Qualifying Facility Rates and Requirements; Implementation Issues Under the Public Utility Regulatory Policies Act of 1978, 53246-53275 [2019-20803]
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53246
Federal Register / Vol. 84, No. 193 / Friday, October 4, 2019 / Proposed Rules
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
Federal Energy Regulatory
Commission, Department of Energy.
ACTION: Notice of proposed rulemaking.
AGENCY:
In this notice of proposed
rulemaking, the Federal Energy
Regulatory Commission proposes to
revise its regulations implementing
SUMMARY:
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 https://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, (202) 502–6415,
lawrence.greenfield@ferc.gov.
Helen Shepherd (Technical
Information), Office of Energy Market
Regulation, Federal Energy Regulatory
Commission, 888 First Street NE,
Washington, DC 20426, (202) 502–6176,
helen.shepherd@ferc.gov.
Thomas Dautel (Technical
Information), Office of Energy Policy
and Innovation, Federal Energy
Regulatory Commission, 888 First Street
NE, Washington, DC 20426, (202) 502–
6196, thomas.dautel@ferc.gov.
SUPPLEMENTARY INFORMATION:
Table of Contents
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Paragraph
Nos.
I. Background ............................................................................................................................................................................................
A. Circumstances Underlying the Passage of PURPA in 1978 and the Commission’s Promulgation of Its PURPA Regulations in 1980 ..................................................................................................................................................................................
B. Changes in Circumstances Subsequent to the Commission’s Promulgation of Its PURPA Regulations in 1980 ...................
C. Need for Revisions to the Commission’s PURPA Regulations in Light of Changed Circumstances .......................................
II. Discussion ............................................................................................................................................................................................
A. QF Rates ........................................................................................................................................................................................
1. Background .............................................................................................................................................................................
2. LMP as a Permissible Rate for Certain As-Available QF Energy Sales ..............................................................................
3. Use of Other Competitive Prices as a Permissible Rate for Certain As-Available QF Energy Sales ................................
a. Background ......................................................................................................................................................................
b. Commission Proposal .....................................................................................................................................................
i. Market Hub Prices ....................................................................................................................................................
ii. Combined Cycle Prices ...........................................................................................................................................
iii. Other Approaches to Competitive Pricing for Certain As-Available QF Energy Sales .....................................
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 .......................................................................................................................
5. Providing for Variable Energy Rates in QF Contracts .........................................................................................................
a. Background ......................................................................................................................................................................
b. Implementation of the Commission’s Proposal ............................................................................................................
6. Consideration of Competitive Solicitations To Determine Avoided Costs ........................................................................
B. Relief From Purchase Obligation in Competitive Retail Markets ..............................................................................................
1. Background .............................................................................................................................................................................
2. Commission Proposal ............................................................................................................................................................
C. Evaluation of Whether QFs Are Separate Facilities ...................................................................................................................
1. Background and Need for Reform .........................................................................................................................................
a. Ability To Rebut Presumption of Separate Sites ..........................................................................................................
b. Electrical Generating Equipment ...................................................................................................................................
2. Proposed Changes to Subpart B—Qualifying Cogeneration and Small Power Production Facilities ..............................
a. Rebuttable Presumption of Separate Facilities .............................................................................................................
b. Electrical Generating Equipment ...................................................................................................................................
3. Corresponding Changes to the FERC Form No. 556 ............................................................................................................
D. PURPA Section 210(m) Rebuttable Presumption of Nondiscriminatory Access to Markets ...................................................
1. Background .............................................................................................................................................................................
2. Commission Proposal ............................................................................................................................................................
3. Reliance on RFPs and Liquid Market Hubs To Terminate Purchase Obligation ...............................................................
E. Legally Enforceable Obligation ....................................................................................................................................................
1. Background and Need for Reform .........................................................................................................................................
2. Commission Proposal ............................................................................................................................................................
F. QF Certification Process ...............................................................................................................................................................
1. Background and Need for Reform .........................................................................................................................................
2. Commission Proposal ............................................................................................................................................................
III. Information Collection Statement ......................................................................................................................................................
IV. Environmental Analysis .....................................................................................................................................................................
V. Regulatory Flexibility Act Certification .............................................................................................................................................
VI. Comment Procedures .........................................................................................................................................................................
VII. Document Availability ......................................................................................................................................................................
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Federal Register / Vol. 84, No. 193 / Friday, October 4, 2019 / Proposed Rules
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.
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
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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‘‘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.
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
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.
3 16
U.S.C. 824a–3(a).
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.
4 The
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7. Third, the Commission proposes to
grant states the flexibility to set ‘‘asavailable’’ 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.
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
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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Federal Register / Vol. 84, No. 193 / Friday, October 4, 2019 / Proposed Rules
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 selfcertification 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 longerterm contracts that support financing.7
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
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Further, the proposed revisions to the
PURPA Regulations relating to the onemile 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.
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
longer-term contracts, which will encourage the
development of QFs.
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).
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rates to customers and the economy as
a whole.13
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.
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
13 FERC
v. Miss., 456 U.S. at 745–46.
at 750.
15 16 U.S.C. 824a–3(a).
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 (crossreferenced 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) (crossreferenced at 15 FERC ¶ 61,281).
17 Order No. 69, FERC Stats. & Regs. ¶ 30,128 at
30,863.
14 Id.
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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.
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
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
18 18
CFR 292.304(a)(2); see API, 461 U.S. at 412–
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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.
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/.
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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.
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
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=13AEO2019&cases=ref2018&sourcekey=0.
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-electricityproduction-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, https://
www.ncsl.org/research/energy/renewable-portfoliostandards.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
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53249
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
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
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.
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
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/.
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-energyinfrastructure.pdf.
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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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.
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
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,
34 Galen Barbose, Lawrence Berkeley National
Laboratory, U.S. Renewable Portfolio Standards
2018 Annual Status Report at 6 (Nov. 2018), https://
eta-publications.lbl.gov/sites/default/files/2018_
annual_rps_summary_report.pdf.
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.
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,
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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.
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.
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 nonutility 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 nonutility 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
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.
41 16 U.S.C. 824a–3(m).
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.
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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, nonutility 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
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.
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
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.
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).
49 16 U.S.C. 824a–3(a).
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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.
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
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
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.
54 16 U.S.C. 824a–3(b), (d).
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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
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
55 16
U.S.C. 824a–3(b)(1).
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).
56 See,
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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
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
§ 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 alreadyexisting provisions of the PURPA
Regulations.
1. Background
36. PURPA requires that the
Commission promulgate rules, to be
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).
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).
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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 shorthand phrase ‘‘avoided cost,’’ 64 although
the term ‘‘avoided cost’’ itself does not
appear in PURPA.
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
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
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.’’).
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)).
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time the LEO is incurred; 67 or (2) the
purchasing electric utility’s avoided cost
calculated at the time of delivery.68
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
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
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).
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.
71 EEI Supplemental Comments, attach. A at 2–3
(June 25, 2018).
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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
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 marketbased 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
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 asavailable 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
72 Id.
at 4.
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.
73 See
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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
45. The Commission therefore
preliminarily finds that LMP is an
accurate measure of avoided costs.
Unlike, for example, average systemwide 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, longlasting prices as tends to be the case
currently for administrativelydetermined avoided costs, but prices
that are calculated daily (for the dayahead 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.
76 Federal Energy Regulatory Commission, Energy
Primer, A Handbook of Market Basics, at 60 (Nov.
2015), available at https://www.ferc.gov/marketoversight/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).
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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
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
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
49. Furthermore, when Congress
added PURPA § 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
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.
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.
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).
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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
3. Use of Other Competitive Prices as a
Permissible Rate for Certain AsAvailable 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
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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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.
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
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
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87 16
U.S.C. 824a–3(b).
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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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 asavailable 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 combinedcycle 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
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
90 See
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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.
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.
ii. Combined Cycle Prices
59. In regions where there are no
RTOs/ISO or market hubs, a competitive
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.
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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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 asavailable 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.
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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
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53255
all the necessary conditions for
determining avoided costs apply.94
5. Providing for Variable Energy Rates in
QF Contracts
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
§ 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
§ 292.304(d)(1)(ii) requirement that the
energy rate be fixed for the term of the
contract.96
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
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
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.
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
PO 00000
Frm 00011
Fmt 4701
Sfmt 4702
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).
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.
101 See Alliant Energy Comments, Docket No.
AD16–16–000, at 5 (Nov. 7, 2016) (‘‘Current marketbased 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
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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
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 twoincremental $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 megawatthour).’’).
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.’’).
104 See Natural Resources Defense Council
Comments, Docket No. AD16–16–000, at 4 (June 30,
2016).
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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
66. The Commission proposes to
revise § 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 § 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.
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
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).
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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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
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
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).
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).
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new capacity in the RTOs and ISOs.113
Testimony presented at the Technical
Conference similarly showed that nonQF 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
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.
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
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
https://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).
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’’).
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’’).
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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.
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 nonutility 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
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.
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42.5 TWh in 2018.122 Pacific Northwest
(Oregon and Washington) net nonutility 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
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 independentlyowned 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.
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
122 This data was taken from EIA’s Electricity
Data Browser, available at www.eia.gov/electricity/
data/browser.
123 Id.
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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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.
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
127 See Technical Conference Tr. at 70 (Solar
Energy Industries Association); 73 (California
Cogeneration Council).
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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
§ 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
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
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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individual market participant to mitigate
anti-competitive behavior of the buyer.129
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
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
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.
129 NARUC Supplemental Comments, Docket No.
AD16–16–000, at 2 (July 20, 2018).
130 Regulations Governing Bidding Programs,
FERC Stats. & Regs. ¶ 32,455 (1988) (crossreferenced 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).
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).
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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 nondiscriminatory 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 § 292.304(b)(8) of the
Commission’s Regulations.
88. In addition, the Commission seeks
comment on whether it should provide
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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further guidance on whether, and under
what circumstances, an RFP can be used
as a utility’s exclusive vehicle for
acquiring QF capacity.137
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.
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
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.
138 18 CFR 292.303(a).
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more accurately reflect the utility’s
avoided costs.
92. The Commission proposes to add
regulatory text at the end of § 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.
94. As discussed below, the
Commission proposes to amend
§§ 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 § 292.202 to include
a definition of ‘‘electrical generating
equipment’’ and § 292.204(a)(2)(ii) to
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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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.
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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.
96. Currently, § 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
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
141 16
U.S.C. 796(17)(A) (emphasis added).
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.
144 See, e.g., EEI Comments, Docket No. AD16–
16–000, at 5 (Nov. 7, 2016); National Rural Electric
Cooperative Association Comments, Docket No.
142 18
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are some facilities that may be so close
that it is reasonable to irrebuttably treat
98. Section 292.204(a)(2)(ii) of the
them as a single facility (those a mile or
PURPA regulations states that, to
less apart), so there are some facilities
measure one mile, ‘‘the distance
that are sufficiently far apart that it is
between facilities shall be measured
from the electrical generating equipment reasonable to treat them as irrebuttably
separate facilities. That latter distance,
of a facility.’’ 145 The Commission has
the Commission believes, is ten miles or
suggested in orders what is not
more apart. Thus, if two affiliated
considered ‘‘electrical generating
146
equipment,’’
but has never defined or facilities are one mile or less apart they
elaborated on what equipment meets the are currently and will continue to be
irrebuttably presumed to be a single
definition of ‘‘electrical generating
facility at a single site. If affiliated
equipment.’’ For example, wind farms
facilities are ten miles or more apart,
are typically comprised of multiple
they will be irrebuttably presumed to be
wind turbines spread over some
separate facilities at separate sites.
geographic area; however, each wind
102. If affiliated facilities are between
turbine could be considered ‘‘electrical
one and ten miles apart (i.e., more than
generating equipment.’’
one mile apart and less than ten miles
99. Similarly, solar facilities can be
apart) there will still be a presumption,
spread over some geographic area (albeit
but it will be a rebuttable presumption,
likely not as large a footprint as a wind
that they are separate facilities at
farm), potentially creating confusion as
separate sites. Purchasing electric
to whether the one mile is measured
utilities and others thus would be able
from the edge of the panels at one
to file a protest attempting to rebut the
facility to the edge of the panel at the
presumption for facilities more than one
next facility, or from the center point of
mile apart and less than ten miles apart,
each solar array. Additionally, the
and argue that they should be treated as
Commission has not specified how to
a single facility. The Commission may
measure the distance between facilities
also act sua sponte. The Commission
that have multiple separate sets of
proposes, as explained below, that self‘‘electrical generating equipment.’’
certifications will remain effective after
2. Proposed Changes to Subpart B—
a protest has been filed, until such time
Qualifying Cogeneration and Small
as the Commission issues an order
Power Production Facilities
revoking the certification.
103. The Commission proposes
a. Rebuttable Presumption of Separate
allowing
an entity seeking QF status to
Facilities
provide further information in its
100. The Commission proposes to
certification (both self-certification and
allow entities challenging a QF
Commission certification), to
certification to rebut the presumption
preemptively defend against rebuttal by
that affiliated facilities located more
asserting factors that affirmatively show
than one mile apart are considered to be that two facilities are indeed separate
separate QFs. The Commission proposes facilities at separate sites.147 Anyone
that this change would be effective as of challenging the QF certification would
the date of a final rule, which means
be allowed to assert factors to show that
that such challenges could only be made the facilities are actually part of the
to QF certifications and recertifications
same, single facility.
that are submitted after the effective
104. The Commission proposes
date of the final rule in this proceeding. limiting protests challenging QF status
101. The Commission proposes that
by requiring any entity filing a protest
an entity can seek to rebut the
to specify facts that make a prima facie
presumption only for those facilities
demonstration that the facility described
that are located more than one mile
in the self-certification, selfapart and less than ten miles apart. The
recertification, or Commission
Commission believes that, just as there
certification does not satisfy the
requirements for QF status. General
AD16–16–000, at 7 (Nov. 7, 2016); Southern
allegations or unsupported assertions
Company Comments, Docket No. AD16–16–000, at
would not be a basis for denial of
9–10 (Nov. 7, 2016); NARUC Supplemental
certification. The Commission further
Comments, Docket No. AD16–16–000, at 3 (Nov. 7,
b. Electrical Generating Equipment
2016).
145 18 CFR 292.204(a)(2)(ii) (emphasis added).
146 In Order No. 70, the Commission stated: ‘‘The
comments noted that some facilities may include
equipment for gathering energy to be used in the
facility which may extend up to a number of miles
from the generating facility. The Commission
believes that the one-mile limit should be measured
from the generating facilities.’’ Order No. 70, FERC
Stats. & Regs. ¶ 30,134 at 30,943.
