor in the establishment of vibrant competitive markets in much of
the United States. Pursuant to the Energy Policy Act of 1992, the
Commission, through Order No. 888 and related orders, has overseen the
development of competition and competitive wholesale electricity
markets.\39\ In addition, regional transmission organizations (RTO) and
independent system operators (ISO) serve two-thirds of electricity
consumers in the United States.\40\ This development has transformed
the electric industry in the intervening years and has significantly
reduced the barriers to entry that faced QFs when PURPA was enacted.
---------------------------------------------------------------------------

    \39\ See Promoting Wholesale Competition Through Open Access
Non-Discriminatory Transmission Services by Public Utilities;
Recovery of Stranded Costs by Public Utilities and Transmitting
Utilities, Order No. 888, FERC Stats. & Regs. ] 31,036 (1996),
(cross-referenced at 75 FERC ] 61,080, order on reh'g, Order No.
888-A, FERC Stats. & Regs. ] 31,048 at 30,176, (cross-referenced at
78 FERC ] 61,220, order on reh'g, Order No. 888-B, 81 FERC ] 61,248
(1997), order on reh'g, Order No. 888-C, 82 FERC ] 61,046 (1998),
aff'd in relevant part sub nom. Transmission Access Policy Study
Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New
York v. FERC, 535 U.S. 1 (2002); Market-Based Rates for Wholesale
Sales of Electric Energy, Capacity and Ancillary Services by Public
Utilities, Order No. 697, 119 FERC ] 61,295, clarified, 121 FERC ]
61,260 (2007), order on reh'g, Order No. 697-A, 123 FERC ] 61,055,
clarified, 124 FERC ] 61,055, order on reh'g, Order No. 697-B, 125
FERC ] 61,326 (2008), order on reh'g, Order No. 697-C, 127 FERC ]
61,284 (2009), order on reh'g, Order No. 697-D, 130 FERC ] 61,206
(2010), aff'd sub nom. Mont. Consumer Counsel v. FERC, 659 F.3d 910
(9th Cir. 2011).
    \40\ ISO/RTO Council, The Role of ISOs and RTOs, https://isorto.org.
---------------------------------------------------------------------------

    26. Congress recognized the important effect of the development of
these organized competitive markets when it enacted, as part of the
Energy Policy Act of 2005, PURPA section 210(m). Among other things,
section 210(m) permits electric utilities to request termination of
their obligation to purchase electricity from QFs having access to RTO/
ISO markets (or markets of comparable competitive quality).\41\ In so
doing, we interpret Congress as recognizing that the development of
competition in the electric industry created conditions that
sufficiently encouraged the development of cogeneration and small power
production facilities, at least in the RTO/ISO markets and in markets
of comparable competitive quality.
---------------------------------------------------------------------------

    \41\ 16 U.S.C. 824a-3(m).
---------------------------------------------------------------------------

    27. Since PURPA was amended in 2005, competition and competitive
markets have spread even further, and have spurred additional
development of independently-owned generation both inside and outside
of the RTO/ISO markets. For example, EIA data shows that net generation
of energy by non-utility owned renewable resources \42\ in the United
States escalated from 51.7 TWh in 2005 when EPAct 2005 was passed, to
340 TWh in 2018.\43\ This also has included significant growth in non-
utility renewable resources in states outside of RTOs. For example, net
generation by non-utility renewable resources in the region defined by
EIA as the Mountain State region \44\ increased from 3.6 TWh in 2005 to
19.5 TWh in 2012, and to 42.5 TWh in 2018.\45\ Pacific Northwest
(Oregon and Washington) net non-utility generation from renewable
resources increased from 1.5 TWh in 2005, to 8.7 TWh in 2012, and to
10.6 TWh in 2018.\46\ In the Southeast region of the country, non-
utility renewable resources saw a lesser increase from 2.6 TWh in 2005
to 2.7 TWh in 2012, but expanded to 6.5 TWh in 2018.\47\
---------------------------------------------------------------------------

    \42\ The EIA renewable resources data discussed herein is based
on the EIA ``other renewables'' category of generation resources,
which consists of wind, utility scale solar, geothermal, and biomass
resources.
    \43\ This data was taken from EIA's Electricity Data Browser,
www.eia.gov/electricity/data/browser (select net generation, other
renewables, independent power producers).
    \44\ Arizona, Colorado, Idaho, Montana, Nevada, New Mexico,
Utah, and Wyoming.
    \45\ This data was taken from EIA's Electricity Data Browser,
www.eia.gov/electricity/data/browser.
    \46\ Id.
    \47\ Florida, Georgia, Alabama, and Mississippi.
---------------------------------------------------------------------------

C. Need for Revisions to the Commission's PURPA Regulations in Light of
Changed Circumstances

    28. In 2016, the Commission conducted a technical conference in
Docket No. AD16-16-000 (Technical Conference) to address issues
involving the implementation of PURPA. The Technical Conference covered
such issues as: (1) Various methods for calculating avoided cost; (2)
the obligation to purchase pursuant to a LEO; (3) application of the
one-mile rule; and (4) the rebuttable presumption the Commission has
adopted under PURPA section 210(m) that QFs 20 MW and below do not have
nondiscriminatory access to competitive organized wholesale
markets.\48\ In addition to the oral presentations made at the
Technical Conference, the Commission received numerous written comments
on these and other subjects regarding the need to revise the PURPA
Regulations. The Commission has found these oral presentations and
comments to be helpful, and the revisions proposed in this NOPR were
informed by the record of the Technical Conference, which the
Commission is incorporating into this proceeding.
---------------------------------------------------------------------------

    \48\ Supplemental Notice of Technical Conference, Implementation
Issues Under the Public Utility Regulatory Policies Act of 1978,
Docket No. AD16-16-000 (May 9, 2016).
---------------------------------------------------------------------------

    29. Consistent with the direction from Congress that the Commission
revise its PURPA Regulations ``from time to time'' \49\ and considering
the changes in the energy industry described above, the Commission
preliminarily finds, based on the data described in the preceding
section and the comments received at the Technical Conference, that the
Commission's PURPA Regulations should be modernized. First, currently
there is an increased supply of natural gas resulting from advanced
production techniques that have opened up large new natural gas
reserves. Second, vertically integrated utilities no longer dominate
the wholesale electric markets throughout the United States as they did

in the past, and the participation of independently owned generation no
longer is the exception but is the rule in much of the country.
Consequently, electric prices increasingly are established based on
competitive factors in many regions. Third, significant renewable
resources have been developed outside of PURPA based on other programs
that specifically target renewable resources, as well as on the falling
costs of such resources.
---------------------------------------------------------------------------

    \49\ 16 U.S.C. 824a-3(a).
---------------------------------------------------------------------------

    30. In addition, there is evidence suggesting that the Commission's
rationale for allowing a QF to fix its avoided cost rate for the term
of its contract, i.e., that any overestimations and underestimations in
avoided cost rates during the term of the contract would ``balance
out'' over time,\50\ may no longer be valid. This evidence suggests,
instead, that overestimations of avoided cost have not been balanced by
underestimations.\51\ This trend may persist with the continuing
general decline in the cost of electricity due to technological
innovations, changes in the fuel mix, and conservation.\52\ Further,
testimony at the Technical Conference and data regarding the
development of independently-owned generation resources suggest that it
is not necessary for energy rates to be fixed in order to obtain
financing.\53\
---------------------------------------------------------------------------

    \50\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,880.
    \51\ See infra note 101.
    \52\ See e.g., EEI Supplemental Comments, Docket No. AD16-16-
000, attach. A at 2-3 (June 25, 2018) (EEI Supplemental Comments).
    \53\ This evidence is discussed in detail below in Section
II.A.5.b.
---------------------------------------------------------------------------