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147 While a QF with a net power production
capacity of 1 MW or less is not required to formally
certify its QF status (either through Commission
certification or self-certification), if the QF’s status
is later challenged the QF would be able to respond
by affirmatively demonstrating that its facilities are
not located at the same site as other affiliated
facilities and thus that the QF does not exceed the
80 MW size limitation.
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proposes limiting protests to QF status
by requiring that once the Commission
has affirmatively certified an applicant’s
QF status through either a Commission
certification proceeding or in response
to protests challenging QF status, any
later protest to a QF’s existing
certification asserting that facilities
further than one mile apart are part of
a single QF must demonstrate changed
circumstances that call into question the
continued validity of the earlier
certification.
105. The Commission proposes that
physical and ownership factors may be
asserted to rebut or defend against
rebuttal. Noting that no single factor
would be dispositive, the Commission
proposes the factors listed below:
(1) Physical characteristics including
such common characteristics as:
Infrastructure, property ownership,
interconnection agreements, control
facilities, access and easements,
interconnection facilities up to the point
of interconnection to the distribution or
transmission system, collector systems
or facilities, points of interconnection,
motive force or fuel source, off-take
arrangements, property leases, and
connections to the electrical grid; and
(2) ownership/other characteristics,
including such characteristics as
whether the facilities in question are:
Owned or controlled by the same
person(s) or affiliated persons(s),
operated and maintained by the same or
affiliated entity(ies), selling to the same
electric utility, using common debt or
equity financing, constructed by the
same entity within 12 months,
managing a power sales agreement
executed within 12 months of a similar
and affiliated facility in the same
location, placed into service within 12
months of an affiliated project’s
commercial operation date as specified
in the power sales agreement, or sharing
engineering or procurement contracts.
The Commission solicits comments on
whether the Commission should rely on
some or any of these factors, or other
factors, or whether the various factors
should be considered together and
weighed.
106. Finally, for its PURPA
Regulations, the Commission generally
relies on the definition of an ‘‘affiliate’’
provided in its regulations at
§ 35.36(a)(9). The Commission will
continue to rely on this definition and
notes that subsection (iii) of the
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Commission’s regulation provides that
the Commission may determine, after
appropriate notice and opportunity for
hearing, that a person stands in such
relation to a specified company that
there is likely to be an absence of arm’slength bargaining in transactions
between them as to make it necessary or
appropriate in the public interest or for
the protection of investors or consumers
that the person be treated as an
affiliate.148 The Commission intends,
when applying its rules on separate
facilities, to consider this provision of
its regulations, when entities otherwise
would not be deemed affiliates under
the other provisions of the definition, to
determine whether a person
nevertheless should be treated as an
affiliate. In doing so, the Commission
could take into consideration many of
the same factors that would reasonably
be considered in evaluating whether
facilities located over one and less than
ten miles apart are a single facility or
separate facilities.
107. The Commission believes that
this change, together with the proposed
definition of ‘‘electrical generating
equipment’’ and revision to the FERC
Form No. 556 discussed below, would
more closely align with Congress’s
requirement that QFs seeking to certify
as small power production facilities are
in fact below the statutory limit for such
facilities.149
b. Electrical Generating Equipment
108. The Commission proposes
defining ‘‘electrical generating
equipment’’ to refer to all boilers, heat
recovery steam generators, prime
movers (any mechanical equipment
driving an electric generator), electrical
generators, photovoltaic solar panels
and/or inverters, fuel cell equipment
and/or other primary power generation
equipment used in the facility,
excluding equipment for gathering
energy to be used in the facility. The
Commission expects that each wind
turbine on a wind farm and each solar
panel in a solar facility would be
considered ‘‘electrical generating
148 18
CFR 35.36(a)(9)(iii).
16 U.S.C. 796(17)(A)(ii) (defining small
power production facility as inter alia ‘‘a facility
which is an eligible solar, wind, waste, or
geothermal facility, or a facility which—. . . 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 megawatts.’’).
149 See
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equipment’’ because each wind turbine
and each solar panel is independently
capable of producing electric energy.
We seek comments on this approach,
and on what—if not individual wind
turbines and solar panels—should be
considered ‘‘electrical generating
equipment’’ for wind and solar plants.
109. The Commission also proposes
specifying how to measure the distance
between facilities that have multiple
separate sets of ‘‘electrical generating
equipment’’ such as wind farms and
solar facilities. In this NOPR, the
Commission proposes measuring the
distance between the nearest ‘‘electrical
generating equipment’’ of any two
facilities such that, for the facilities to
be considered irrebuttably separate, all
such equipment of one QF must be at
least ten miles away from all such
equipment of another QF. We believe
this is the appropriate way to measure
the distance between affiliated sets of
‘‘electrical generating equipment’’
because this reflects the distance
between the components directly tied to
producing electric energy.
110. The Commission seeks comment
on this approach, and whether
alternative approaches would be more
appropriate. For example, some parties
have suggested in QF certification
proceedings that the Commission could
use the geographic center of the plant
footprint or a weighted average of the
locations of the individual pieces of
‘‘electrical generating equipment.’’ 150
The Commission is concerned these
approaches may be easily gamed, but
seeks comment on whether they may be
constructed in a way that would prevent
gaming, and whether such formulations
would be preferable to the approach
proposed above.
3. Corresponding Changes to the FERC
Form No. 556
111. If the changes to the evaluation
of whether QFs are separate facilities are
implemented as proposed above, the
Commission proposes corresponding
changes to the FERC Form No. 556.
Currently, item 8a of Form No. 556
requires that the applicant identify any
facilities with electrical generating
equipment within one mile of the
instant facility’s electrical generating
equipment, as shown below in Figure 1.
150 See Beaver Creek Wind II, LLC, 160 FERC
¶ 61,052, at P 9 (2017).
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112. The Commission proposes
adding a new item 8b,151 which would
be similar to the current item 8a, except
that it would cover affiliated facilities
whose nearest electrical generating
equipment is greater than 1 mile and
less than 10 miles from the electrical
generating equipment of the instant
facility.
113. The Commission proposes that
the instructions for the new item 8b
would also allow applicants with
facilities identified under item 8b (i.e.,
facilities more than one mile apart and
less than ten miles apart) to, if they
choose, explain (in the Miscellaneous
section starting on page 19 of the form)
why the facilities identified under item
8b should be considered separate
facilities, considering the relevant
physical and ownership factors. We
further propose to provide reference, in
the instructions to the new item 8b, to
the paragraphs of the final rule under
this rulemaking which discuss the
relevant physical and ownership factors
that may be asserted to defend against
rebuttal.
114. The Commission seeks comment
on whether item 8a (existing) should be
revised and item 8b (as newly proposed)
written to require that the applicant
specify the distance from the instant
facility to each affiliated facility listed.
We also seek comment on whether
items 8a and (new) 8b should require
the applicant to document (in the
Miscellaneous section on page 19 of the
Form No. 556) how the distances
reported were calculated. Specifically,
we seek comment on whether the
applicant should be required to identify
the particular electrical generating
equipment and associated geographic
151 Subsequent
items in that section of the form
would be retained, but re-numbered and moved
down accordingly.
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coordinates used in calculating the
distance(s) between the facility(ies).
115. The Commission notes that item
8a currently requires applicants to list
all affiliated ‘‘facilities.’’ Under this
requirement, an applicant would have
to list all affiliated QFs and affiliated
non-QFs. We request comment on
whether such a requirement is more
burdensome than necessary. It is not
clear that requiring the listing of
affiliated non-QFs is necessary in
monitoring for compliance with the
relevant QF regulations, which are
concerned only with the distance
between affiliated QFs. Particularly
under the newly proposed item 8b,
where applicants would list facilities
located more than one mile apart but
less than ten miles apart, many more
facilities are likely to be listed than are
currently listed in the existing item 8a.
As such, we seek comment on whether
we should revise item 8a (existing) and
write item 8b (as newly proposed) to
require that applicants list only
affiliated QFs, or whether there is reason
to continue to require all affiliated
facilities to be listed.
116. The Commission also seeks
comment on whether item 3c
(geographic coordinates) and the
Geographic Coordinates instructions on
page 4 of the current Form No. 556
should be modified such that reporting
of geographic coordinates should be
required for all applications, rather than
only for applications where there is no
facility street address (as is now the
case). We believe such information may
provide more transparency in
approximate distances between
facilities, and that such transparency
may be useful for both the public and
Commission staff in monitoring
compliance with the Commission’s QF
regulations.
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117. We note, as we did in Order No.
732,152 and as we do in the general form
instructions on page 4 of the Form No.
556, that such coordinates can be
obtained through certain free online
map services (with links and
instructions available through the
Commission’s QF website); GPS devices
(including smartphones, which are now
nearly ubiquitous); Google Earth;
property surveys; various engineering or
construction drawings; property deeds;
or municipal or county maps showing
property lines. We also note that the
Commission has a link on its QF web
page (www.ferc.gov/QF) which provides
assistance with determining geographic
coordinates of facilities. As such, we
believe that the burden that would be
created by requiring every QF to provide
geographic coordinates would be
limited. Even so, we seek comment on
whether the value of the information to
the public and the Commission would
outweigh the limited burden.
D. PURPA Section 210(m) Rebuttable
Presumption of Nondiscriminatory
Access to Markets
118. In accordance with PURPA
section 210(m), the PURPA Regulations
permit an electric utility to file an
application with the Commission
requesting relief from the requirement to
enter into new contracts or obligations
to purchase electric energy from a QF if
the Commission finds that a QF has
nondiscriminatory access to certain
markets. As relevant here, the PURPA
Regulations establish a rebuttable
presumption that QFs with a net power
production capacity at or below 20 MW
lack nondiscriminatory access to such
markets. The Commission now proposes
152 Revisions to Form, Procedures, and Criteria for
Certification of Qualifying Facility Status for a
Small Power Production or Cogeneration Facility,
Order No. 732, 130 FERC ¶ 61,214, at P 100 (2010).
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to revise the PURPA Regulations to
reduce the capacity level at which this
presumption attaches for small power
production facilities, but not
cogeneration facilities, from 20 MW to
1 MW.153
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1. Background
119. In 2005, Congress amended
PURPA section 210 to add section
210(m), which was intended to reflect
the fact that organized electric markets
have been created in RTOs/ISOs that
provide alternative markets for sales by
QFs. Section 210(m) provides for
termination of the requirement that an
electric utility enter into a new
obligation or contract to purchase from
a QF if the QF, in fact, has
nondiscriminatory access to certain
defined types of markets.154
120. In Order No. 688, the
Commission identified certain specified
markets as qualifying for section 210(m)
relief from the PURPA mandatory
purchase obligation, provided that QFs,
in fact, have nondiscriminatory access
to such markets.155 Because section
210(m) requires the Commission to
make a final determination on
applications to terminate the
requirement to enter into new
obligations or contracts to purchase
from QFs within 90 days of the
application, the Commission established
certain rebuttable presumptions to make
the processing of the applications
possible given this 90-day action
requirement.
121. As relevant here, one of those
rebuttable presumptions, contained in
§ 292.309(d)(1) of the PURPA
Regulations,156 is that a QF with a net
power production capacity at or below
20 MW does not have
nondiscriminatory access to markets. In
creating this rebuttable presumption,
the Commission found persuasive
arguments that some QFs may, in
practice, not have nondiscriminatory
access to markets in light of their small
size.
122. The Commission noted that there
was agreement among commenters
representing both QFs and utilities that
153 The Commission also proposes to revise the
PURPA Regulations to replace ‘‘Midwest
Independent Transmission System Operator, Inc.
(Midwest ISO)’’ and ‘‘ISO New England, Inc.’’ in 18
CFR 292.309(e), with ‘‘Midcontinent Independent
System Operator, Inc. (MISO)’’ and ‘‘ISO New
England Inc.,’’ respectively.
154 See 16 U.S.C. 824a–3(m).
155 New PURPA Section 210(m) Regulations
Applicable to Small Power Production and
Cogeneration Facilities, Order No. 688, 117 FERC
¶ 61,078, at PP 9–12 (2006), order on reh’g, Order
No. 688–A, 119 FERC ¶ 61,305 (2007), aff’d sub
nom. Am. Forest & Paper Ass’n v. FERC, 550 F.3d
1179 (D.C. Cir. 2008).
156 18 CFR 292.309(d)(1).
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small size could affect a QF’s ability to
access markets.157 The Commission
explained that smaller QFs often are
interconnected at the distribution level
and that QFs interconnected at the
distribution level may, in practice, lack
the same level of access to markets as
those connected to transmission
lines.158 The Commission also
explained that smaller QFs were more
likely to have to overcome obstacles that
larger QFs would not have to overcome,
such as jurisdictional differences,
pancaked delivery rates, and
administrative burdens to obtaining
access to distant buyers.
123. The Commission found that such
difficulties supported a rebuttable
presumption that smaller QFs have
‘‘substantially less ability to access
wholesale markets than do larger
QFs.’’ 159 The Commission further
explained that it set this rebuttable
presumption at 20 MW, rather than at a
much smaller size of one or two MW, to
reflect its understanding of ‘‘the general
nature of QFs’ interconnection practices
and the relative capabilities of small
entities’’ to participate in markets.160
The Commission acknowledged that
‘‘[t]here is no perfect bright line that can
be drawn,’’ but stated that it ‘‘reasonably
exercised [its] discretion in adopting a
20 MW or below demarcation for
purposes of determining which QFs are
unlikely to have nondiscriminatory
access to markets.’’ 161
124. Order No. 688 placed the burden
of proof on the electric utility to
demonstrate that a smaller QF has
nondiscriminatory access to energy
markets.162 The Commission, in Order
No. 688, did not specify what evidence
a utility could set forth to rebut the
presumption, but noted that ‘‘relevant
evidence may include the extent to
which the QF has been participating in
the market or is owned by, or is an
affiliate of, a[n] entity that has been
participating in the relevant market.’’ 163
157 E.g., Order No. 688, 117 FERC ¶ 61,078 at PP
72–73; Order No. 688–A, 119 FERC ¶ 61,305 at P
103.
158 Order No. 688–A, 119 FERC ¶ 61,305 at PP 94–
103.
159 Id. P 96.
160 Id. P 101.
161 Id. P 95.
162 18 CFR 292.310(d)(2) (to the extent an electric
utility seeks relief from the purchase obligation
with respect to a QF 20 MW or smaller, the electric
utility bears burden to prove the QF has
nondiscriminatory access to the wholesale markets).
163 Order No. 688, 117 FERC ¶ 61,078 at P 78. In
saying this, however, the Commission did not
intend to suggest that these two facts alone would
necessarily be a basis for granting relief from
PURPA’s mandatory purchase obligation. PPL Elec.
Utils. Corp., 145 FERC ¶ 61,053, at P 23 & n.25
(2013), order denying reh’g, 148 FERC ¶ 61,207
(2014).
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125. The Commission in Order No.
688 stated that ‘‘[t]here is nothing in
section 210(m) of PURPA to suggest that
Congress intended to ensure a QF’s
commercial viability. Nor does the
statute require the Commission to find
that the ‘economic and technical
equivalent to mandatory purchase is
available through a competitive market’
before it terminates the requirement that
an electric utility enters into a new
contract or obligation to purchase
electric energy from QFs.’’ 164
2. Commission Proposal
126. In 2006, when Order No. 688 was
issued, the organized electric markets
had been in existence for only a few
years and were not well understood by
all market participants. Now, twelve
years later, the markets are more mature,
and the mechanics of participation in
such markets are improved and better
understood. Consequently, the
Commission believes that small power
production facilities below 20 MW
should be able to participate in such
markets under most circumstances. The
Commission therefore proposes to revise
§ 292.309(d) of the PURPA Regulations
to reduce the net power production
capacity level at which the presumption
of nondiscriminatory access to a market
attaches for small power production
facilities, but not cogeneration facilities,
from 20 MW to 1 MW.
127. The Commission believes that, in
light of the maturation of organized
electric markets, such a reduction is
consistent with Congress’s intent to
relieve electric utilities of their
obligation to purchase when a QF has
nondiscriminatory access to competitive
markets. Under current market
conditions, it is fair to expect that small
power production facilities above 1 MW
can acquire the administrative and
technical expertise necessary to obtain
nondiscriminatory access to a market.
128. The Commission, in establishing
the presumption that QFs whose net
power production capacity was 20 MW
or below lacked nondiscriminatory
access to markets defined in sections
210(m)(1)(A)–(C) of PURPA,
acknowledged that ‘‘there is no unique
and distinct megawatt size that uniquely
determines if a generator is small.’’ 165
In using 20 MW to separate the
presumption that large QFs had
nondiscriminatory access and small QFs
lacked such access, the Commission
recognized: (1) Order No. 671’s
exemption for QFs that are 20 MW or
smaller from sections 205 and 206 of the
FPA; and (2) Order Nos. 2006 and 2006–
164 Order
165 Order
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A’s setting 20 MW as the demarcation
for different interconnection standards
between small and large generators.166
While the Commission has not (and
does not here) propose to revise the
exemptions for QFs from sections 205
and 206 of the FPA, the Commission has
taken steps to ease both interconnection
and market access for generation
resources with small capacities since it
first implemented section 210(m) of
PURPA.
129. For example, the Commission
has required public utilities to provide
a Fast-Track interconnection process for
some interconnection customers whose
capacity is up to and including 5 MW
(up from the previous 2 MW
threshold),167 and has required each
RTO/ISO to revise its tariff to include a
participation model for electric storage
resources that establishes a minimum
size requirement for participation in the
RTO/ISO markets that does not exceed
100 kW.168 While both of these changes
do not apply only to generation types
that could become QFs or to RTOs/ISOs,
we believe they generally show that
small power production facilities below
20 MW, specifically those whose
capacity exceeds 1 MW now have
greater access to the markets defined in
section 210(m)(1) of PURPA than they
did when the Commission first
established the presumptions of market
access. Under this proposal, like QFs
over 20 MW today, small power
production facilities over 1 MW would
be able to rebut the presumption of
access due to operational characteristics
or transmission constraints.169
130. The Commission does not
propose to make the same reduction
166 See Order No. 688, 117 FERC ¶ 61,078 at P 76,
order on reh’g, Order No. 688–A, 119 FERC ¶ 61,305
at P 97; see also 18 CFR 292.601(c)(1) (‘‘sales of
energy or capacity made by qualifying facilities 20
MW or smaller, or made pursuant to a contract
executed on or before March 17, 2006 or made
pursuant to a state regulatory authority’s
implementation of section 210, the Public Utility
Regulatory Policies Act of 1978, 16 U.S.C. 824a–1,
shall be exempt from scrutiny under sections 205
and 206’’); Revised Regulations Governing Small
Power Production and Cogeneration Facilities,
Order No. 671, 114 FERC ¶ 61,102, at P 98 (2006),
order on reh’g, Order No. 671–A, 115 FERC ¶ 61,225
(2006) (establishing exemption for QFs 20 MW or
below from 205 and 206 of FPA); Standardization
of Small Generator Interconnection Agreements and
Procedures, Order No. 2006, 111 FERC ¶ 61,220, at
P 75, order on reh’g, Order No. 2006–A, 113 FERC
¶ 61,195 (2005), order granting clarification, Order
No. 2006–B, 116 FERC ¶ 61,046 (2006).
167 Small Generator Interconnection Agreements
and Procedures, Order No. 792, 145 FERC ¶ 61,159,
at P 103 (2013), clarifying, Order No. 792–A, 146
FERC ¶ 61,214 (2014).
168 Electric Storage Participation in Markets
Operated by Regional Transmission Organizations
and Independent System Operators, Order No. 841,
162 FERC ¶ 61,127, at P 265 (2018).
169 See 18 CFR 292.309(c), (e), (f).
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applicable to cogeneration facilities.
Unlike small power production
facilities, which are constructed solely
to produce and sell electricity,
cogeneration facilities seeking QF
certification after February 2, 2006 are
statutorily required to show that they
are intended primarily to provide heat
for an industrial, commercial,
residential or institutional process
rather than fundamentally for sale to an
electric utility.170 Consequently, the
production and sale of electricity is a
byproduct of these processes, and
owners of cogeneration facilities might
not be as familiar with energy markets
and the technical requirements for such
sales. Retention of the existing 20 MW
level for the presumption of access to
markets therefore would be appropriate
for cogeneration facilities.
3. Reliance on RFPs and Liquid Market
Hubs To Terminate Purchase Obligation
131. NARUC has proposed that the
Commission allow utilities to rely on
RFPs (in combination with liquid
market hubs) to establish eligibility to
terminate a utility’s purchase obligation
pursuant to PURPA section
210(m)(1)(C).171 After describing
generally how such a proposal might be
structured, NARUC suggests that ‘‘[t]he
Commission should create a yardstick of
characteristics that describe in detail
how a utility could qualify for an
exemption under subparagraph (C).’’ 172
132. Under the PURPA Regulations,
electric utilities already may seek to
terminate their mandatory purchase
obligation pursuant to PURPA section
210(m)(1)(C) by demonstrating that a
particular market is of comparable
competitive quality to markets
described in PURPA section
210(m)(1)(A) and (B).173 The current
170 See
16 U.S.C. 824a–3(n); 18 CFR 292.205(d)(3).
We recognize that cogeneration facilities seeking
certification 5 MW or smaller after February 2, 2006
are presumed to satisfy this requirement. 18 CFR
292.205(d)(4).
171 See NARUC Supplemental Comments, Docket
No. AD16–16–000 (Oct. 17, 2018).
172 Id., attach. A at 9.
173 Order No. 688–A, 119 FERC ¶ 61,305 at P 43
(‘‘Congress believed the two types of markets
identified in subparagraphs (A) and (B), while
distinct between themselves, contain certain
competitive qualities that justify termination of the
purchase requirement for any QF with
nondiscriminatory access to those markets.
Subparagraph (C) directs the Commission to
consider these competitive qualities when
analyzing whether there are other markets that,
while not meeting the specific requirements of
subparagraphs (A) and (B), are sufficiently
competitive to justify termination of the purchase
requirement.’’); cf. Pub. Serv. Co. of N.M., 140 FERC
¶ 61,191, at PP 29–38 (2012) (denying application
to terminate mandatory purchase obligation on the
grounds that the Four Corners Hub is not of
comparable competitive quality to markets in
sections 210(m)(1)(A) and (B) of PURPA).
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PURPA Regulations are not prescriptive
about how an electric utility must make
such a demonstration and nothing in the
PURPA Regulations or precedent would
bar an electric utility from arguing that
RFPs in combination with liquid market
hubs are sufficient to satisfy PURPA
section 210(m)(1)(C).
133. The Commission believes that a
properly structured proposal along the
lines proposed by NARUC potentially
could satisfy the statutory requirements
under PURPA section 210(m)(1)(C) and
will consider such proposals on a caseby-case basis. Although the Commission
does not in this NOPR propose
additional criteria a utility or utilities
may rely on to satisfy PURPA section
210(m)(1)(C), the Commission seeks
comments on any specific factors that
would be useful to consider in
determining how a utility or utilities
may satisfy PURPA section
210(m)(1)(C).
E. Legally Enforceable Obligation
134. Section 292.304(d) of the PURPA
Regulations provides that a QF can
choose to have its rates based on the
avoided cost calculated at the time of
delivery or at the time a LEO is
incurred. However, the PURPA
Regulations do not specify when or how
a LEO is established.174 To date, the
Commission has not identified specific
criteria that states must follow in
determining when a LEO is established.
135. Although not specifying such
criteria, the Commission has found that
certain prerequisites to QFs obtaining a
LEO imposed by some states—such as a
utility’s execution of an interconnection
agreement or power purchase
agreement—are unreasonable.175 The
174 But see, e.g., FLS, 157 FERC ¶ 61,211 at P 23
(‘‘[R]equiring a QF to tender an executed
interconnection agreement is equally inconsistent
with PURPA and our regulations. Such a
requirement allows the utility to control whether
and when a legally enforceable obligation exists—
e.g., by delaying the facilities study or by delaying
the tendering by the utility to the QF of an
executable interconnection agreement.’’);
Memorandum of Agreement between Idaho Public
Utilities Commission and Federal Energy
Regulatory Commission at 2 (Dec. 24, 2013),
available at https://www.ferc.gov/legal/mou/mouidaho-12-2013.pdf (Idaho Commission
acknowledging that ‘‘a legally enforceable
obligation may be incurred prior to the formal
memorialization of a contract to writing’’).
175 See, e.g., FLS, 157 FERC ¶ 61,211 at P 26
(requiring signed interconnection agreement as
prerequisite to legally enforceable obligation is
inconsistent with PURPA Regulations); Grouse
Creek Wind Park, LLC, 142 FERC ¶ 61,187, at P 40
(2013) (Grouse Creek) (finding that requiring a QF
to file complaint as prerequisite to a legally
enforceable obligation is inconsistent with PURPA
Regulations); Murphy Flat Power, LLC, 141 FERC
¶ 61,145, at P 24 (2012) (finding that requiring a
signed and executed contract with an electric utility
as a prerequisite to a legally enforceable obligation
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Commission does not propose to
overturn this precedent because the
Commission continues to believe that
imposition of the prerequisites
addressed in its precedent is
unreasonable and does not satisfy
PURPA’s requirement that the
Commission prescribe rules as
necessary to encourage the development
of QFs.
136. As discussed below, however,
the Commission proposes to amend
§ 292.304(d) of the PURPA Regulations
to require that a QF demonstrate its
commercial viability and financial
commitment to construct its facility
through objective and reasonable statedetermined criteria before being entitled
to a LEO.
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1. Background and Need for Reform
137. The Commission created the
concept of a LEO in Order No. 69 ‘‘to
prevent a utility from circumventing the
requirement that provides capacity
credit for an eligible qualifying facility
merely by refusing to enter into a
contract with the qualifying facility.’’ 176
The Commission has held that requiring
a fully-executed contract or executed
interconnection agreement as a
condition precedent to obtaining a LEO
is inconsistent with PURPA.177
138. The record indicates that some
QFs believe that informing a utility that
the QF intends to sell energy to that
utility at some point in the future is
sufficient to create a LEO and thereby
establish the price for future deliveries,
regardless of whether the QF project
being considered ever generates
electricity.178 This approach, Xcel
explains, puts the electric utility and its
customers at risk since the utility is
required to reliably plan its system and
resources for a QF that will not be
operational for many years, or not at all,
thereby creating uncertainty for the
utility and its consumers.179 Conversely,
is inconsistent with PURPA Regulations); Rainbow
Ranch Wind, LLC, 139 FERC ¶ 61,077 (2012) (same);
Cedar Creek Wind, LLC, 137 FERC ¶ 61,006, at P 36
(2011) (Cedar Creek) (same).
176 Order No. 69, FERC Stats. & Regs. ¶ 30,128 at
30,880.
177 FLS, 157 FERC ¶ 61,211 at P 26; Cedar Creek,
137 FERC ¶ 61,006 at P 35.
178 See, e.g., EEI Supplemental Comments, attach.
A at 7.
179 See Xcel Comments, Docket No. AD16–16–
000, at 15–16 (Nov. 7, 2016) (‘‘If a utility is required
to enter into a LEO with a QF, it will (or may be
required to) factor the capacity associated with that
LEO into its resource planning efforts. And if that
project does not materialize—for whatever reason—
the utility’s resource plan will need to change.
Depending on the amount of capacity associated
with the LEO or LEOs that the utility has pending,
the utility may have to scramble to replace the
capacity associated with the now non-existent
LEO(s). Such a scramble would very likely result in
payment of above-market prices for capacity and
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QF developers argue generally that they
need the certainty of a LEO to obtain the
financing to build their facilities in the
first place, as QFs do not have the same
ability that the electric utilities have to
‘‘rate base’’ their facilities and, thereby,
guarantee capital recovery.180
139. While it is up to states to
reasonably determine the circumstances
and thus when a legally enforceable
obligation arises,181 states may not
impose obstacles that make it
unreasonably difficult to obtain a
LEO.182 Given the significant changes in
the electric industry since PURPA’s
enactment, as discussed above, the
Commission finds that it now may be
appropriate to: (1) Specify the
commercial viability of a QF and
financial commitment to construct the
proposed project as the necessary prerequisites for obtaining a LEO; and (2)
provide guidance for states as to what
energy, again violating the indifference standard.
Moreover, additional capacity over and above the
capacity associated with the non-existent QF might
have been procured, at additional cost to customers,
to manage the variability of that anticipated QF. Of
greater concern would be a situation where
additional capacity is simply not available to make
up for the capacity that the QF was expected to
provide under the LEO, putting system reliability at
risk and potentially putting the utility at risk of
violations of NERC reliability standards approved
by the Commission. Further, attempting to lock in
long-term prices far in advance of the start date of
deliveries under a LEO creates significant potential
for payments in excess of avoided cost rates.’’).