    31. Consequently, the Commission is proposing revisions to its
PURPA Regulations to rebalance the approach adopted in the 1980s.
Because some of the small power producer generation technologies
originally encouraged by PURPA are now being developed independent of
PURPA, it appears appropriate to provide states flexibility to rely on
the market tools that are available today to set QF rates. The
Commission is proposing to allow states flexibility to ensure that the
rates for energy sold by QFs to electric utilities more accurately
reflect PURPA's requirement that the rates for purchases of energy from
QFs not exceed ``the cost to the electric utility of the electric
energy which, but for the purchase from such [QF], such utility would
generate or purchase from another source'' at the time of delivery.\54\
The Commission preliminarily finds that using a competitive price will
continue to encourage the development of QFs and more closely adhere to
PURPA's requirement that rates for purchases of energy from QFs not
only be capped at avoided cost, but also be just and reasonable to the
purchasing electric utility's electric consumers and in the public
interest.\55\ Given the targeted nature of the reforms proposed here,
and the existing benefits to QFs that the Commission does not propose
to amend and that were directly responsive to the barriers to QFs that
PURPA sought to reduce,\56\ the approach adopted here also maintains
PURPA's protections against discrimination.\57\
---------------------------------------------------------------------------

    \54\ 16 U.S.C. 824a-3(b), (d).
    \55\ 16 U.S.C. 824a-3(b)(1).
    \56\ See, e.g., supra notes 19-20, 22 (citing inter alia 18 CFR
292.303(c) (electric utility's obligation to interconnect), 292.305
(electric utility's obligation to provide backup power to QFs),
292.601-02 (QF exemption from public utility regulations in FPA and
Public Utility Holding Company Act)).
    \57\ 16 U.S.C. 824a-3(b)(2).
---------------------------------------------------------------------------

    The Commission believes that the revisions proposed here represent
a reasonable package of benefits and obligations that would bring the
Commission's implementation of PURPA into the modern era while at the
same time continuing to satisfy PURPA's statutory mandates.

II. Discussion

A. QF Rates

    32. The Commission proposes to revise its PURPA Regulations to
permit states to incorporate competitive market forces in setting QF
rates. First, the Commission proposes to allow states to exercise their
discretion to set the energy component of the rate a purchasing
electric utility pays for a QF's power based on market prices rather
than on the purchasing electric utility's administratively-determined
avoided cost rate. Thus, the Commission proposes to revise its PURPA
Regulations with regard to energy rates to state that:
     States have 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 locational marginal price (LMP) or
similar energy price derived by the market, in effect at the time the
energy is delivered.
     States have the flexibility to 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.
     States have the flexibility to 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.
     States in RTO/ISO markets have the flexibility to instead
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.
    33. Second, the Commission proposes to amend its regulations to
make clear that States have the flexibility to require that energy and/
or capacity rates be determined through a competitive solicitation
process, such as an RFP. However, the Commission does not otherwise
propose to change how the PURPA Regulations require the capacity
component of a QF's rates to be determined.\58\
---------------------------------------------------------------------------

    \58\ An electric utility is not required to pay for QF capacity
that the state has determined is not needed. See Hydrodynamics Inc.,
146 FERC ] 61,193, at P 35 (2014) (Hydrodynamics) (referencing 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.''); Entergy Servs., Inc., 137 FERC ] 61,199, at P
56 (2011).
---------------------------------------------------------------------------

    34. Although the Commission is proposing to modify how the states
are permitted to calculate avoided costs, it is not terminating the
requirement that the states continue to calculate, and to set QF rates
at, such avoided costs.
    35. The Commission has long emphasized that states have ``great
latitude in determining the manner of implementation of the
Commission's rules, provided that the manner chosen is reasonably
designed to implement the requirements of Subpart C [which includes the
pricing rules of Sec.  292.304].'' \59\ The modifications proposed here
are intended to be consistent with this approach. The Commission
intends that the states will continue to have ``great latitude'' in
determining how to apply the revised rules, provided that such
application is reasonably designed to implement any new rate provisions
that may be adopted, as well as the other already-existing provisions
of the PURPA Regulations.
---------------------------------------------------------------------------

    \59\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,891-92.
The Commission explained that ``[s]uch latitude is necessary in
order for implementation to accommodate local conditions and
concerns, so long as the final plan is consistent with statutory
requirements.'' Policy Statement Regarding the Commission's
Enforcement Role Under Section 210 of the Public Utility Regulatory
Policies Act of 1978, 23 FERC ] 61,304, at 61,646 (1983).
---------------------------------------------------------------------------

1. Background
    36. PURPA requires that the Commission promulgate rules, to be

implemented by the states,\60\ establishing the rates electric
utilities pay for purchases of QF energy. 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; \61\ and
(3) not exceed ``the incremental cost to the electric utility of
alternative electric energy,'' \62\ 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.'' \63\ 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,'' \64\ although the term ``avoided
cost'' itself does not appear in PURPA.
---------------------------------------------------------------------------

    \60\ 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).
    \61\ 16 U.S.C. 824a-3(b)(1)-(2).
    \62\ 16 U.S.C. 824a-3(b).
    \63\ 16 U.S.C. 824a-3(d) (emphasis added).
    \64\ 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.'').
---------------------------------------------------------------------------

    37. In addition, the PURPA Regulations currently provide a QF two
options for how to sell its power to an electric utility. The QF may
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 (the so-called ``as-available'' rate).\65\ Alternatively, the
QF may choose to sell pursuant to a contract over a specified term.\66\
---------------------------------------------------------------------------

    \65\ 18 CFR 292.304(d)(1).
    \66\ 18 CFR 292.304(d)(2)(a)-(b); see also FLS Energy, Inc., 157
FERC ] 61,211, at P 21 (2016) (FLS) (citing 18 CFR 292.304(d)).
---------------------------------------------------------------------------

    38. 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 and fixed at the time the LEO is incurred; \67\ or (2)
the purchasing electric utility's avoided cost calculated at the time
of delivery.\68\
---------------------------------------------------------------------------

    \67\ 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).
    \68\ 18 CFR 292.304(d)(2)(i).
---------------------------------------------------------------------------

    39. 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.'' \69\ 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.'' \70\
---------------------------------------------------------------------------

    \69\ 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 (``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.'').
    \70\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,880.
---------------------------------------------------------------------------

    40. The record developed in the Commission's technical conference
docket, Docket No. AD16-16-000, where the Commission began its
reconsideration of the PURPA Regulations, indicates that allowing QFs
to fix their avoided cost rates at the time a LEO is incurred has
resulted in overpayments as energy prices generally have declined over
the years, leaving the fixed energy portion of the QF rate well above
the purchasing electric utility's actual avoided energy costs at the
time of delivery.\71\ Some commenters have recommended that the
Commission allow states to ``price generation [energy] from QFs at
market prices, and to update those prices regularly so that the prices
for qualifying facilities are not burdensome on customer rates'' and
``clarify that states can set avoided costs through [requests for
proposal (RFPs)] or other forms of competitive solicitations,'' and
that the Commission limit as-available avoided cost energy rates in a
LEO to no higher than avoided cost rates at the time of delivery.\72\
---------------------------------------------------------------------------

    \71\ EEI Supplemental Comments, attach. A at 2-3 (June 25,
2018).
    \72\ Id. at 4.
---------------------------------------------------------------------------

    41. Over the years subsequent to the issuance of the PURPA
Regulations in 1980, the Commission has taken significant steps to
implement changes to its rules and regulations to encourage the
development of competitive wholesale electricity markets. After
approving the first market-based rate tariff in 1989,\73\ sales of
electricity at market-based rates proliferated. This ultimately led to
the issuance of Order No. 697 \74\ in 2007, which established uniform
regulations governing market-based rate sales. In addition, RTOs and
ISOs with organized electric markets were established in the 2000s, and
today serve two-thirds of electricity consumers in the United
States.\75\
---------------------------------------------------------------------------