180 Compare EEI Supplemental Comments, attach.
A at 7 with Renewable Energy Coalition Comments,
Docket No. AD16–16–000, at 11–12 (Nov. 7, 2016)
(‘‘Long-term contracts allow existing QFs to remain
economically viable in times of long resource
sufficiency periods with low avoided cost
rates. . . . Unlike utilities, which can spread the
costs of resource acquisition over the entire useful
life of a facility, QFs do not have this option
because doing so could expose ratepayers to
unnecessary risk from deviations in avoided
costs.’’); and Northwest and Intermountain Power
Producers Coalition Comments, Docket No. AD16–
16–000, at 5 (Nov. 4, 2016) (‘‘To earn a return on
investment, there must first be the prospect of a
return on investment. It takes at least 15 years in
most cases involving [Northwest and Intermountain
Power Producers Coalition] members to recover
their invested capital and to retire the debt incurred
to build a renewable energy facility. It takes a
contract term of 20 years to earn a justifiable return
on that investment.’’).
181 W. Penn Power Co., 71 FERC ¶ 61,153, at
61,495 (1995) (West Penn) (‘‘It is up to the States,
not this Commission, to determine the specific
parameters of individual QF power purchase
agreements, including the date at which a legally
enforceable obligation is incurred under State law.
Similarly, whether the particular facts applicable to
an individual QF necessitate modifications of other
terms and conditions of the QF’s contract with the
purchasing utility is a matter for the States to
determine. This Commission does not intend to
adjudicate the specific provisions of individual QF
contracts.’’ (footnotes omitted)).
182 See, e.g., Cedar Creek, 137 FERC ¶ 61,006 at
P 35 & n.57 (citing West Penn, 71 FERC ¶ 61,153
at 61,495).
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53265
types of criteria may be applied to make
the necessary demonstration.
2. Commission Proposal
140. The Commission proposes to add
regulatory text in § 292.304(d)(3) of the
PURPA Regulations to require QFs to
demonstrate that a proposed project is
commercially viable and the QF has a
financial commitment to construct the
proposed project pursuant to objective,
reasonable, state-determined criteria in
order to be eligible for a LEO. The
Commission further proposes to provide
that, although a showing of commercial
viability and the QF’s financial
commitment to construct the project is
required, states have flexibility as to
what constitutes an acceptable showing
of commercial viability and financial
commitment.
141. Our objective in requiring a
showing of commercial viability and the
QF’s financial commitment to construct
the project is to ensure that no electric
utility obligation is triggered for those
QF projects that are not sufficiently
advanced in their development and,
therefore, for which it would be
unreasonable for a utility to include in
its resource planning, while at the same
time ensuring that the purchasing utility
does not unilaterally and unreasonably
decide when its obligation arises. States
may require a showing, for example,
that a QF has satisfied, or is in the
process of undertaking, at least some of
the following prerequisites: (1)
Obtaining site control adequate to
commence construction of the project at
the proposed location; (2) filing an
interconnection application with the
appropriate entity; (3) securing local
permitting and zoning; or (4) other
similar, objective, reasonable criteria
that allow a QF to demonstrate its
commercial viability and financial
commitment to construct the facilities.
These indicia are not intended to be
exhaustive and the Commission seeks
comment on these indicia and others
that also might be appropriate for
consideration.
142. We believe requiring QFs to
demonstrate their commercial viability
and financial commitment to construct
the facilities based on such indicia
before obtaining a LEO will allow
electric utilities to reliably plan for their
systems ensuring resource adequacy.
Additionally, states’ development and
definition of objective and reasonable
factors to determine commercial
viability and financial commitment to
construct a facility encourage the
development of QFs by providing QFs
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Federal Register / Vol. 84, No. 193 / Friday, October 4, 2019 / Proposed Rules
with more certainty as to when they will
obtain a LEO.183
F. QF Certification Process
1. Background and Need for Reform
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143. The Commission provides two
paths for an entity to obtain QF status:
self-certification and Commission
certification.184 Self-certification, the
procedures for which are contained in
§ 292.207(a) of the PURPA
Regulations,185 is the more common
method of certification. When an
applicant self-certifies (or selfrecertifies), it certifies that its facility
satisfies the requirements for QF status.
Under the self-certification (or selfrecertification) approach a QF is
assigned a docket number, and
Commission staff reviews the filing to
discern that the information required in
Form No. 556 appears to have been
included, but a notice of the selfcertification typically is not published
in the Federal Register and Commission
staff does not otherwise evaluate
whether the applicant meets the
requirements for QF status.
144. The Commission recognized that
the self-certification process may not
always satisfy the needs of certain
stakeholders or interested entities.
Accordingly, the Commission
established, in § 292.207(b) of the
PURPA Regulations,186 what is called
the ‘‘optional procedure’’ for QF status.
Under the optional procedure, an entity
may file an application for a
determination by the Commission that a
facility meets the requirements for QF
status. The application is noticed in the
Federal Register, the Commission
decides whether the applicant meets the
requirements for QF status, and then
183 Because QFs already in operation have
necessarily demonstrated a commitment to
construct the project, the Commission does not
intend commercial viability and financial
commitment requirements to serve as prerequisites
to QFs already in operation with existing LEOs to
obtaining new LEOs.
184 There is no fee for a self-certification; there is,
however, a fee for Commission certification. 18 CFR
381.505. For 2018, an application for Commission
certification requires a filing fee of $23,330 for
small power production facilities and $26,410 for
cogeneration facilities. In recent years, the
Commission has received approximately 5
applications per year for Commission-certification,
with the remaining applicants (approximately 3,400
per year) filing for self-certification of their
facilities. See Commission Information Collection
Activities, Notice of information Collection and
Request for Comments, Docket No. IC19–16–000, 84
FR 9317, 9318 (Mar. 7, 2019). The Commission will
not issue notice of nor process an application for
Commission certification without receipt of the
applicable fee.
185 18 CFR 292.207(a).
186 18 CFR 292.207(b).
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issues an order either granting or
denying the requested certification.
145. After the enactment of EPAct
2005, which imposed new requirements
for QF status for ‘‘new’’ cogeneration
facilities,187 the Commission issued
Order No. 671,188 which implemented
new requirements for QF status
including a formal filing requirement for
all QFs claiming QF status whether
through self-certification or Commission
certification.189 As part of that
implementation, for the first time,
notices of some (but not all) selfcertifications were required to be
published in the Federal Register.
Specifically, § 292.207(a)(iv) provides
that self-certifications or selfrecertifications, other than for ‘‘new’’
cogeneration facilities, would not be
published in the Federal Register. In
2010, in Order No. 732, the Commission
adopted an exemption from the filing
requirement for generating facilities
with net power production capacities of
1 MW or less.190
146. The Commission has explained
that, to challenge the self-certification of
a QF, an entity must file a petition for
declaratory order and pay the associated
filing fee, which currently is $28,990.
The Commission in Chugach Electric
Association, Inc. explained that Order
No. 671 did not create a right for a
challenging entity to submit a motion
for revocation in response to a notice of
self-certification. Rather, the
Commission explained that QF selfcertification is effective upon filing, and
therefore challenging a self-certification
requires a separate petition for
declaratory order asking that the
Commission revoke QF status.191
147. A concern with the existing
procedures with respect to selfcertification is whether protestors
should bear the burden of filing a
separate petition for declaratory order
and paying the associated filing fee for
187 ‘‘New’’ cogeneration facilities are defined as
any cogeneration facility that was either not
certified a qualifying cogeneration facility on or
before August 8, 2005, or that had not filed a notice
of self-certification, self-recertification or an
application for Commission certification or
Commission recertification as a qualifying
cogeneration facility prior to February 2, 2006. 18
CFR 292.205(d)(1).
188 Order No. 671, 114 FERC ¶ 61,102, order on
reh’g, Order No. 671–A, 115 FERC ¶ 61,225 (2006).
189 See 18 CFR 292.203(a)(3), (b)(2).
190 Revisions to Form, Procedures, and Criteria for
Certification of Qualifying Facility Status for a
Small Power Production or Cogeneration Facility,
Order No. 732, 130 FERC ¶ 61,214 (2010).
191 Chugach Elec. Assoc., Inc., 121 FERC ¶ 61,287,
at PP 51–54 (2007); see also Hydro Investors, Inc.
v. Trafalgar Power, Inc., 94 FERC ¶ 61,207, at
61,780, reh’g denied, 95 FERC ¶ 61,120 (2001).
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a declaratory order to object to a
questionable self-certification.192
2. Commission Proposal
148. The Commission proposes to
change § 292.207(a) of the PURPA
Regulations to allow a party to intervene
and to file a protest of a self-certification
or self-recertification of a facility
without the necessity of filing a separate
petition for declaratory order and
without having to pay the filing fee
required for a declaratory order. Because
an applicant for self-certification or selfrecertification is required to serve a
copy of its submission on interested
electric utilities (principally those it is
interconnected with and those it will be
selling to) as well as the relevant state
regulatory authorities, the Commission
will allow interested persons 30 days
from the date of filing at the
Commission to intervene and/or to file
a protest (without paying a filing fee).193
149. Any party submitting a protest
would have the burden of specifying
facts that make a prima facie
demonstration that the facility described
in the self-certification or selfrecertification does not satisfy the
requirements for QF status.194 General
allegations that the facility is not a QF
without reference to the specific
regulatory provision that has not been
satisfied (and without an explanation
why the provision has not been
satisfied), or unsupported assertions
that the self-certification does not satisfy
an aspect of the PURPA Regulations,
would not satisfy this burden and
would not be a basis for denial of
certification. However, if this prima
facie burden is met, then the burden
would shift to the applicant submitting
the self-certification or selfrecertification to demonstrate that the
claims raised in the protest are incorrect
and that certification is, in fact,
warranted.
150. As explained above, QF selfcertification is effective upon filing, and
remains effective if a protest is filed,
until such time as the Commission rules
that certification is revoked. The
Commission proposes that it would
issue an order within 90 days of the date
the protest is filed. The Commission
also reserves the right to request more
information from the protester, the
entity seeking QF status, or both.195 If
192 EEI
Supplemental Comments, attach. A at 16.
CFR 292.207(c)(1).
194 See 18 CFR 385.211.
195 Such information requests could be issued by
the Commission or by staff under any applicable
delegated authority. For example, the Director of
the Office of Energy Market Regulation is
authorized under 18 CFR 375.307(b)(3)(ii) to
‘‘[i]ssue and sign requests for additional
193 18
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the Commission requests more
information, the time period for the
Commission order would be extended to
60 days from the filing of a complete
answer to the information request.
151. There may be instances,
however, when the Commission needs
additional time to review the record in
light of the nature of the protests. In
those cases, the Commission proposes
that, in addition to any extension
resulting from a request for information,
the Commission also may toll the 90day period during which the
Commission commits to act for one
additional 60-day period. The
Commission proposes to delegate to the
Commission’s Secretary, or the
Secretary’s designee, the authority to
toll the 90-day period for this purpose.
152. The Commission believes these
procedures will allow for timely but
thorough review of protested selfcertifications and re-certifications. The
Commission seeks comment on whether
these procedures impose an undue
burden on the QF even though the QF
remains certified pending the review.
III. Information Collection Statement
153. The Paperwork Reduction Act 196
requires each federal agency to seek and
obtain the Office of Management and
Budget’s (OMB) approval before
undertaking a collection of information
(including reporting, record keeping,
and public disclosure requirements)
directed to ten or more persons or
contained in a rule of general
applicability. OMB regulations require
approval of certain information
collection requirements contemplated
by proposed rules (including deletion,
revision, or implementation of new
requirements).197 Upon approval of a
collection of information, OMB will
assign an OMB control number and an
expiration date. Respondents subject to
the filing requirements of a rule will not
be penalized for failing to respond to the
collection of information unless the
collection of information displays a
valid OMB control number.
Public Reporting Burden: In this
NOPR, the Commission proposes to
revise its regulations implementing
PURPA. The principal changes that
affect information collection, i.e., the
Form No. 556, are as follows: first, the
Commission proposes to change 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, by allowing
electric utilities, state regulatory
authorities, or other interested parties to
show that facilities over one and less
than ten miles apart actually are a single
facility; and second, to allow a party to
protest a self-certification or selfrecertification of a facility without a fee.
The estimated changes to the burden
and cost 198 of the information
collection affected by this NOPR, i.e.,
Form No. 556, follow.
FERC–556, AS MODIFIED BY THE NOPR IN DOCKET NOS. RM19–15–000 AND AD16–16–000
Facility type
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Cogeneration Facility > 1
MW.
Cogeneration Facility > 1
MW.
Small Power Production
Facility > 1 MW, > 1
Mile, < 10 Miles from Affiliated Facility.
Small Power Production
Facility > 1 MW, > 1
Mile, < 10 Miles from Affiliated Facility.
Cogeneration and Small
Power Production Facility ≤ 1 MW (Self-Certification) 199.
Small Power Production
Facility > 1 MW, ≤ 1 Mile
from Affiliated Facility.
Small Power Production
Facility > 1 MW, ≤ 1 Mile
from Affiliated Facility.
Small Power Production
Facility > 1 MW, ≥ 10
Miles from Affiliated Facility.
Small Power Production
Facility > 1 MW, ≥ 10
Miles from Affiliated Facility.
Total ...........................
Number of
respondents
Annual
number of
responses per
respondent
Total
number of
responses
Average
burden hours
& cost per
response
Total annual burden hours
& total annual
cost
Cost per
respondent
($)
(1)
(2)
(1) * (2) = (3)
(4)
(3) * (4) = (5)
(5) ÷ (1)
Self-certification
10 ...................
1.25 ................
12.5 ................
8 hrs.; $632 ....
100 hrs.; $7,900 ..................
$790.
Application for
FERC certification.
Self-certification
1 .....................
1.25 ................
1.25 ................
55 hrs.; $4,345
68.75 hrs.; $5,431.25 ..........
$5,431.25.
20 ...................
1.25 ................
25 ...................
8 hrs.; $632 ....
200 hrs.; $15,800 ................
$790.
Application for
FERC certification.
1 .....................
1.25 ................
1.25 ................
55 hrs.; $4,345
68.75 hrs.; $5,431.25 ..........
$5,431.25.
Self-certification
312 .................
1.25 ................
390 .................
4 hrs.; $316 ....
1,560 hrs.; $123,240 ...........
$395.
Self-certification
no change ......
no change ......
no change ......
no change ......
no change ............................
no change.
Application for
FERC certification.
Self-certification
1 .....................
1.25 ................
1.25 ................
55 hrs.; $4,345
68.75 hrs.; $5,431.25 ..........
$5,431.25.
1,980 ..............
1.25 ................
2,475 ..............
8 hrs.; $632 ....
19,800 hrs.; $1,564,200 ......
$790.
Application for
FERC certification.
no change ......
no change ......
no change ......
no change ......
no change ............................
no change.
........................
........................
........................
........................
22,235 hrs.; $1,727,433.75
Filing type
.....................
information regarding applications, filings, reports
and data processed by the Office of Energy Market
Regulation.’’
196 44 U.S.C. 3501–21.