    \73\ See Citizens Power and Light Corp., 48 FERC ] 61,210
(1989).
    \74\ Market-Based Rates for Wholesale Sales of Electric Energy,
Capacity and Ancillary Services by Public Utilities, Order No. 697,
119 FERC ] 61,295, clarified, 121 FERC ] 61,260 (2007), order on
reh'g, Order No. 697-A, 123 FERC ] 61,055, clarified, 124 FERC ]
61,055, order on reh'g, Order No. 697-B, 125 FERC ] 61,326 (2008),
order on reh'g, Order No. 697-C, 127 FERC ] 61,284 (2009), order on
reh'g, Order No. 697-D, 130 FERC ] 61,206 (2010), aff'd sub nom.
Mont. Consumer Counsel v. FERC, 659 F.3d 910 (9th Cir. 2011).
    \75\ ISO/RTO Council, The Role of ISOs and RTOs, https://isorto.org.
---------------------------------------------------------------------------

    42. These developments have largely transformed the electric
industry from one where rates were once based on administratively-
determined cost of service ratemaking to one where rates now often are
based on competitive market forces. This change has led the Commission
to likewise consider whether to allow states to rely on competitive
forces, rather than administrative determinations, to set as-available
avoided cost energy rates.
2. LMP as a Permissible Rate for Certain As-Available QF Energy Sales
    43. The Commission proposes to revise the PURPA Regulations in 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.
    44. RTOs and ISOs generally use LMP to set day-ahead and real-time
energy prices through competitive auctions that optimally dispatch
resources to balance

supply and demand, while taking into account actual system conditions
including congestion on the transmission system. As described in the
Commission Energy Primer written by Commission staff, ``[t]he RTO
markets calculate a LMP at each location on the power grid. . . All
sellers receive the LMP for their location and all buyers pay the
market clearing price for their location.'' \76\ While the various RTOs
and ISOs may calculate LMP somewhat differently, the Commission has
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.'' \77\ 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, and thus prices vary based
on location and time.'' \78\
---------------------------------------------------------------------------

    \76\ Federal Energy Regulatory Commission, Energy Primer, A
Handbook of Market Basics, at 60 (Nov. 2015), available at https://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
    \77\ Offer Caps in Markets Operated by Regional Transmission
Organizations and Independent System 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).
    \78\ 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).
---------------------------------------------------------------------------

    45. The Commission therefore preliminarily finds 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, 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 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).
The Commission also notes that Congress, through enactment of section
210(m) of PURPA, appears to recognize that RTO/ISO LMP pricing provides
sufficient encouragement for QFs.
    46. Consequently the Commission believes it is appropriate to
consider giving states the flexibility to employ LMP pricing for QF
energy rates. Specifically, the Commission proposes to make clear in
the PURPA Regulations that a state may use LMP as a rate for as-
available QF energy sales to electric utilities located in an RTO/ISO
market.\79\
---------------------------------------------------------------------------

    \79\ Although not regulated by the Commission, the Commission
proposes to include in this definition of LMP the LMP established in
the market governed by the Electric Reliability Council of Texas.
---------------------------------------------------------------------------

    47. The Commission requests comment on whether the real-time prices
established in the California Independent System Operator, Inc.
(CAISO)-administered Energy Imbalance Market (EIM) \80\ are similar for
these purposes to the LMP in RTOs/ISOs. In this regard, the Commission
requests comment on whether there are any reasons why prices developed
in the EIM similarly ``reflect the least-cost of meeting an incremental
megawatt-hour of demand at each location on the grid,'' \81\ as the
Commission has found to be the case with LMP rates.\82\
---------------------------------------------------------------------------

    \80\ By seeking comment regarding the CAISO EIM prices, the
Commission does 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.
    \81\ SMUD, 616 F.3d at 524.
    \82\ Use of real time prices in the 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 requests comments on
whether it would be appropriate to use the EIM price to develop an
as-available energy rate.
---------------------------------------------------------------------------

    48. In addition to continuing to set QF energy rates at avoided
costs, using LMPs for as-available energy pricing brings many other
benefits. 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.\83\
---------------------------------------------------------------------------

    \83\ 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. Markets Operated by Regional Transmission
Organizations and Indep. Sys. Operators, 153 FERC ] 61,221, at P 2
(2015).
---------------------------------------------------------------------------

    49. Furthermore, when Congress added PURPA Sec.  210(m) as part of
EPAct 2005, Congress provided for the Commission to terminate electric
utilities' obligation to make new purchases from QFs that have
nondiscriminatory access to the RTO/ISO markets and markets of
comparable competitive quality. The Commission interprets this
amendment as representing an acknowledgement by Congress that access to
these markets provides sufficient encouragement to QFs.
    50. The Commission understands that some states already use LMP to
establish avoided cost energy rates under our PURPA Regulations.\84\
The Commission thus proposes 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,\85\ a state would be able to
adopt LMP as a per se appropriate measure of the as-available energy
component of avoided costs.\86\
---------------------------------------------------------------------------

    \84\ See Exelon Wind 1, LLC, 140 FERC ] 61,152, at P 11 (2012),
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 (Sept. 27, 2012) (stating that Maryland, New Jersey,
North Carolina, Virginia, Connecticut, New Hampshire, Kentucky, and
Michigan have set avoided costs at LMP).
    \85\ See 18 CFR 292.304(e).
    \86\ We recognize 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 (2012), reconsideration denied, 155 FERC ]
61,066 (2016) (``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 already found that this statement was overtaken by
events, namely Southwest Power Pool, Inc.'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 acknowledges that, if adopted in a
final rule, the reasoning in this NOPR supports the departure from
our 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)).
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3. Use of Other Competitive Prices as a Permissible Rate for Certain
As-Available QF Energy Sales
    51. The Commission proposes 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 a

competitive price (Competitive Price) calculated at the time of
delivery. Competitive Prices would be defined as: (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 case, the state would need to find that the
Competitive Price reasonably represents a competitive market price for
the purchasing electric utility, consistent with Congress's directive
that QF rates not exceed ``the incremental cost to the electric utility
of alternative electric energy.'' \87\ Other conditions also would have
to be satisfied, as explained below.
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    \87\ 16 U.S.C. 824a-3(b).
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a. Background
    52. The Commission recognizes 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.\88\ Further, 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.\89\
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    \88\ See Price Discovery in Natural Gas and Electric Markets,
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 Electric 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 ] 61,463, at 61,463 (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).
    \89\ See, e.g., ISO New England Inc., 131 FERC ] 61,147, at P 5
(2010) (calculating the competitive price cap for imports into ISO
New England equal to a published fuel price times a proxy heat
rate).
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    53. For the same reasons described above that LMPs represent an
appropriate energy rate for QFs purchasing from electric utilities
located in RTO/ISO markets, the Commission proposes to find that
Competitive Prices 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 price
at particular points and times. 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.
However, depending on how far away a particular purchasing electric
utility or selling QF may be from the liquid market hub in question,
the Commission believes that it may be appropriate to allow the states
to set as-available energy rates based on Market Hub prices.
    54. Natural gas indices coupled with the heat rate of an efficient
natural gas combined-cycle generating facility may also be a reasonably
accurate measure of avoided cost, at least in those markets where
natural gas commonly is the marginal fuel. In such markets, we 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 economically displace them. Thus, using natural gas
indices and the heat rate of a combined-cycle unit to establish avoided
cost also relies on competitive market forces, in this case competitive
forces in natural gas markets for the fuel used by natural gas combined
cycle) facilities the purchasing electric utility would generate itself
or purchase from another source but for the sale from the QF.\90\
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    \90\ See 16 U.S.C. 824a-3(d).
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b. Commission Proposal
    55. The Commission proposes in sections 292.304(b)(7) and (e)(1) to
give states the flexibility to set QF energy rates for sales to
electric utilities located outside of RTO/ISO markets based on
Competitive Prices, i.e., prices determined at liquid market hubs
(Market Hub Prices), or prices determined by a formula based on natural
gas price indices and a specified proxy heat rate for an efficient
natural gas combined-cycle generating facility (Combined Cycle Prices).
i. Market Hub Prices
    56. The Commission proposes 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 actually
relate to the costs an electric utility would avoid but for the
purchase from the QF.
    57. The following represents examples of factors the Commission
believes a state reasonably could consider in making this
determination: (1) Whether the hub is sufficiently liquid that prices
at the hub represent a competitive price; \91\ (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; \92\ 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. The above
factors are not intended to be exhaustive and states reasonably could
consider other factors in identifying a relevant liquid trading hub for
setting QF energy rates. The Commission seeks comment on additional
factors or standards for consideration by the states in determining
whether liquid trading hubs could be used to set an electric utility's
as-available energy avoided cost rate.
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    \91\ 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 Natural Gas and Electric Markets,
109 FERC ] 61,184 at P 66.
    \92\ This factor might not apply if the purchase of energy
avoided by the electric utility is from a resource whose energy is
priced based on the hub price even though the purchasing electric
utility does not have the ability to deliver energy from the hub
itself to its load.
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    58. The Commission also understands that, 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.\93\
In addition, the Commission understands that market prices in a region
may be determined based on a formula that incorporates prices at more
than one market hub located in the region. The Commission seeks comment
on whether under this proposal a state should be permitted to set QF
rates at energy prices in a region that are 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.
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    \93\ 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.
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ii. Combined Cycle Prices
    59. In regions where there are no RTOs/ISO or market hubs, a
competitive

price for energy may be established as the price of energy generated
from an efficient natural gas combined cycle generating facility. The
Commission proposes to allow states to set QF as-available energy rates
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 particular proposed natural gas price indices 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. Again, the above factors are not exhaustive
and states would have flexibility to apply other factors that also
might be appropriate for consideration.
iii. Other Approaches to Competitive Pricing for Certain As-Available
QF Energy Sales
    60. The Commission observes that electric utilities may purchase
energy at market-oriented prices other than those that would qualify
under the standards identified above.
    The two options presented above are not intended to supersede the
states' existing ability to set as-available energy rates based on an
electric utility's avoided costs. The states would continue to be free,
under the Commission's existing PURPA Regulations, to determine that
competitive energy prices included in an electric utility's power
purchase agreement represent the electric utility's avoided cost of
energy and to set avoided cost energy rates for that utility based on
its contract rate. Nothing proposed here would prevent a state from
establishing an avoided cost rate based on such a contract, provided
that all the necessary conditions for determining avoided costs
apply.\94\
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    \94\ Further, as explained in more detail below, energy and/or
capacity rates for QFs could be established through a competitive
solicitation process, such as an RFP.
---------------------------------------------------------------------------

4. Permitting the Energy Rate Component of a Contract To Be Fixed at
the Time of the LEO Using Forecasted Values of the Estimated Stream of
Market Revenues
    61. Frequently, price forecasts are available for LMPs in RTOs/
ISOs, for liquid market hubs located outside of RTOs/ISOs, and for
natural gas pricing hubs. Such forecasts could be used to allow QFs to
request a fixed energy rate component calculated at the time a LEO is
incurred. The Commission therefore proposes to add a new option in
Sec.  292.304(d)(1)(iii) permitting fixed energy rates to be based on
forecasted estimates of the stream of revenue flows during the term of
the contract. In other words, states could rely on market estimates of
forecasted energy prices at the times of delivery over the anticipated
life of the contract--such estimates are commonly referred to as a
forward price curve--to develop a fixed energy rate component for that
contract when such estimates reflect the purchasing electric utility's
avoided costs.
    62. The fixed energy rate component of the contract could be a
single energy rate, based on the amortized present value of the
forecast energy prices, or it could be a series of specified energy
rates that are different in future years (or other periods).\95\ Under
this proposal, the QF would be able to establish, at the time the LEO
is incurred, the applicable energy rate(s) for the entire term of a
contract when the contract is signed; however, the energy rate in the
contract could be different from year-to-year (or some other period)
and nevertheless comply with the current Sec.  292.304(d)(1)(ii)
requirement that the energy rate be fixed for the term of the
contract.\96\
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    \95\ As explained above, the PURPA Regulations already require
that the fixed energy rate would need to account for the operating
characteristics of the QF, including the QF's ability to deliver
energy during peak periods and the utility's ability to dispatch
energy from the QF. See 18 CFR 292.304(e)(2).
    \96\ This is permissible under the Commission's existing PURPA
Regulations. See Windham Solar LLC, 157 FERC ] 61,134, at PP 5-6
(2016) (Windham Solar) (``[A]lthough state regulatory authorities
cannot preclude a QF . . . from obtaining a legally enforceable
obligation with a forecasted avoided cost rate, we remind the
parties that the Commission's regulations allow state regulatory
authorities to consider a number of factors in establishing an
avoided cost rate. These factors which include, among others, the
availability of capacity, the QF's dispatchability, the QF's
reliability, and the value of the QF's energy and capacity, allow
state regulatory authorities to establish lower avoided cost rates
for purchases from intermittent QFs than for purchases from firm
QFs.'' (citing 18 CFR 292.304(e)-(f)) (footnote omitted).
---------------------------------------------------------------------------

5. Providing for Variable Energy Rates in QF Contracts
a. Background
    63. As explained above, if a QF chooses to sell energy and/or
capacity pursuant to a contract, the PURPA Regulations provide the QF
the option of receiving the purchasing electric utility's avoided cost
calculated and fixed at the time the LEO is incurred.\97\ The
Commission's justification for allowing QFs to fix their rate at the
time of the LEO for the entire term of a contract was that fixing the
rate provides certainty necessary for the QF to obtain financing.\98\
The Commission stated that its regulations pertaining to LEOs ``are
intended to reconcile the requirement that the rates for purchases
equal the utilities' avoided costs with the need for qualifying
facilities to be able to enter contractual commitments based, by
necessity, on estimates of future avoided costs.'' \99\ Further, the
Commission agreed with the ``need for certainty with regard to return
on investment in new technologies.'' \100\
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    \97\ 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).
    \98\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,880
(justifying the rule on the basis of ``the need for certainty with
regard to return on investment in new technologies'').
    \99\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,880.
    \100\ Id.
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    64. The provision that QFs be permitted to fix their rates for the
entire term of a contract or other LEO has proved to be one of the most
controversial aspects of the Commission's PURPA Regulations. Some
commenters at the Technical Conference submitted data indicating that
energy prices generally have declined over the years, leaving the fixed
energy portion of the QF rate, even when levelized, well above market
prices that likely would represent the purchasing electric utility's
actual avoided energy costs at the time of delivery.\101\ Based on this
concern, some