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197 See
5 CFR 1320.11.
burden costs are based on FERC’s 2018
average annual salary plus benefits of $164,820 (or
$79/hour). The Commission believes that industry
198 The
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is similarly situated in terms of staff costs and skill
sets.
199 Not required to file.
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Title: FERC–556, Certification of
Qualifying Facility (QF) Status for a
Small Power Production or
Cogeneration Facility.
Action: Revisions to existing
collection FERC–556.
OMB Control No.: 1902–0075.
Respondents: Facilities that are selfcertifying their status as a cogenerator or
small power producer or that are
submitting an application for
Commission certification of their status
as a cogenerator or small power
producer; and electric utilities, state
regulatory authorities, or other entities
submitting comments on, or protests to,
the self-certification or application for
Commission certification.
Frequency of Information: Ongoing.
Necessity of Information: The
Commission proposes the changes in
this NOPR in order to revise its
implementation of PURPA in light of
changes in the electric industry since
the enactment of PURPA in 1978.
Internal Review: The Commission has
reviewed the proposed changes and has
determined that such changes are
necessary. These requirements conform
to the Commission’s need for efficient
information collection, communication,
and management within the energy
industry.
Interested persons may obtain
information on the reporting
requirements by contacting the Federal
Energy Regulatory Commission, 888
First Street NE, Washington, DC 20426
[Attention: Ellen Brown, Office of the
Executive Director], by email to
DataClearance@ferc.gov, by phone (202)
502–8663, or by fax (202) 273–0873.
Comments concerning the collection
of information and the associated
burden estimate may also be sent to:
Office of Information and Regulatory
Affairs, Office of Management and
Budget, 725 17th Street NW,
Washington, DC 20503 [Attention: Desk
Officer for the Federal Energy
Regulatory Commission]. Due to
security concerns, comments should be
sent electronically to the following
email address: oira_submission@
omb.eop.gov. Comments submitted to
OMB should refer to FERC–556 and
OMB Control No. 1902–0075.
IV. Environmental Analysis
154. The Commission is required to
prepare an Environmental Assessment
(EA) or an Environmental Impact
Statement (EIS) for any action that may
have a significant adverse effect on the
quality of the human environment.200
200 Regulations Implementing the National
Environmental Policy Act, Order No. 486, FERC
Stats. & Regs. ¶ 30,783 (1987) (cross-referenced at 41
FERC ¶ 61,284).
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Whether and how the revisions
proposed here, however, would affect
QF development and the environment is
speculative.
155. The proposed changes to the
PURPA Regulations do not authorize or
fund particular QFs, nor do they license
QFs or issue permits for QFs to operate.
They do not authorize or prohibit a
generator’s use of any particular
technologies or fuels, nor do they
mandate or limit where QFs should or
should not be built. They do not exempt
QFs from any Federal, state or local
environmental, siting, or other similar
laws or regulatory requirements. And
while the Commission establishes
factors that are to be taken into account
by the states in setting QF rates, it is the
states and not the Commission that set
QF rates. It is impossible to know what
actions the states may take in response
to the revisions proposed here, and how
any such actions would, on balance,
impact QF development and the
environment going forward—especially
given that QFs include not only
renewable resources such as solar and
wind resources but also renewable
resources that, per Congress’ directive,
depend on waste (such as waste coal) as
an energy input 201 and cogeneration
that often depends on fossil fuels as an
energy input.202 Moreover, as explained
above, PURPA requires that the
Commission must prescribe, and from
time to time thereafter revise, such rules
as the Commission determines
necessary to encourage QFs,203 and the
Commission’s rules as revised as
proposed here would continue to
encourage QFs. Given these facts any
environmental impacts analysis of the
revisions proposed here would be
speculative and not meaningfully
inform the Commission or the public of
the revisions’ impact on QF
development or, correspondingly, of any
associated potential impacts on the
environment; there are, in short, no
reasonably foreseeable environmental
impacts for the Commission to
consider.204 Therefore, the Commission
will not prepare an environmental
document.
201 16 U.S.C. 796(17); 18 CFR 292.202(b),
292.204(b).
202 16 U.S.C. 796(18); 18 CFR 292.205.
203 16 U.S.C. 824a–3(a).
204 While courts have held that NEPA requires
‘‘reasonable forecasting,’’ an agency is not required
‘‘to engage in speculative analysis’’ or ‘‘to do the
impractical, if not enough information is available
to permit meaningful consideration.’’ N. Plains Res.
Council v. Surface Transp. Board, 668 F.3d 1067,
1078 (9th Cir. 2011).
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V. Regulatory Flexibility Act
Certification
156. The Regulatory Flexibility Act of
1980 (RFA) 205 generally requires a
description and analysis of proposed
rules that will have significant
economic impact on a substantial
number of small entities. In lieu of
preparing a regulatory flexibility
analysis, an agency may certify that a
proposed rule will not have a significant
economic impact on a substantial
number of small entities.206
157. The Small Business
Administration’s (SBA) Office of Size
Standards develops the numerical
definition of a small business.207 The
SBA size standard for electric utilities is
based on the number of employees,
including affiliates.208 Under SBA’s
current size standards, the threshold for
a small entity (including its affiliates) is
250 employees for cogeneration and
small power production applicants in
the following NAICS 209 categories:
• NAICS code 221114 for Solar Electric
Power Generation
• NAICS code 221115 for Wind Electric
Power Generation
• NAICS code 221116 for Geothermal
Electric Power Generation
• NAICS code 221117 for Biomass
Electric Power Generation
• NAICS code 221118 for Other Electric
Power Generation
The threshold for a small entity
(including its affiliates) is 500
employees for NAICS code 221111 for
Hydroelectric Power Generation.
This proposed rule directly affects
QFs, the majority of which the
Commission estimates are small
businesses. But, as reflected in the
burden and cost estimates provided
above, the Commission does not
anticipate that any additional reporting
burden or cost imposed on QFs,
regardless of their status as a small or
large business, would be significant.210
The proposed revisions may result in
additional information being submitted
205 5
U.S.C. 601–12.
U.S.C. 605(b).
207 13 CFR 121.101.
208 SBA Final Rule on ‘‘Small Business Size
Standards: Utilities,’’ 78 FR 77,343 (Dec. 23, 2013).
209 The North American Industry Classification
System (NAICS) is an industry classification system
that Federal statistical agencies use to categorize
businesses for the purpose of collecting, analyzing,
and publishing statistical data related to the U.S.
economy. United States Census Bureau, North
American Industry Classification System, https://
www.census.gov/eos/www/naics/ (accessed April
11, 2018).
210 The average cost per response is estimated to
be $594.39 (or $1,727,433.75/2,906.25 responses).
206 5
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Federal Register / Vol. 84, No. 193 / Friday, October 4, 2019 / Proposed Rules
by some small power production QF
applicants and self-certifiers (those with
affiliated small power production
facilities using the same fuel source
located over one and less than ten miles
away, and with a combined total
capacity greater than 80 MW). The
Commission estimates that less than ten
percent of QF applications and selfcertifications meet these criteria.
158. Accordingly, pursuant to section
605(b) of the RFA, the Commission
certifies that this proposed rule will not
have a significant economic impact on
a substantial number of small entities.
VI. Comment Procedures
159. The Commission invites
interested persons to submit comments
on the matters and issues proposed in
this notice to be adopted, including any
related matters or alternative proposals
that commenters may wish to discuss.
Comments are due December 3, 2019.
Comments must refer to Docket No.
RM19–15–000 and AD16–16–000, and
must include the commenter’s name,
the organization they represent, if
applicable, and their address in their
comments.
160. The Commission encourages
comments to be filed electronically via
the eFiling link on the Commission’s
website at https://www.ferc.gov. The
Commission accepts most standard
word processing formats. Documents
created electronically using word
processing software should be filed in
native applications or print-to-PDF
format and not in a scanned format.
Commenters filing electronically do not
need to make a paper filing.
161. Commenters that are not able to
file comments electronically must send
an original of their comments to:
Federal Energy Regulatory Commission,
Secretary of the Commission, 888 First
Street NE, Washington, DC 20426.
162. All comments will be placed in
the Commission’s public files and may
be viewed, printed, or downloaded
remotely as described in the Document
Availability section below. Commenters
on this proposal are not required to
serve copies of their comments on other
commenters.
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VII. Document Availability
163. In addition to publishing the full
text of this document in the Federal
Register, the Commission provides all
interested persons an opportunity to
view and/or print the contents of this
document via the internet through the
Commission’s Home Page (https://
www.ferc.gov) and in the Commission’s
Public Reference Room during normal
business hours (8:30 a.m. to 5:00 p.m.
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Eastern time) at 888 First Street NE,
Room 2A, Washington, DC 20426.
164. From the Commission’s Home
Page on the internet, this information is
available on eLibrary. The full text of
this document is available on eLibrary
in PDF and Microsoft Word format for
viewing, printing, and/or downloading.
To access this document in eLibrary,
type the docket number excluding the
last three digits of this document in the
docket number field.
165. User assistance is available for
eLibrary and the Commission’s website
during normal business hours from the
Commission’s Online Support at 202–
502–6652 (toll free at 1–866–208–3676)
or email at ferconlinesupport@ferc.gov,
or the Public Reference Room at (202)
502–8371, TTY (202) 502–8659. Email
the Public Reference Room at
public.referenceroom@ferc.gov.
List of Subjects in 18 CFR Part 292
Electric power; Electric power plants;
Electric utilities.
By direction of the Commission.
Commissioner Glick is dissent in part with a
separate statement attached.
Issued: September 19, 2019.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
In consideration of the foregoing, the
Commission proposes to amend Parts
292 and 375, Chapter I, Title 18, Code
of Federal Regulations, as follows.
PART 292—REGULATIONS UNDER
SECTIONS 201 AND 210 OF THE
PUBLIC UTILITY REGULATORY
POLICIES ACT OF 1978 WITH REGARD
TO SMALL POWER PRODUCTION AND
COGENERATION
1. The authority citation for part 292
continues to read as follows:
■
Authority: 16 U.S.C. 791a–825r, 2601–
2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352.
2. Amend § 292.101 by adding
paragraphs (b)(12) through (16) to read
as follows:
■
§ 292.101
Definitions.
*
*
*
*
*
(b) * * *
(12) Locational marginal price means
the price for energy at a particular
location as determined in a market
defined in § 292.309(e), (f), or (g).
(13) Competitive Price means a Market
Hub Price or a Combined Cycle Price.
(14) Market Hub Price means a price
for as-delivered energy determined
pursuant to § 292.304(b)(7)(i).
(15) Combined Cycle Price means a
price for as-delivered energy determined
pursuant to § 292.304(b)(7)(ii).
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(16) Competitive Solicitation Price
means a price for energy and/or capacity
determined pursuant to § 292.304(b)(8).
■ 3. Amend § 292.202 by adding
paragraph (t) to read as follows:
§ 292.202
Definitions.
*
*
*
*
*
(t) Electrical generating equipment
means all boilers, heat recovery steam
generators, prime movers (any
mechanical equipment driving an
electric generator), electrical generators,
photovoltaic solar panels and/or
inverters, fuel cell equipment and/or
other primary power generation
equipment used in the facility,
excluding equipment for gathering
energy to be used in the facility.
■ 4. Amend § 292.204 by revising
paragraph (a) to read as follows:
§ 292.204 Criteria for qualifying small
power production facilities.
(a) Size of the facility—(1) Maximum
size. Except as provided in paragraph
(a)(4) of this section, the power
production capacity of a facility for
which qualification is sought, together
with the power production capacity of
any other small power production
facilities that use the same energy
resource, are owned by the same
person(s) or its affiliates, and are located
at the same site, may not exceed 80
megawatts.
(2) Method of calculation. (i)(A) For
purposes of this paragraph (a)(2)(i)(A),
there is an irrebuttable presumption that
facilities located one mile or less from
the facility for which qualification is
sought are located at the same site as the
facility for which qualification is
sought.
(B) For purposes of this paragraph
(a)(2)(i)(B), for facilities for which
qualification is filed on or after [DATE
60 DAYS AFTER DATE OF
PUBLICATION OF THE FINAL RULE
IN THE FEDERAL REGISTER], there is
an irrebuttable presumption that
facilities located ten miles or more from
the facility for which qualification is
sought are facilities located at separate
sites from the facility for which
qualification is sought.
(C) For purposes of this paragraph
(a)(2)(i)(C), for facilities for which
qualification is filed on or after [DATE
60 DAYS AFTER DATE OF
PUBLICATION OF THE FINAL RULE
IN THE FEDERAL REGISTER], there is
a rebuttable presumption that facilities
located over one and less than ten miles
from the facility for which qualification
is sought are facilities located at
separate sites from the facility for which
qualification is sought.
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properly completing a Form No. 556
and filing that form with the
Commission, pursuant to § 131.80 of
this chapter, and complying with
paragraph (c) of this section.
(2) Factors. For small power
production facilities pursuant to
§ 292.204, the owner or operator of the
facility or its representative may, when
completing the Form No. 556, provide
information asserting factors showing
that the facility for which qualification
is sought is at a separate site from other
facilities using the same energy resource
and owned by the same person(s) or its
affiliates.
(3) Protests and Interventions. Any
protest to and any intervention in a selfcertification must be filed in accordance
with §§ 385.211 and 385.214 of this
chapter, on or before 30 days from the
date the self-certification is filed. Any
protest must provide evidence to
substantiate the claims in the protest.
(4) Commission action. Selfcertification is effective upon filing. If
no protests are timely filed, no further
action by the Commission is required
for a self-certification to be effective. If
protests are timely filed, a selfcertification will remain effective until
the Commission issues an order
revoking QF certification. The
Commission will act on the protest
within 90 days from the date the protest
is filed; provided that, if the
Commission requests more information
from the protester, the entity seeking QF
certification, or both, the time for the
Commission to act will be extended to
60 days from the filing of a complete
answer to the information request. In
addition to any extension resulting from
a request for information, the
Commission also may toll the 90-day
period for one additional 60-day period
if so required to rule on a protest.
Authority to toll the 90-day period for
this purpose is delegated to the
Secretary or the Secretary’s designee.
(b) Optional procedure—Commission
certification. (1) Application for
Commission certification. In lieu of the
self-certification procedures in
paragraph (a) of this section, an owner
or operator of an existing or a proposed
facility, or its representative, may file
with the Commission an application for
Commission certification that the
facility is a qualifying facility. The
application must be accompanied by the
§ 292.207 Procedures for obtaining
fee prescribed by part 381 of this
qualifying status.
chapter, and the applicant for
(a) Self-certification. (1) Form No. 556. Commission certification must comply
The qualifying facility status of an
with paragraph (c) of this section.
(2) General contents of application.
existing or a proposed facility that meets
The application must include a properly
the requirements of § 292.203 may be
self-certified by the owner or operator of completed Form No. 556 pursuant to
§ 131.80 of this chapter. For small
the facility or its representative by
(D) For hydroelectric facilities,
facilities are considered to be located at
the same site as the facility for which
qualification is sought if they are
located within one mile of the facility
for which qualification is sought and
use water from the same impoundment
for power generation.
(ii) For purposes of making the
determination in clause (i), the distance
between facilities shall be measured
from the electrical generating equipment
of the facility for which qualification is
sought and the nearest electrical
generating equipment of the other
facility using the same energy resource
and owned by the same person(s) or its
affiliates.
(3) Rebuttal. (i) Filing a Protest. Any
person who opposes either a selfcertification submitted pursuant to
§ 292.207(a) or a Commission
certification filed pursuant to
§ 292.207(b) may submit a protest
attempting to rebut the presumption
that facilities located over one mile and
less than ten miles from the facility for
which qualification is sought are
separate facilities at separate sites from
the facility for which qualification is
sought.
(ii) Limitations on rebuttal. Once the
Commission has affirmatively certified
an applicant’s QF status either in
response to a protest opposing a selfcertification or in a Commission
certification proceeding, any later
challenge to a QF’s certification
asserting that facilities more than one
mile and less than ten miles apart are
located at the same site must
demonstrate a material change in the
relevant circumstances that calls into
question the continued validity of the
certification.
(4) Waiver. The Commission may
modify the application of paragraph
(a)(2) of this section, for good cause.
(5) Exception. Facilities meeting the
criteria in section 3(17)(E) of the Federal
Power Act (16 U.S.C. 796(17)(E)) have
no maximum size, and the power
production capacity of such facilities
shall be excluded from consideration
when determining the maximum size of
other small power production facilities
less than ten miles of such facilities.
*
*
*
*
*
■ 5. Amend § 292.207 by revising
paragraphs (a) and (b) to read as follows:
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power production facilities pursuant to
§ 292.204, the owner or operator of the
facility or its representative may, when
completing the Form No. 556, provide
information asserting factors showing
that the facility for which qualification
is sought is at a separate site from other
facilities using the same energy resource
and owned by the same person(s) or its
affiliates.
*
*
*
*
*
■ 6. Section 292.303 is revised to read:
§ 292.303 Electric utility obligations under
this subpart.
(a) Obligation to purchase from
qualifying facilities. Subject to
paragraph (b) of this section, each
electric utility shall purchase, in
accordance with § 292.304, unless
exempted by § 292.309 and § 292.310,
any energy and capacity which is made
available from a qualifying facility:
(1) Directly to the electric utility; or
(2) Indirectly to the electric utility in
accordance with paragraph (e) of this
section.
(b) Reduction in purchase obligation.
The obligation of an electric utility to
purchase from a qualifying facility may
be reduced to the extent that a
purchasing electric utility’s supply
obligation has been reduced by a state’s
retail choice program.
(c) Obligation to sell to qualifying
facilities. Each electric utility shall sell
to any qualifying facility, in accordance
with § 292.305, unless exempted by
§ 292.312, energy and capacity
requested by the qualifying facility.
(d) Obligation to interconnect.
(1) Subject to paragraph (d)(2) of this
section, any electric utility shall make
such interconnection with any
qualifying facility as may be necessary
to accomplish purchases or sales under
this subpart. The obligation to pay for
any interconnection costs shall be
determined in accordance with
§ 292.306.
(2) No electric utility is required to
interconnect with any qualifying facility
if, solely by reason of purchases or sales
over the interconnection, the electric
utility would become subject to
regulation as a public utility under part
II of the Federal Power Act.
(e) Transmission to other electric
utilities. If a qualifying facility agrees, an
electric utility which would otherwise
be obligated to purchase energy or
capacity from such qualifying facility
may transmit the energy or capacity to
any other electric utility. Any electric
utility to which such energy or capacity
is transmitted shall purchase such
energy or capacity under this subpart as
if the qualifying facility were supplying
energy or capacity directly to such
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electric utility. The rate for purchase by
the electric utility to which such energy
is transmitted shall be adjusted up or
down to reflect line losses pursuant to
§ 292.304(e)(4) and shall not include
any charges for transmission.
(f) Parallel operation. Each electric
utility shall offer to operate in parallel
with a qualifying facility, provided that
the qualifying facility complies with any
applicable standards established in
accordance with § 292.308.
■ 7. Amend § 292.304 by
■ a. Adding paragraphs (b)(6), (b)(7),
(b)(8); and
■ b. Revising paragraphs (d), and (e).
The addition and revisions read as
follows:
§ 292.304
Rates for purchases.
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*
*
*
*
*
(b) * * *
(6) Locational Marginal Price. A state
regulatory authority or nonregulated
electric utility may use a locational
marginal price as a rate for as-available
qualifying facility energy sales to
purchasing utilities located in a market
operated defined in § 292.309(e), (f), or
(g).
(7) Competitive Price. A state
regulatory authority or nonregulated
electric utility may use a Competitive
Price as a rate for as-available qualifying
facility energy sales to purchasing
electric utilities located outside a
market defined in § 292.309(e), (f), or
(g). A Competitive Price may be either
a Market Hub Price or a Combined Cycle
Price, determined as follows:
(i) A Market Hub Price is a price
established at a liquid market hub to
which a state regulatory authority or
nonregulated electric utility determines
the purchasing electric utility has
reasonable access, based on its
evaluation of the relevant factors,
including but not limited to the
following:
(A) Whether the hub is sufficiently
liquid that prices at the hub represent a
competitive price;
(B) Whether prices developed at the
hub are sufficiently transparent;
(C) Whether the purchasing electric
utility has the ability to deliver power
from such hub to its load, even if its
load is not directly connected to the
hub; and
(D) Whether the hub represents an
appropriate market to derive an energy
price for the purchasing electric utility’s
purchases from the relevant QFs given
the electric utility’s physical proximity
to the hub or other factors.
(ii) A Combined Cycle Price is a price
determined pursuant to a formula
established by a state regulatory
authority or nonregulated electric utility
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using published natural gas price
indices and a proxy heat rate for an
efficient natural gas combined-cycle
generating facility. Before establishing
such a formula rate, a state regulatory
authority or nonregulated electric utility
must determine that the resulting
Combined Cycle Price represents an
appropriate approximation of the
purchasing electric utility’s avoided
cost, based on its evaluation of the
relevant factors, including but not
limited to the following:
(A) 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;
(B) Whether natural gas priced
pursuant to particular proposed natural
gas price indices would be available in
the relevant market;
(C) 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
(D) Whether the proxy heat rate used
in the formula should be updated
regularly to reflect improvements in
generation technology.
(8) Competitive Solicitation Price. A
state regulatory authority or
nonregulated electric utility may use a
price determined pursuant to a
competitive solicitation process to
establish qualifying facility energy and/
or capacity rates for sales to purchasing
electric utilities, provided that such
competitive solicitation process is
conducted pursuant to procedures
ensuring the solicitation is conducted in
a transparent and non-discriminatory
manner including, but not limited to,
the following:
(i) The solicitation process is an open
and transparent process;
(ii) 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;
(iii) Solicitations are conducted at
regular intervals;
(iv) Solicitations are subject to
oversight by an independent
administrator; and
(v) Solicitations are certified as
fulfilling the above criteria by the
relevant state regulatory authority or
nonregulated electric utility.
*
*
*
*
*
(d) Purchases ‘‘as available’’ or
pursuant to a legally enforceable
obligation. (1) Each qualifying facility
shall have the option either:
(i) To provide energy as the qualifying
facility determines such energy to be
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53271
available for such purchases, in which
case the rates for such purchases shall
be based on the purchasing electric
utility’s avoided costs calculated at the
time of delivery; or
(ii) To provide energy or capacity
pursuant to a legally enforceable
obligation for the delivery of energy or
capacity over a specified term, in which
case the rates for such purchases shall,
except as provided in subsection (d)(2)
below, be based on either:
(A) The avoided costs calculated at
the time of delivery; or
(B) The avoided costs calculated at
the time the obligation is incurred.
(iii) The rate for delivery of energy
calculated at the time the obligation is
incurred may be based on estimates of
the present value of the stream of
revenue flows of future locational
marginal prices, or Competitive Prices
during the anticipated period of
delivery.
(2) Notwithstanding paragraph
(d)(1)(ii)(B) of this section, a state
regulatory authority or nonregulated
electric utility may require that rates for
purchases of energy from a qualifying
facility pursuant to a legally enforceable
obligation to vary through the life of the
obligation, and to be set at the asavailable energy price applicable to the
purchasing electric utility determined at
the time of delivery.
(3) Obtaining a legally enforceable
obligation. A qualifying facility must
demonstrate commercial viability and
financial commitment to construct its
facility pursuant to criteria determined
by the state regulatory authority or
nonregulated electric utility as a
prerequisite to a qualifying facility
obtaining a legally enforceable
obligation. Such criteria must be
objective and reasonable.
(e) Factors affecting rates for
purchases. (1) A state regulatory
authority or nonregulated electric utility
may establish rates for purchases of
energy from a qualifying facility based
on a purchasing electric utility’s
locational marginal price calculated by
the applicable market defined in
§ 292.309(e), (f), or (g), or the purchasing
electric utility’s applicable Competitive
Price. Alternatively, a state regulatory
authority or nonregulated electric utility
may establish rates for purchases of
energy and/or capacity from a qualifying
facility based on a Competitive
Solicitation Price. To the extent that
capacity rates are not set pursuant to
this section, capacity rates shall be set
pursuant to subsection (2).
(2) To the extent that a state
regulatory authority or nonregulated
electric utility does not to set energy
and/or capacity rates pursuant to
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paragraph (e)(1) of this section, the
following factors shall, to the extent
practicable, be taken into account in
determining rates for purchases from a
qualifying facility:
(i) The data provided pursuant to
§ 292.302(b), (c), or (d), including State
review of any such data;
(ii) The availability of capacity or
energy from a qualifying facility during
the system daily and seasonal peak
periods, including:
(A) The ability of the electric utility
to dispatch the qualifying facility;
(B) The expected or demonstrated
reliability of the qualifying facility;
(C) The terms of any contract or other
legally enforceable obligation, including
the duration of the obligation,
termination notice requirement and
sanctions for non-compliance;
(D) The extent to which scheduled
outages of the qualifying facility can be
usefully coordinated with scheduled
outages of the electric utility’s facilities;
(E) The usefulness of energy and
capacity supplied from a qualifying
facility during system emergencies,
including its ability to separate its load
from its generation;
(F) The individual and aggregate
value of energy and capacity from
qualifying facilities on the electric
utility’s system; and
(G) The smaller capacity increments
and the shorter lead times available
with additions of capacity from
qualifying facilities; and
(iii) The relationship of the
availability of energy or capacity from
the qualifying facility as derived in
paragraph (e)(2)(ii) of this section, to the
ability of the electric utility to avoid
costs, including the deferral of capacity
additions and the reduction of fossil
fuel use; and
(iv) The costs or savings resulting
from variations in line losses from those
that would have existed in the absence
of purchases from a qualifying facility,
if the purchasing electric utility
generated an equivalent amount of
energy itself or purchased an equivalent
amount of electric energy or capacity.
■ 8. Amend § 292.309 by revising
paragraphs (d), (e), and (f) to read as
follows:
§ 292.309 Termination of obligation to
purchase from qualifying facilities.
*
*
*
*
*
(d)(1) For purposes of § 292.309(a)(1),
(2), and (3), there is a rebuttable
presumption that a qualifying
cogeneration facility with a capacity at
or below 20 megawatts does not have
nondiscriminatory access to the market.
(2) For purposes of § 292.309(a)(1),
(2), and (3), there is a rebuttable
presumption that a qualifying small
power production facility with a
capacity at or below 1 megawatt does
not have nondiscriminatory access to
the market.
(3) For purposes of implementing
paragraphs (d)(1) and (d)(2) of this
section, the Commission will not be
bound by the standards set forth in
§ 292.204(a)(2).
(e) Midcontinent Independent System
Operator, Inc. (MISO), PJM
Interconnection, L.L.C. (PJM), ISO New
England Inc. (ISO–NE), and New York
Independent System Operator, Inc.
(NYISO) qualify as markets described in
§ 292.309(a)(1)(i) and (ii), and there is a
rebuttable presumption that small
power production facilities with a
capacity greater than one megawatt and
cogeneration facilities with a capacity
greater than 20 megawatts have
nondiscriminatory access to those
markets through Commission-approved
open access transmission tariffs and
interconnection rules, and that electric
utilities that are members of such
regional transmission organizations or
independent system operators (RTO/
ISOs) should be relieved of the
obligation to purchase electric energy
from the qualifying facilities. A
qualifying facility may seek to rebut this
presumption by demonstrating, inter
alia, that:
(1) The qualifying facility has certain
operational characteristics that
effectively prevent the qualifying
facility’s participation in a market; or
(2) The qualifying facility lacks access
to markets due to transmission
constraints. The qualifying facility may
show that it is located in an area where
persistent transmission constraints in
effect cause the qualifying facility not to
have access to markets outside a
persistently congested area to sell the
qualifying facility output or capacity.
(f) The Electric Reliability Council of
Texas (ERCOT) qualifies as a market
described in § 292.309(a)(3), and there is
a rebuttable presumption that small
power production facilities with a
capacity greater than one megawatt and
cogeneration facilities with a capacity
greater than 20 megawatts have
nondiscriminatory access to that market
through Public Utility Commission of
Texas (PUCT) approved open access
protocols, and that electric utilities that
operate within ERCOT should be
relieved of the obligation to purchase
electric energy from the qualifying
facilities. A qualifying facility may seek
to rebut this presumption by
demonstrating, inter alia, that:
(1) The qualifying facility has certain
operational characteristics that
effectively prevent the qualifying
facility’s participation in a market; or
(2) The qualifying facility lacks access
to markets due to transmission
constraints. The qualifying facility may
show that it is located in an area where
persistent transmission constraints in
effect cause the qualifying facility not to
have access to markets outside a
persistently congested area to sell the
qualifying facility output or capacity.
*
*
*
*
*
PART 375—THE COMMISSION
1. The authority citation for part 375
continues to read as follows:
■
Authority: 5 U.S.C. 551–557; 15 U.S.C.
717–717w, 3301–3432; 16 U.S.C. 791–825r,
2601–2645; 42 U.S.C. 7101–7352.
2. Section 375.302(v) is revised to
read:
■
§ 375.302
Delegations to the Secretary.
*
*
*
*
*
(v) Toll the time for action on requests
for rehearing, and toll the time for
action on protested self-certifications
and self-recertifications of qualifying
facilities.