commenters recommended that the Commission allow states to ``price
generation [energy] from QFs at market prices, and to update those
prices regularly so that the prices for qualifying facilities are not
burdensome on customer rates'' and that the Commission should limit
avoided cost energy rates in a LEO to no higher than avoided cost rates
at the time of delivery.\102\ QFs, in turn argued that elimination of
the option to fix QF rates for the term of a contract would threaten a
QF's ability to obtain financing.\103\
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    \101\ See Alliant Energy Comments, Docket No. AD16-16-000, at 5
(Nov. 7, 2016) (``Current market-based wind prices in the Iowa
region of MISO are approximately 25% lower than the PURPA contract
obligation prices [Interstate Power and Light Company] is forced to
pay for the same wind power for long-term contracts entered into as
of June 2016. As a result, PURPA-mandated wind power purchases
associated with just one project could cost Alliant Energy's Iowa
customers an incremental $17.54 million above market wind prices
over the next 10 years.'') (emphasis in original); EEI Supplemental
Comments, Docket No. AD16-16-000, attach. A at 3-4 (June 25, 2018)
(EEI Supplemental Comments) (``On August 1, 2014, a 10-year fixed
price contract at the Mid-Columbia wholesale power market trading
hub was priced at $45.87/MWh. On June 30, 2016, the same contract
was priced as $30.22/MWh, a decline of 34% in less than two years.
However, over the next 10 years, PacifiCorp has a legal obligation
to purchase 51.9 million MWhs under its PURPA contract obligations
at an average price of $59.87/MWh. The average forward price curve
for the Mid-Columbia trading hub during the same period is $30.22/
MWh, or 50% below the average PURPA contract price that PacifiCorp
will pay. The additional price required under long-term fixed
contracts will cost PacifiCorp's customers $1.5 billion above
current forward market prices over the next 10 years.''); Comm'r
Kristine Raper, Idaho Commission Comments, Docket No. AD16-16-000,
at 3-4 (June 29, 2016) (``Idaho Power demonstrated that the average
cost for PURPA power since 2001 has exceed the Mid-Columbia (Mid-C)
Index Price and is projected to continue to exceed the Mid-C price
through 2032. Likewise, PacifiCorp's levelized avoided cost rates
for 15-year contract terms in Wyoming shows a decrease of
approximately 50% from 2011 through 2015 (from approximately $60 per
megawatt-hour to less than $30 per megawatt-hour).'').
    \102\ EEI Supplemental Comments, attach. A at 4; see also
Southern Company Comments, Docket No. AD16-16-000, at 7 (June 29,
2016) (``the avoided energy cost payment to the QF should be based
on actual avoided energy cost at the time the QF delivers energy'').
    \103\ See Technical Conference Tr. at 26:22-25, 27:1-3 (Solar
Energy Industries Association) (``The Power Purchase Agreement is
the single most important contract of the development and financing
of an energy project that's not owned by a utility. Without the
long-term commitment to buy the output of that agreement at a fixed
price, there is no predictable stream of revenue. Without a
predictable stream of revenues, there is no financing. Without any
financing, there is no project.'').
---------------------------------------------------------------------------

    65. Further, it is clear that the desire to limit the effect of
fixed QF contract rates has directly led to PURPA implementation issues
that affect QF financing in other respects, particularly with respect
to the length of QF contracts.\104\ For example, a commissioner of the
Idaho Public Service Commission (Idaho Commission) testified at the
Technical Conference that the Idaho Commission's decision to limit QF
contracts to a two-year term was based on the Idaho Commission's
concern that longer contract terms at fixed rates would lead to
payments above avoided costs.\105\ Similarly, Southern Company
testified that the fixed payment requirement is ``resulting in . . .
typically shorter contract term lengths.'' \106\ Golden Spread Electric
Cooperative recommended that if the fixed cost requirement is not
eliminated, the Commission permit shorter contract terms, ``as short as
one-year or three years at most.'' \107\
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    \104\ See Natural Resources Defense Council Comments, Docket No.
AD16-16-000, at 4 (June 30, 2016).
    \105\ See Technical Conference Tr. at 142-43 (Idaho Commission)
(``No matter the starting point, allowing QFs to fix their avoided
cost rates for long terms results in rates which will eventually
exceed and overestimate avoided cost rates into the future. The
longer the term, the greater the disparity. . . . [The Idaho
Commission] recently reduced PURPA contract lengths to two years in
order to correct the disparity. We didn't reduce contract lengths to
kill PURPA. We did it to allow periodic adjustment of avoided cost
rates.'').
    \106\ Id. at 202 (Southern Company).
    \107\ Golden Spread Electric Cooperative Comments, Docket No.
AD16-16-000, at 10 (June 29, 2016).
---------------------------------------------------------------------------

    66. The Commission proposes to revise Sec.  292.304(d) of the PURPA
Regulations to permit a state to limit a QF's option to elect to fix at
the outset of a LEO the energy rate for the entire length of its
contract, and instead allow the state to require QF energy rates to
vary during the term of the contract. However, under the proposed
revisions to Sec.  292.304(d), a QF would continue to be entitled to a
contract with avoided capacity costs calculated and fixed at the time
the LEO is incurred. Only the contractual energy rate could be required
by a state to vary.
    67. To the extent that a QF is not entitled to capacity payments
because a purchasing electric utility is not avoiding any capacity as a
consequence of entering into a contract with a QF, the QF's contract
could be limited by a state under the proposed rule to variable energy
payments. However, in that event, the only costs being avoided by the
purchasing electric utility would be the incremental costs of
purchasing or producing energy at the time the energy is
delivered.\108\ Further, the state would retain the ability to require
that the QF's energy rate be fixed at the time the LEO is incurred.
---------------------------------------------------------------------------

    \108\ See, e.g., City of Ketchikan, 94 FERC at 62,061
(``[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.'').
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    68. In Order No. 69, the Commission allowed avoided costs to be
calculated and fixed at the time a LEO is first incurred because the
Commission believed that any overestimations or underestimations ``will
balance out.'' \109\ The Commission now finds compelling the record
evidence, discussed in section II.A.5.a. above, that overestimations
have not been adequately balanced by underestimations in past years.
Further, this trend may persist into the future with the continuing
general decline in the cost of both wind and solar generation.\110\
Consequently, the Commission believes that it may be necessary to allow
states to provide for a variable energy rate in order to reflect more
accurately the purchasing electric utility's avoided costs and
therefore satisfy the statutory requirement that QF rates not exceed
the utility's avoided cost and ``be just and reasonable to the electric
consumers of the electric utility and in the public interest.'' \111\
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    \109\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,880.
    \110\ See EIA, Today in Energy, Average U.S. construction costs
for solar and wind continued to fall in 2016 (Aug. 8, 2018),
available at https://www.eia.gov/todayinenergy/detail.php?id=36813
(``Based on 2016 EIA data for newly constructed utility-scale
electric generators (those with a capacity greater than one
megawatt) in the United States, annual capacity-weighted average
construction costs for solar photovoltaic systems and onshore wind
turbines declined . . . .'').
    \111\ 16 U.S.C. 824a-3(b)(1).
---------------------------------------------------------------------------

    69. The Commission recognizes that the current PURPA Regulations
allowing a QF to fix its rates for the term of a contract were based on
the recognition that fixed rates are beneficial for obtaining financing
for QF projects. QF developers continue to assert today that they
require fixed rates to finance new projects. However, the Commission
does not view the proposed modification to the PURPA Regulations as
materially affecting the ability of QFs to obtain financing. This is
the case for a number of reasons.
    70. First, the Commission's proposed modifications would allow a
state to set a variable energy rate, but not a variable avoided
capacity rate at the time of a LEO. The Commission understands that
fixed energy rates are not generally required in the electric industry
in order for electric generation facilities to be financed. For
example, RTO/ISO capacity markets provide only for fixed capacity
payments, leaving capacity owners to sell their energy into the
organized electric markets at LMPs that vary based on market conditions
at the time the energy is delivered.\112\ These fixed capacity and
variable energy payments have been sufficient to permit the financing
of significant amounts of

new capacity in the RTOs and ISOs.\113\ Testimony presented at the
Technical Conference similarly showed that non-QF independent power
projects located outside of RTOs enter into contracts with fixed
capacity and variable energy prices.\114\ Other comments at the
Technical Conference suggested that a fixed capacity charge likewise
would be adequate for financing a QF project.\115\
---------------------------------------------------------------------------

    \112\ See, e.g., ISO New England Inc., 147 FERC ] 61,172, at P 2
(2014) (resources receiving capacity awards must offer into energy
market).
    \113\ See, e.g., Monitoring Analytics, LLC., Third Quarter, 2018
State of the Market Report for PJM, January through September, at
249, Table 5-6 (Nov. 8, 2018) (over 23,000 MW of new capacity
constructed in PJM Interconnection, L.L.C. since 2007-2008;
including over 16,000 MW of new capacity added in the last four
years), available at http://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2018/2018q3-som-pjm.pdf.
    \114\ See Technical Conference Tr. at 167-69 (Southern Company)
(``So if we enter into a bilateral contract with an independent
power producer for combustion turbine or combined cycle capacity, we
don't fix the energy price. The capacity payment is a fixed payment.
That's their fixed [stream]. The energy price is typically indexed
to the price of natural gas.''); see also id. at 178 (American
Forest & Paper Association) (``Now, you sign a long-term IPP
contract. That contract [has] got a variable energy cost in it.'').
    \115\ See Solar Energy Industries Association Comments, Docket
No. AD16-16-000, at 3 (June 29, 2016) (``Developers need rates for
such sales of energy and/or capacity to be fixed'') (emphasis
added).
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    71. In addition to the fact that the Commission is not changing the
requirement that QF capacity rates be fixed, the Commission anticipates
that some may prefer basing variable QF contract energy rates on
transparent competitive market prices over the term of the contract.
Such rates are based on observable and foreseeable market forces, and
thus the electric industry has developed forecasts for these
competitive markets that are commonly accepted by the Commission and
the industry as reasonable estimates of future prices.\116\ Such
estimates may provide some support for financing purposes.
---------------------------------------------------------------------------

    \116\ See generally ITC Great Plains, LLC, 126 FERC ] 61,223, at
P 43 (2009) (study evaluating benefits of transmission project based
on price forecasts ``provides a reasonable basis to conclude that
ITC Great Plains' projects will reduce the cost to serve load by
reducing congestion through facilitating integration and delivery of
low-cost wind energy in the [Southwest Power Pool, Inc.] region and
providing greater transfer capability'').
---------------------------------------------------------------------------

    72. Further, there are financial products available, such as
contracts for differences, which allow generation owners to hedge their
exposure to fluctuating energy prices.\117\ Such financial products can
provide additional comfort to lenders regarding the level of energy
rate revenues that a QF can expect from the energy it delivers, in
addition to the fixed capacity payments the QF is entitled to receive
under its contract.
---------------------------------------------------------------------------

    \117\ See, e.g., Electric Storage Participation in Markets
Operated by Regional Transmission Organizations and Independent
System Operators, Order No. 841, 162 FERC ] 61,127, at P 299 (2018)
(noting that ``market participants that purchase energy from the
RTO/ISO markets . . . may enter into bilateral financial
transactions to hedge the purchase of that energy'').
---------------------------------------------------------------------------

    73. Moreover, although it may have been true at the time the
Commission promulgated its PURPA Regulations in 1980 that QFs needed to
fix their energy rate for the term of their contract in order to obtain
financing of their facilities, there is evidence that this no longer is
true. This evidence comes in the form of data, described below, showing
that independent generators that have not qualified as QFs under PURPA
(including renewable resources that could qualify as QFs but have not
sought QF status) have been able to obtain financing for new
facilities. That owners of such facilities, which do not have recourse
to the avoided cost provisions of PURPA, have been able to obtain
financing for new projects is highly relevant to the question of
whether the existing PURPA avoided cost provisions--including the
requirement to enter into contracts with fixed energy rates--are
necessary for QFs to obtain financing.
    74. For example, EIA data shows that, since 2005, QFs have made up
only 10 to 20 percent of all renewable resource capacity in service in
the United States, demonstrating that most renewable resources no
longer need to rely on PURPA avoided cost rates to sell their output
economically.\118\ EIA data also shows that net generation of energy by
non-utility owned renewable resources \119\ in the United States
escalated from 51.7 TWh in 2005 when EPAct 2005 was passed, to 340 TWh
in 2018.\120\ While much of this growth was in states located in RTOs/
ISOs, there also was significant growth of non-utility renewable
generation in other states. For example, net generation by non-utility
renewable resources in the region defined by EIA as the Mountain State
region \121\ increased from 3.6 TWh in 2005 to 19.5 TWh in 2012, and to
42.5 TWh in 2018.\122\ Pacific Northwest (Oregon and Washington) net
non-utility generation from renewable resources increased from 1.5 TWh
in 2005, to 8.7 TWh in 2012, and to 10.6 TWh in 2018.\123\
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    \118\ See EIA, Today in Energy, North Carolina has More PURPA-
Qualifying Solar Facilities than any other State, figure entitled
PURPA qualifying facilities (1980-2015) percent of total renewable
capacity (Aug. 23, 2015), available at https://eia.gov/todayinenergy/detail.php?id=27632.
    \119\ The EIA renewable resources data discussed herein is based
on the EIA ``other renewables'' category of generation resources,
which consists of wind, utility scale solar, geothermal, and biomass
resources.
    \120\ This data was taken from EIA's Electricity Data Browser,
available at www.eia.gov/electricity/data/browser.
    \121\ Arizona, Colorado, Idaho, Montana, Nevada, New Mexico,
Utah, and Wyoming.
    \122\ This data was taken from EIA's Electricity Data Browser,
available at www.eia.gov/electricity/data/browser.
    \123\ Id.
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    75. EIA data on independently-owned natural gas-fired generation
capacity tells a similar story. Natural gas-fired capacity without the
requisite cogeneration technology cannot qualify as qualifying small
power production or cogeneration, and thus most of this capacity will
not be within the scope of the PURPA avoided cost rate provisions. EIA
data shows that, in 2018, 44.4 percent of all energy produced by
natural gas-fired generation in the United States was generated by
independently-owned capacity.\124\ The total amount of energy produced
in 2018 by independently-owned natural gas-fired generation was 651
TWh, an increase of 13.7 percent from 2017.\125\ Again, the percentage
of independently-owned natural gas generation outside of RTOs/ISOs was
lower than in RTOs/ISOs, but still was significant. In the Mountain
states region, 21.4 percent of the energy produced by natural gas-fired
generation 2018 was produced by independently-owned capacity, and in
Oregon and Washington 45.4 percent of natural gas-fired energy was
produced by independently-owned capacity.\126\ It thus is apparent that
independent owners of non-QF generation have been, and continue to be,
able to obtain financing for their facilities.
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    \124\ EIA, Electric Power Monthly with Data for December 2018,
at Table 1.7.B, available at https://www.eia.gov/electricity/monthly/current_month/epm.pdf.
    \125\ Id.
    \126\ Id.
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    76. The Commission does not suggest that this evidence supports the
conclusion that substantial non-QF capacity is being financed and
constructed without any form of fixed revenue to support financing.
Rather, the evidence demonstrates that the existing PURPA avoided cost
rate provisions are not necessary for some independent power generators
to put in place contractual arrangements, including fixed revenue
streams, that are sufficient to obtain financing. QFs, which have the
advantage of mandatory purchase requirements, should be better
positioned than non-QFs to negotiate the necessary contractual
arrangements for financing. Moreover, QFs are as equally well
positioned as non-QF independent generators to take