The following will not appear in the
Code of Federal Regulations:
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FEDERAL ENERGY REGULATORY COMMISSION
Docket Nos.
Qualifying Facility Rates and Requirements ...................................................................................................................................
Implementation Issues Under the Public Utility Regulatory Policies Act of 1978 ...........................................................................
(Issued September 19, 2019)
GLICK, Commissioner, dissenting in part:
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1. I dissent in part from today’s notice of
proposed rulemaking (NOPR) because it
would effectively gut the Public Utility
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AD16–16–000
Regulatory Policies Act (PURPA).1 Our basic
1 Public
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responsibilities under PURPA are three-fold:
(1) To encourage the development of
qualifying facilities (QFs); (2) to prevent
discrimination against QFs by incumbent
utilities; and (3) to ensure that the resulting
rates paid by electricity customers remain
just and reasonable and in the public
interest.2 As discussed further below, it is not
clear from the record or the discussion in
today’s NOPR that many of the proposed
changes will satisfy those requirements.
Although the record developed in response
to this NOPR will give us a basis to address
those issues, I am deeply concerned that the
Commission has failed so far to show that
certain aspects of its proposal satisfy our
basic responsibilities under the law.
2. It appears that the Commission no longer
believes that PURPA is necessary. I disagree.
I believe that the goals of PURPA—including
the need to expand competition and reduce
our reliance on fossil fuels 3—remain as
relevant now as ever. But our apparent
disagreement is beside the point. Whether
PURPA’s goals remain relevant is a decision
for Congress, not an administrative agency.
The Commission should not be seizing the
reins from Congress in order to isolate an
important debate about national energy
policy within an independent regulatory
agency.
I. PURPA’s Continuing Relevance Is an Issue
for Congress To Decide
3. A fundamental reform to a major energy
statute, particularly one that Congress has
been debated for decades, ought to come
from Congress, not an independent
regulatory agency. For more than forty years,
the Commission has rather consistently
interpreted Congress’s directives in PURPA.
During that time, Congress has repeatedly
considered legislation to amend the statute,
in some cases to expand its reach and in
others to pare it back. Indeed, almost from
the moment PURPA was passed, Congress
began to hear many of the arguments being
used today to justify scaling the law back. Yet
Congress only on one occasion—in 2005—
significantly amended the statute. After a
lengthy debate, which included proposals to
repeal PURPA, Congress adopted the Energy
Policy Act of 2005 (EPAct 2005), which left
in place PURPA’s basic framework but added
a series of provisions that relieved utilities of
their requirements in regions of the country
with robust wholesale energy markets.4 Over
the course of the last fourteen years, Congress
has continued to consider a wide range of
proposals to reform PURPA, some of which
would have enacted into law many of the
proposals advanced in this NOPR. But
Congress did not enact any of these reforms.
4. Today’s NOPR flips that dynamic on its
head. It removes an important debate from
the halls of Congress and isolates it within
the Commission. That may help to achieve
certain stakeholders’ objectives and, no
doubt, some Members of Congress that have
unsuccessfully sought to further reform
2 See
16 U.S.C. 824a–3 (2018).
Am. Paper Inst., Inc. v. Am. Elec. Power
Serv. Corp., 461 U.S. 402, 405 (1983) (describing
Congress’s intent in enacting PURPA).
4 Public Law 109–58, 119 Stat. 594 (2005).
3 See
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PURPA will applaud this outcome. But what
should concern all of us is that resolving
these sorts of questions by regulatory edict
rather than congressional legislation is
neither a durable nor desirable approach for
developing energy policy.
5. With those concerns in mind, the
Commission’s explanation of the purported
need for reform rings hollow. The majority
recites statistics to show that the energy
landscape has changed over the last 40 years.
And there is no doubt that it has. Renewables
are growing rapidly and, in some parts of the
country, are being financed in large numbers
without PURPA’s protections.5 Natural gas
production has increased in similarly
dramatic fashion and recently surpassed coal
as the country’s principal source of fuel for
generating electricity.6 But reams of statistics
do not make a law irrelevant. The majority
and I might disagree about PURPA and the
importance of its objectives, but that is not
a dispute that we, as Commissioners, should
resolve. A policy debate about the continuing
relevance of PURPA—which, make no
mistake, is what this NOPR is really about—
is an issue for Congress to resolve.
II. Certain Proposed Revisions Are
Inconsistent With Our Statutory Obligations
6. In addition to my general concerns about
the direction and intent of today’s NOPR, I
have a number of more discrete objections
regarding aspects of the Commission’s
proposal. I raise these concerns in particular
because I believe that neither the record
established to date nor the rationale
articulated in today’s NOPR suggest that
these changes are consistent with our
obligations under PURPA. Accordingly, I am
especially interested in reviewing the record
developed in response to these elements of
the proposed rule and I encourage parties to
address these issues in detail in their
comments.
A. Avoided Cost
7. No issue has consumed as much
attention in the debates over PURPA as how
to set avoided cost. Following PURPA’s
enactment in 1978, the Commission
introduced a framework for setting ‘‘avoided
cost’’ that allows each individual state to
consider a wide range of factors in
identifying the ‘‘full’’ costs that are avoided
when a utility purchases energy and capacity
from a QF.7 The basic idea is that the avoided
cost figure should reflect the full cost that the
utility would incur but for the purchase of
the QF output of energy or capacity, with
each individual state enjoying considerable
flexibility in implementing that concept.8
5 See Qualifying Facility Rates and Requirements;
Implementation Issues Under the Public Utility
Regulatory Policies Act of 1978, 168 FERC ¶ 61,184,
at PP 19–21 (2019) (NOPR).
6 U.S. Energy Info. Admin., What is U.S.
electricity generation by energy source?, https://
www.eia.gov/tools/faqs/faq.php?id=427&t=3 (last
visited Sept. 19, 2019).
7 See 18 CFR 292.304(e) (2019).
8 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, at
30,865 (cross-referenced 10 FERC ¶ 61,150), order
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The Commission’s regulations also provide
states the flexibility to accommodate
Congress’s intent that the rates paid to QFs
‘‘look beyond’’ just ‘‘instantaneous cost
savings’’ in order to consider savings over a
longer time horizon.9
8. The NOPR proposes two fundamental
changes to how avoided cost is calculated
and applied to QFs. First, it proposes to
eliminate the requirement that a utility must
afford a QF the option to enter a contract at
an avoided cost energy rate that is fixed or
known for the duration of the contract.10 As
things stand now, a QF generally has two
options for selling its output to a utility.
Under the first option, the QF can sell its
energy on an as-available basis and receive
an avoided cost rate calculated at the time of
delivery. This is generally known as the asavailable option. Under the second option, a
QF can enter into a fixed duration contract
at an avoided cost rate that is fixed either at
the time the QF establishes a legally
enforceable obligation or at the time of
delivery. This is generally known as the
contract option. The ability to choose
between both types sale options has played
an important role in fostering the
development of a variety of QFs. For
example, the as-available option provides a
way for QFs whose principal business is not
generating electricity, such as industrial
cogeneration facilities, to monetize their
excess electricity generation. The contract
option, by contrast, provides QFs who are
principally in the business of generating
electricity, such as small renewable
electricity generators, a relatively stable
option that will allow them to secure
financing. Together, the presence of these
two options have allowed the Commission to
satisfy its statutory mandate to encourage the
development of QFs and ensure that the rates
they receive are non-discriminatory.
9. I am concerned that the Commission’s
proposal to allow utilities to eliminate the
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).
9 H.R. Rep. 95–1750, at 98–99 (1978) (Conf. Rep.)
(‘‘In interpreting the incremental cost of alternative
energy, the Conferees expect that the Commission
and the states may look beyond the costs of
alternative sources which are instantaneously
available to the utility. Rather the Commission and
states should look to the reliability of that power
and the cost savings to the utility which may result
at some later date by reasons of supply to the utility
at that time of power from the cogenerate or small
power producers.’’).
10 The NOPR proposes to eliminate the contract
option for the energy component, keeping the longterm contract requirement in place for capacity.
That sounds more reasonable than it will often be
in practice. The NOPR later clarifies that the fixed
capacity value may be zero if the state determines
that the electric utility does not have a need for
additional capacity resources. See NOPR, 168 FERC
¶ 61,184 at P 67. That would also mean that, in
some instances, there would be no fixed element in
an avoided cost contract, which would seem
inconsistent with the Commission’s rationale
justifying variable energy price contracts. See id. P
70.
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fixed-price contract option will make it more
difficult—or in some cases impossible—for
QFs to obtain financing. The option to enter
a contract with a fixed or known price has
played in essential role in encouraging QF
development.11 In addition, those contracts
have played an important role in ensuring
that QFs receive non-discriminatory rates,
especially in areas of the country with
vertically integrated utilities that are
guaranteed to recover the costs of their
prudently incurred investments through
retail rates.12 Neither the record nor the
rationale in this NOPR addresses these
concerns in a manner that is even remotely
convincing.
10. Second, I am concerned about the
implications of the Commission’s proposal to
determine that a locational marginal price
(LMP) is a per se reasonable measure of an
as-available avoided cost for energy and to
preliminarily advance several other
‘‘Competitive Prices’’ that would also be
sufficient.13 Current regulations require
states to consider factors, including
reliability and when the QF is available,
when calculating the avoided cost rate.
Today’s NOPR proposes to allow states to
ignore these factors and, instead, rely entirely
on LMP or a price set at a ‘‘liquid market
hub.’’ That rule would apply across the
country, irrespective of whether the QF has
access non-discriminatory access to
competitive markets.14 That is
notwithstanding the fact that the evidence
the Commission relies on to justify this
proposal comes overwhelmingly from regions
with sophisticated RTO and ISO markets
and/or restructured utilities.
11. As an initial matter, I support
introducing more competition into the
Commission’s implementation of PURPA.
Liquid price signals can be useful and
transparent inputs that are worthy of
considering as part of the overall calculation
of an appropriate avoided cost number that
includes both the short-term and long-term
costs avoided by the utility’s purchases from
QFs. But referencing the words
‘‘competitive’’ and ‘‘market’’ over and over
again is not the same thing as proof that there
is sufficient market competition. Many
11 See, e.g., June 29, 2016 Technical Conf. Tr. at
26–27 (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.’’).
12 See Statement of Travis Kavulla, Docket No.
AD16–16–000, at 2 (June 29, 2016) (‘‘Whether
compensation for a QF is a matter of market
clearing prices or of administrative decision-making
is largely a reflection of how larger or utility-owned
generation is compensated.’’).
13 NOPR, 168 FERC ¶ 61,184 at PP 50, 55–60.
14 The NOPR proposes to allow states or utilities
to use this liquid market price only for the ‘‘asavailable’’ energy sales rate, not the capacity rate or
for QFs that choose the contract option. But given
that the Commission is also proposing to allow
utilities to eliminate the fixed-price contract option
for energy sales, QFs may have no choice but to rely
on the ‘‘as-available’’ option for sales of energy.
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regions of the country—often the same
regions where the debates about PURPA are
most heated—have not established
competitive markets, let alone nondiscriminatory access to those markets for
independent generators, even if there are
liquid market hubs for spot energy purchases.
When combined with the Commission’s
proposal to allow utilities to eliminate the
contract option, discussed above, QFs may be
reduced to relying solely on some synthetic
measure of what spot prices would be in a
competitive market based on gas prices and
heat rates. I am not persuaded that this will
satisfy our obligation to encourage QFs.
12. Nor am I confident that this proposal
will not result in discriminatory rates. In
regions of the country with vertically
integrated utilities (including some parts of
RTO/ISO markets) the relevant utility will
almost always receive guaranteed costrecovery on its generation investments.
Indeed, state regulators will often effectively
pre-approve certain incumbent utility
investments through those utilities’
integrated resource plans, making it highly
unlikely that the utility investments will
ultimately be disallowed as imprudent.
Under those circumstances, it is not clear to
me how a rule that conclusively presumes
that LMP—let alone some other measure of
price—is a non-discriminatory rate in those
regions.
13. I recognize that in some regions of the
country—such as the RTOs and ISOs with
developed real-time and day-ahead markets
and largely restructured utilities—this may
be an appropriate approach for calculating
the as-available rate for energy, at least for
relatively large QFs. But the NOPR’s
proposed revisions are not limited to those
regions and are not even predicated on
utilities themselves actually relying on LMP,
liquid market hubs, or other calculations of
‘‘Competitive Prices.’’ In any case, neither the
record nor the rationale in this NOPR
addresses these concerns in a convincing
manner.
B. Reducing the 20 MW Rebuttable
Presumption
14. The Commission is also proposing to
reduce the threshold for the rebuttable
presumption of non-discriminatory access to
competitive wholesale markets within RTOs
and ISOs from 20 MW to 1 MW. This
proposal would, in essence, relieve most
utilities within RTOs and ISOs from the
must-purchase obligation for any resource
greater than 1 MW based on the theory that
those resources have non-discriminatory
access to the RTO and ISO markets.15
15. The Commission created the rebuttable
presumption framework in response to
Congress’s enactment of section 210(m) in
EPAct 2005. The Commission explained that
QFs smaller than 20 MW often face more
challenges than larger QFs in accessing
competitive wholesale markets and therefore
presumptively do not have nondiscriminatory access.16 The challenges it
15 This issue, as much as any other, has been
subject to vigorous debate in Congress. See supra
at 3.
16 New PURPA Section 210(m) Regulations
Applicable to Small Power Production and
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identified included issues such as
interconnection at the distribution level,
jurisdictional differences, pancaked delivery
rates, and administrative burdens to
obtaining access to distant buyers.17
16. Today’s NOPR contains precious little
justification to support that change and does
not cite a single piece of record evidence
supporting its proposal.18 That may be
because it seems a stretch to suggest that a
1 MW resource can generally access and
compete in markets as sophisticated and
complex as, for example, PJM
Interconnection, L.L.C., on a similar footing
as the resources in the portfolio of a large
vertically integrated utility or merchant
power generator.
17. These are among the most important
issues presented in this NOPR. I hope that
the parties will assemble a correspondingly
robust record that allows to us to dig into
them in detail and evaluate whether the
Commission’s proposals are consistent with
our obligations under the statute.
III. PURPA Should Be Revised To Create
More Competition, Not Less
18. Insofar as I can tell, the Commission
interprets the success of PURPA since 1978
as evidence that the law is no longer needed
and that the Commission should revise its
regulations so that they do less to encourage
QFs. I draw a slightly different conclusion
from the same evidence. I view PURPA’s
success in deploying gigawatts of relatively
low-cost electricity as proof of the benefits of
introducing competition into the bulk power
system.