advantage of federal and state incentives designed to encourage the
construction of renewable resources.
    77. Finally, as described above, states and utilities have
responded to the requirement that QF contract rates be fixed for the
term of a contract by shortening the terms of those contracts and
taking other steps that some argue make it more difficult for a QF to
obtain a financeable contract. Representatives of QFs explained that
short contract terms make financing difficult, and they cited the Idaho
Commission's decision to limit contracts to a two-year term as being
especially harmful.\127\ Because the decisions to impose short contract
terms were based largely on the current requirement that QFs be able to
fix their rates, particularly energy rates, for the term of their
contracts, allowing states to require contractual energy rates to vary
could result in longer QF contracts, and perhaps other more favorable
treatment, that would improve the financeability of QF projects.
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    \127\ See Technical Conference Tr. at 70 (Solar Energy
Industries Association); 73 (California Cogeneration Council).
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    78. Although the Commission believes that the above evidence
supports the conclusion that a fixed capacity rate and a variable
energy rate should be adequate to support financing for QFs, the
Commission solicits further information from interested entities on the
ability of QFs to obtain financing based on contracts with a fixed
capacity rate and a variable energy rate. In particular, the Commission
solicits information on any independently owned projects (QF and non-
QF) that required a fixed energy rate in addition to a fixed capacity
rate to obtain financing and on independently owned projects (QF and
non-QF) that were able to obtain financing without a fixed energy rate.
b. Implementation of the Commission's Proposal
    79. The proposal described above is not mandatory. The Commission
proposes to give the states the flexibility to continue to allow QFs to
fix their contract energy rates as of the date of their LEO. The
Commission's proposal here gives states the additional flexibility to
consider imposing some measure of variability to QF contract energy
rates when a state determines that it is necessary to do so to comply
with the statutory requirement that QF rates not exceed the utility's
avoided costs.
    80. Further, the Commission understands that one standard form of
QF contract rate currently employed by a number of utilities is a one-
part rate, applicable to each MWh of energy delivered by the QF, which
is calculated to reflect both avoided capacity costs and avoided energy
costs. Such contracts also typically impose a must purchase obligation
on the purchasing utility. The Commission's proposed rule is not
intended to prevent states from implementing such an approach to
setting QF contract rates in the future. However, as explained above,
the Commission is not modifying the requirement in the PURPA
Regulations that QFs have the option of fixing their contract capacity
rates as of the date of the LEO.
    81. Consequently, the Commission proposes that, to the extent that
a state determines to establish a one-part QF contract rate that
recovers both avoided capacity and avoided energy costs, the rate must
continue to be subject to the QF's option to select a fixed rate for
the term of the contract, as provided in Sec.  304(d)(2)(ii). Any
requirement to impose a variable energy QF contract rate would need to
be accomplished through a multi-part rate that includes separate
avoided capacity cost rates and avoided energy cost rates.\128\
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    \128\ If, however, the QF contract rate is appropriately based
solely on avoided energy costs with no avoided capacity cost
component, then that rate could be implemented on a variable basis
in accordance with the requirements of these proposed rules.
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6. Consideration of Competitive Solicitations To Determine Avoided
Costs
    82. The Commission proposes to revise the PURPA Regulations in 18
CFR 292.304 to add subsection (b)(8). In combination with new
subsection (e)(1), this subsection would permit a state the flexibility
to set avoided energy and/or capacity rates using competitive
solicitations (i.e., RFPs), conducted pursuant to appropriate
procedures.
    83. The Commission recognizes that one way to enable the industry
to move towards more competitive QF pricing is to allow states to
establish QF avoided cost rates through an RFP process. Such an
approach has been suggested on a number of occasions, including in the
National Association of Regulatory Utility Commissioners' (NARUC)
supplemental comments submitted in Docket No. AD16-16-000, where NARUC
proposed that

energy and capacity needs . . . would be filled by conducting
competitive solicitations for energy and capacity. These competitive
solicitations, or request for proposals (RFPs), would be open to all
QFs and would be overseen by State commissions or administered
independently of any individual market participant to mitigate anti-
competitive behavior of the buyer.\129\
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    \129\ NARUC Supplemental Comments, Docket No. AD16-16-000, at 2
(July 20, 2018).

    84. The Commission previously has explored this issue. In 1988, the
Commission issued a Notice of Proposed Rulemaking proposing to adopt
regulations that would allow bidding procedures to be used in
establishing rates for purchases from QFs.\130\ That rulemaking
proceeding, along with several related proceedings, ultimately was
withdrawn as overtaken by events in the industry.\131\
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    \130\ Regulations Governing Bidding Programs, FERC Stats. &
Regs. ] 32,455 (1988) (cross-referenced at 42 FERC ] 61,323)
(Bidding NOPR); see also Administrative Determination of Full
Avoided Costs, FERC Stats. & Regs. ] 32,457 (1988) (cross-referenced
at 42 FERC ] 61,324) (ADFAC NOPR).
    \131\ See Regulations Governing Bidding Programs, 64 FERC ]
61,364 at 63,491-92 (1993) (terminating Bidding NOPR proceeding);
see also Administrative Determination of Full Avoided Costs, 84 FERC
] 61,265 (1998) (terminating ADFAC NOPR proceeding).
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    85. Since then, the Commission held in a 2014 order addressing the
specific facts of the RFP at issue that an electric utility's
obligation to purchase power from a QF under a LEO could not be
curtailed based on a failure of the QF to win an only occasionally-held
RFP.\132\ In a separate proceeding involving a different RFP, the
Commission declined to initiate an enforcement action where the state
RFP was an alternative to a PURPA program.\133\
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    \132\ See, e.g., Hydrodynamics, 146 FERC ] 61,193 at PP 31-35.
RFP processes have been used more recently in a number of states,
including Georgia, North Carolina, and Colorado. Georgia's RFP
process is described at Ga. Comp. R. & Regs. 515-3-4.04(3) (2018).
North Carolina's RFP process is described at 4 N.C. Admin. Code
11.R8-71 (2018). Colorado's RFP process is described at SPower
Development Co. v. Colorado Pub. Utils. Comm'n, 2018 WL 1014142 (D.
Colo. Feb. 22, 2018).
    \133\ Winding Creek Solar LLC, 151 FERC ] 61,103,
reconsideration denied, 153 FERC ] 61,027 (2015). But see Winding
Creek Solar LLC v. Peterman, 932 F.3d 861 (9th Cir. 2019).
---------------------------------------------------------------------------

    86. Given this precedent, the Commission proposes to amend its
regulations to clarify that a state could establish QF avoided cost
rates through an appropriate RFP process. Consistent with its general
approach of giving states flexibility in the manner in which they
determine avoided costs, the Commission does not propose in this NOPR
to prescribe detailed criteria governing the use of RFPs as tools to
determine rates to be paid to QFs, as well as to determine other
contract terms. States arguably may be in the best position to consider
their particular local circumstances, including questions of need,
resulting economic impacts, amounts to be purchased through auctions,
and related issues.

    87. Nevertheless, in considering what constitutes proper design and
administration of an RFP, it is appropriate for the Commission to
establish certain minimum criteria governing the process by which RFPs
are to be conducted in order for an RFP to be used to set QF rates. In
that regard, the Commission has addressed competitive solicitations in
prior orders in a number of contexts that provide potential guidance to
states and others. For example, the Commission's policy for the
establishment of negotiated rates for merchant transmission
projects,\134\ the Bidding NOPR, and the Hydrodynamics case \135\ all
suggest factors that could be considered in establishing an appropriate
RFP that is conducted in a transparent and non-discriminatory manner.
These factors include, among others: (a) An open and transparent
process; (b) solicitations should be open to all sources to satisfy
that purchasing electric utility's capacity needs, taking into account
the required operating characteristics of the needed capacity; \136\
(c) solicitations conducted at regular intervals; (d) oversight by an
independent administrator; and (e) certification as fulfilling the
above criteria by the state regulatory authority or nonregulated
electric utility. The Commission proposes that a state may use an RFP
to set avoided energy and capacity rates provided that such competitive
solicitation process is conducted pursuant to procedures ensuring the
solicitation is conducted in a transparent and non-discriminatory
manner. Such an RFP must be conducted in a process that includes, but
is not limited to, the factors identified above which are set forth in
proposed Sec.  292.304(b)(8) of the Commission's Regulations.
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    \134\ Allocation of Capacity on New Merchant Transmission
Projects and New Cost-Based, Participant-Funded Transmission
Projects, 142 FERC ] 61,038 (2013).
    \135\ See Hydrodynamics, 146 FERC ] 61,193 at P 32 n.70 (citing
Bidding NOPR, FERC Stats. & Regs. ] 32,455 at 32,030-42). The
Commission notes that, while QFs not awarded a contract pursuant to
an RFP would retain their existing PURPA right to sell energy as
available to the electric utility, if the state has concluded that
such QF puts tendered after an RFP was held are ``not needed,'' the
capacity rate may be zero because an electric utility is not
required to pay a capacity rate for such puts if they are not
needed. See Hydrodynamics, 146 FERC ] 61,193 at P 35 (referencing
City of Ketchikan, Alaska, 94 FERC at 62,061 (``[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.'')).
    \136\ See 18 CFR 292.304(e); Windham Solar LLC, 157 FERC ]
61,134 at PP 5-6.
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    88. In addition, the Commission seeks comment on whether it should
provide further guidance on whether, and under what circumstances, an
RFP can be used as a utility's exclusive vehicle for acquiring QF
capacity.\137\
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    \137\ Even if an RFP were used as an exclusive vehicle for an
electric utility to obtain QF capacity, QFs that do not receive an
award in the RFP would be entitled to sell energy to the electric
utility at its as-available avoided energy cost rate.
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B. Relief From Purchase Obligation in Competitive Retail Markets

    89. Section 292.303(a) of the PURPA Regulations requires electric
utilities generally to purchase ``any energy and capacity which is made
available from a qualifying facility.'' \138\ The Commission proposes
to modify this regulation to provide electric utilities relief from
this purchase obligation to the extent their supply obligations are
reduced by a state's retail choice program.
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    \138\ 18 CFR 292.303(a).
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1. Background
    90. Historically, electric utilities were responsible for serving
all of the load within their franchised service territories. Since the
1990s, however, some states have restructured their electricity markets
to incorporate retail choice, which allows retail electric customers to
choose alternative electricity suppliers and not purchase from their
local electric utility. This type of restructuring may have decreased
electric utilities' obligations to serve load, i.e., they no longer are
required to serve load that otherwise would be their native load.
However, electric utilities were still generally required to continue
to serve as the Provider of Last Resort (POLR) and serve customers that
were not obtaining electricity from competitive electric retail
suppliers. Electricity for POLR load often is procured through a
competitive solicitation process with contracts of one year or less.
This allows customers to leave POLR service and enter into contracts
with competitive electricity suppliers while protecting electric
utilities from having to honor long-term contracts for a shifting
customer base.
2. Commission Proposal
    91. It is reasonable for electric utilities' PURPA capacity
purchase obligations to be reduced to the extent retail choice reduces
their supply obligations. To the extent POLR supplies are obtained
through solicitations having a particular contract term such as one
year, the length of the utility's PURPA purchase contract should match
the term of the POLR supply solicitation contracts in order to more
accurately reflect the utility's avoided costs.
    92. The Commission proposes to add regulatory text at the end of
Sec.  292.303(a) of the PURPA Regulations to provide that the purchase
obligation may be reduced to the extent the purchasing electric
utility's supply obligation has been reduced by a state retail choice
program. The Commission proposes, through this change, to provide that
state regulatory authorities and nonregulated electric utilities have
flexibility to respond to the possibility that, over time, a utility's
POLR supply obligation may decrease (or increase). The Commission
intends that this proposal would apply prospectively from the effective
date of the final rule and would not disturb contracts in effect at the
time the utility's supply obligation is reduced.

C. Evaluation of Whether QFs Are Separate Facilities

    93. The PURPA Regulations and Commission precedent establish an
irrebuttable presumption that affiliated small power production
facilities using the same energy resource, but which are more than one
mile apart from each other, are located at separate sites and thus are
separate facilities. This irrebuttable presumption therefore renders
such facilities eligible for the benefits of PURPA if each facility,
individually, has a maximum power production capacity of 80 MW or
less.\139\ Section 292.204(a)(2)(ii) of the PURPA Regulations states
that to measure one mile, ``the distance between facilities shall be
measured from the electrical generating equipment of a facility,''
\140\ but the PURPA Regulations do not define what constitutes
electrical generating equipment or explain how to measure the distance
between facilities.
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    \139\ N. Laramie Range Alliance, 139 FERC ] 61,190, at PP 22-24
(2012) (Northern Laramie). See 18 CFR 292.204(a)(1).
    \140\ 18 CFR 292.204(a)(2)(ii).
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    94. As discussed below, the Commission proposes to amend Sec. Sec.
292.204(a) and 292.207 of the PURPA Regulations to allow entities
challenging a QF certification to show that affiliated small power
production facilities more than one mile apart and less than ten miles
apart, are actually part of a single facility, and not separate
facilities; the presumption, in other words, would be a rebuttable
presumption for facilities over one mile apart and less than ten miles
apart. The Commission also proposes amending Sec.  292.202 to include a
definition of ``electrical generating equipment'' and Sec.
292.204(a)(2)(ii) to

specify how to measure the distance between facilities that have
multiple separate sets of ``electrical generating equipment'' such as
is often the case with wind farms and solar facilities.
1. Background and Need for Reform
a. Ability To Rebut Presumption of Separate Sites
    95. PURPA defines a small power production facility as ``a facility
which is an eligible solar, wind, waste, or geothermal facility, or a
facility which (i) produces electric energy solely by the use, as a
primary energy source, of biomass, waste, renewable resources,
geothermal resources, or any combination thereof; and (ii) has a power
production capacity which, together with any other facilities located
at the same site (as determined by the Commission), is not greater than
80 MW.'' \141\ The 80 MW limit on the size of a facility that can
qualify as a small power production facility requires a definition of
what it means to be ``located at the same site,'' to determine whether
a QF satisfies the 80 MW limit.
---------------------------------------------------------------------------

    \141\ 16 U.S.C. 796(17)(A) (emphasis added).
---------------------------------------------------------------------------

    96. Currently, Sec.  292.204(a) of the PURPA Regulations provides
that small power production facilities are considered to be at the same
site if they are located within one mile of each other, use the same
energy resource, and are owned by the same person(s) or its
affiliates.\142\ This regulatory provision is commonly referred to as
``the one-mile rule'' and is used to calculate the size of a facility
and to distinguish what is a separate facility. The Commission has
stated that the one-mile rule is an irrebuttable presumption--
facilities within one mile are ``at the same site'' and facilities more
than a mile apart from each other are not.\143\
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    \142\ 18 CFR 292.204(a). Hydroelectric facilities have slightly
different rules, which reference water from the same impoundment.
    \143\ Northern Laramie, 139 FERC ] 61,190 at PP 22-24.
---------------------------------------------------------------------------

    97. In recent years, arguments have been raised that some QF
developers of small power production facilities are circumventing the
one-mile rule, and thereby circumventing PURPA, by strategically siting
small power production facilities that use the same energy resource--
primarily wind farms made up of multiple individual wind turbines--
slightly more than one mile apart in order to qualify as separate small
power production facilities that are protected by the irrebuttable
presumption that facilities more than a mile apart are separate
QFs.\144\
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    \144\ See, e.g., EEI Comments, Docket No. AD16-16-000, at 5
(Nov. 7, 2016); National Rural Electric Cooperative Association