19. Several proposals in the record would
do just that. For example, the National
Association of Regulatory Commissioners
(NARUC) submitted a proposal for how the
Commission might implement section
210(m)(1), which was added by the Energy
Policy Act of 2005. The new provision
provided three bases for FERC to terminate
a utility’s must-purchase obligation under
PURPA, all of which hinged on QFs’ access
to competitive wholesale electricity
markets.19 The NARUC proposal urged the
Cogeneration Facilities, Order No. 688, 117 FERC
¶ 61,078, at PP 9–12 (2006), order on reh’g, Order
No. 688–A, 119 FERC ¶ 61,305 (2007), aff’d sub
nom. Am. Forest & Paper Ass’n v. FERC, 550 F.3d
1179 (D.C. Cir. 2008).
17 NOPR, 168 FERC ¶ 61,184 at P 121.
18 To the contrary, the Commission has found that
QFs less than 20 MW may not have nondiscriminatory access, even within RTO/ISO
markets. In just the last few years, the Commission
has explained that barriers such as transmission
constraints are the very ‘‘circumstances explained
in Order No. 688 that gave rise to the rebuttable
presumption that smaller QFs lack
nondiscriminatory access to markets.’’ N. States
Power Co., 151 FERC ¶ 61,110, at P 34 (2015).
Today’s NOPR fails to provide any explanation for
the departure from the Commission’s existing
policy.
19 Section 210m(1) provides:
(A)(i) Independently administered, auction-based
day ahead and real-time wholesale markets for the
sale of electric energy; and (ii) wholesale markets
for long-term sales of capacity and electric energy;
or
(B)(i) transmission and interconnection services
that are provided by a Commission approved
regional transmission entity and administered
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Commission to give meaning to section
210m(1)(C) of the Federal Power Act by
establishing criteria by which a vertically
integrated utility outside of an RTO or ISO
could apply to terminate the must-purchase
obligation if it conducts sufficiently
competitive auctions or RFPs for energy and
capacity.20 In other words, it would use the
pathway established by Congress’s
amendments to PURPA to create more
opportunity and competition in areas where,
for non-incumbent utilities, PURPA is often
the only game in town.
20. The NARUC proposal was a
whitepaper, not a detailed NOPR. It would
surely require more development before we
could determine whether it satisfies PURPA’s
statutory requirements. Nevertheless it
represented a step in the right direction that
would have been consistent with PURPA’s
pro-competitive purposes. It was also an idea
that we could have—and should have—
amply explored through a technical
conference or other proceeding since the
Chairman indicated his intent to go forward
with revisions to PURPA.
21. The Solar Energy Industries
Association also put forward a procompetitive proposal of the type that I would
like to have explored in more detail in this
NOPR.21 The proposal would address
competitive solicitations as a means of
procuring energy and capacity from all new
generation resources, including QFs. It also
discussed the potential for these competitive
solicitations to set avoided cost under certain
circumstances. As with the NARUC proposal,
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pursuant to an open access transmission tariff that
affords nondiscriminatory treatment to all
customers; and (ii) competitive wholesale markets
that provide a meaningful opportunity to sell
capacity, including long-term and short-term sales,
and electric energy, including long-term, shortterm, and real-time sales, to buyers other than the
utility to which the qualifying facility is
interconnected. In determining whether a
meaningful opportunity to sell exists, the
Commission shall consider, among other factors,
evidence of transactions within the relevant market;
or
(C) wholesale markets for the sale of capacity and
electric energy that are, at a minimum, of
comparable competitive quality as markets
described in subparagraphs (A) and (B).
16 U.S.C. 824a–3(m)(1) (2018)
20 National Association of Regulatory Utility
Commissioners Supplemental Comments, Docket
No. AD16–16–00 (Oct. 17, 2018), Attachment A at
8; id. (proposing the Commission’s Edgar-Allegheny
criteria as a basis for evaluating whether a proposal
was adequately competitive).
21 Solar Energy Industries Association
Supplemental Comments, Docket No. AD16–16–000
(Aug. 28, 2019).
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17:08 Oct 03, 2019
Jkt 250001
this proposal would revise PURPA to include
more genuine competition rather simply
revising the regulations to do less to
encourage QFs.
22. Rather than seeking to expand
competition, the majority is instead using the
success of competition in certain parts of the
country as a reason to scale back PURPA
throughout the country. In some areas of the
country, particularly those with developed
RTO and ISO markets and with few, if any,
vertically integrated utilities, competition is
the norm and PURPA may not be necessary,
at least for generators that are sufficiently
large and sophisticated to participate on an
equal footing with other market participants.
But it does not necessarily follow that the
healthy competition we see in those regions
means that PURPA does not continue to play
a vital role in other parts of the country,
including those without RTO and ISO
markets or where vertically integrated
utilities dominate. To put it bluntly, the
success that a QF might have in selling its
energy and capacity within ISO New England
Inc. tells you very little about the success a
similar resource might have in the Southeast
or the West, at least without PURPA. I worry
that applying lessons learned in the truly
competitive regions of the country to the less
competitive regions will actually result in
less competition and, ultimately, higher
prices for consumers.
23. I support certain aspects of this NOPR
that I believe are consistent with the
Commission’s proper role in administering
PURPA and are supported by the record
developed so far. First and foremost, I agree
that it is time to address the ‘‘one-mile’’ rule,
which currently provides an irrebuttable
presumption that resources located more
than a mile apart are separate QFs.22 There
is evidence compiled as part of the
Commission’s 2016 technical conference on
PURPA that suggests that this rule is
susceptible to gaming and that some
developers are splitting what should fairly be
considered one project into a series of
discrete projects spread separated by a mile
each.23 I do not believe that is what Congress
had in mind when it set out to promote small
power production facilities in PURPA. The
NOPR proposes what I believe is a reasonable
framework for addressing this issue and I
look forward to reviewing the comments we
receive.
24. In addition, I support the proposal to
require that QFs demonstrate commercial
22 18
CFR 292.204(a) (2019).
Statement of Paul Kjellander, Docket No.
AD16–16–000, at 4–5 (June 29, 2016); Portland
General Electric Company Comments, Docket No.
AD16–16–000, at 6 (June 29, 2016).
23 See
PO 00000
Frm 00031
Fmt 4701
Sfmt 9990
53275
viability before securing a legally enforceable
obligation with the relevant utility. It seems
only fair to require that a proposed QF
demonstrate that it is not speculative and
will likely enter service before a utility incurs
an obligation to purchase that QF’s output at
any particular price. The proposal in today’s
NOPR appears to strike a reasonable balance
between allowing QFs to secure a
commitment for purchase early enough in
their development cycle so that they can use
it to facilitate financing while preventing QFs
from locking-in avoided-cost rates too far
ahead of their actual delivery of any energy
or capacity. Nevertheless, in contrast to the
one-mile rule, the record on this question is
relatively underdeveloped and I hope that
parties will address the specifics of this
proposal in detail.
25. Finally, I support the proposal to allow
stakeholders to protest self-certification of
QFs. If an entity believes a resource does not
qualify as a QF, it should have the
opportunity to protest the QF’s filing in the
same way that stakeholders have the
opportunity to protest most other
Commission filings. At the very least, it
seems unfair to require them to file a
declaratory order, and pay tens of thousands
of dollars, in order to inform the Commission
of their views.
* * *
26. The Commission seems to believe that
PURPA’s time has passed. But that is
Congress’s decision to make, not the
Commission’s. So long as PURPA is on the
books, we must faithfully implement the
requirements of the law. Although I support
certain elements of today’s NOPR, I am
concerned that many of the Commission’s
proposals will fall short of our statutory
obligations. In addition, I am also
disappointed that the Commission is not
doing more to explore using PURPA to
expand opportunities for genuine
competition, including through section
210(m)—the avenue for reform that Congress
enacted in 2005. I believe that focusing on
expanding opportunities for genuine
competition would far better serve the public
interest than simply rebalancing the scales
against QFs, which seems to be the principal
goal of today’s NOPR.
For these reasons, I respectfully dissent in
part.
lllllllllllllllllllll
Richard Glick,
Commissioner.
[FR Doc. 2019–20803 Filed 10–3–19; 8:45 am]
BILLING CODE 6717–01–P
E:\FR\FM\04OCP2.SGM
04OCP2
Agencies
[Federal Register Volume 84, Number 193 (Friday, October 4, 2019)]
[Proposed Rules]
[Pages 53246-53275]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2019-20803]
[[Page 53245]]
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
[[Page 53246]]
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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 https://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, (202) 502-6415, [email protected].
Helen Shepherd (Technical Information), Office of Energy Market
Regulation, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426, (202) 502-6176, [email protected].
Thomas Dautel (Technical Information), Office of Energy Policy and
Innovation, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426, (202) 502-6196, [email protected].
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
[[Page 53247]]
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
[[Page 53248]]
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
[[Page 53249]]
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.
---------------------------------------------------------------------------
\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, https://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
[[Page 53250]]
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), https://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.
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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.
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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.
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\41\ 16 U.S.C. 824a-3(m).
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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.
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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.
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\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).
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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
[[Page 53251]]
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.
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\49\ 16 U.S.C. 824a-3(a).
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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\
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\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\
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\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).
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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\
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\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.
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\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).
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1. Background
36. PURPA requires that the Commission promulgate rules, to be
[[Page 53252]]
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.
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\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.'').
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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\
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\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\
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\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).
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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\
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\71\ EEI Supplemental Comments, attach. A at 2-3 (June 25,
2018).
\72\ Id. at 4.
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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\
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\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.
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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
[[Page 53253]]
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\
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\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).
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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\
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\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.
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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\
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\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.
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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\
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\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).
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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\
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\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
[[Page 53254]]
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
[[Page 53255]]
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.
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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).
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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
[[Page 53256]]
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.'').
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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).
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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.
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\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).
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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
[[Page 53257]]
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\
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\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 https://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.
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\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'').
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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.
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\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'').
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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
[[Page 53258]]
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).
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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.
[[Page 53259]]
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
[[Page 53260]]
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.
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\141\ 16 U.S.C. 796(17)(A) (emphasis added).
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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.
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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
Comments, Docket No. AD16-16-000, at 7 (Nov. 7, 2016); Southern
Company Comments, Docket No. AD16-16-000, at 9-10 (Nov. 7, 2016);
NARUC Supplemental Comments, Docket No. AD16-16-000, at 3 (Nov. 7,
2016).
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b. Electrical Generating Equipment
98. 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.''
\145\ The Commission has suggested in orders what is not considered
``electrical generating equipment,'' \146\ but has never defined or
elaborated on what equipment meets the definition of ``electrical
generating equipment.'' For example, wind farms are typically comprised
of multiple wind turbines spread over some geographic area; however,
each wind turbine could be considered ``electrical generating
equipment.''
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\145\ 18 CFR 292.204(a)(2)(ii) (emphasis added).
\146\ In Order No. 70, the Commission stated: ``The comments
noted that some facilities may include equipment for gathering
energy to be used in the facility which may extend up to a number of
miles from the generating facility. The Commission believes that the
one-mile limit should be measured from the generating facilities.''
Order No. 70, FERC Stats. & Regs. ] 30,134 at 30,943.
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99. Similarly, solar facilities can be spread over some geographic
area (albeit likely not as large a footprint as a wind farm),
potentially creating confusion as to whether the one mile is measured
from the edge of the panels at one facility to the edge of the panel at
the next facility, or from the center point of each solar array.
Additionally, the Commission has not specified how to measure the
distance between facilities that have multiple separate sets of
``electrical generating equipment.''
2. Proposed Changes to Subpart B--Qualifying Cogeneration and Small
Power Production Facilities
a. Rebuttable Presumption of Separate Facilities
100. The Commission proposes to allow entities challenging a QF
certification to rebut the presumption that affiliated facilities
located more than one mile apart are considered to be separate QFs. The
Commission proposes that this change would be effective as of the date
of a final rule, which means that such challenges could only be made to
QF certifications and recertifications that are submitted after the
effective date of the final rule in this proceeding.
101. The Commission proposes that an entity can seek to rebut the
presumption only for those facilities that are located more than one
mile apart and less than ten miles apart. The Commission believes that,
just as there are some facilities that may be so close that it is
reasonable to irrebuttably treat them as a single facility (those a
mile or less apart), so there are some facilities that are sufficiently
far apart that it is reasonable to treat them as irrebuttably separate
facilities. That latter distance, the Commission believes, is ten miles
or more apart. Thus, if two affiliated facilities are one mile or less
apart they are currently and will continue to be irrebuttably presumed
to be a single facility at a single site. If affiliated facilities are
ten miles or more apart, they will be irrebuttably presumed to be
separate facilities at separate sites.
102. If affiliated facilities are between one and ten miles apart
(i.e., more than one mile apart and less than ten miles apart) there
will still be a presumption, but it will be a rebuttable presumption,
that they are separate facilities at separate sites. Purchasing
electric utilities and others thus would be able to file a protest
attempting to rebut the presumption for facilities more than one mile
apart and less than ten miles apart, and argue that they should be
treated as a single facility. The Commission may also act sua sponte.
The Commission proposes, as explained below, that self-certifications
will remain effective after a protest has been filed, until such time
as the Commission issues an order revoking the certification.
103. The Commission proposes allowing an entity seeking QF status
to provide further information in its certification (both self-
certification and Commission certification), to preemptively defend
against rebuttal by asserting factors that affirmatively show that two
facilities are indeed separate facilities at separate sites.\147\
Anyone challenging the QF certification would be allowed to assert
factors to show that the facilities are actually part of the same,
single facility.
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\147\ While a QF with a net power production capacity of 1 MW or
less is not required to formally certify its QF status (either
through Commission certification or self-certification), if the QF's
status is later challenged the QF would be able to respond by
affirmatively demonstrating that its facilities are not located at
the same site as other affiliated facilities and thus that the QF
does not exceed the 80 MW size limitation.
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104. The Commission proposes limiting protests challenging QF
status by requiring any entity filing a protest to specify facts that
make a prima facie demonstration that the facility described in the
self-certification, self-recertification, or Commission certification
does not satisfy the requirements for QF status. General allegations or
unsupported assertions would not be a basis for denial of
certification. The Commission further
[[Page 53261]]
proposes limiting protests to QF status by requiring that once the
Commission has affirmatively certified an applicant's QF status through
either a Commission certification proceeding or in response to protests
challenging QF status, any later protest to a QF's existing
certification asserting that facilities further than one mile apart are
part of a single QF must demonstrate changed circumstances that call
into question the continued validity of the earlier certification.
105. The Commission proposes that physical and ownership factors
may be asserted to rebut or defend against rebuttal. Noting that no
single factor would be dispositive, the Commission proposes the factors
listed below:
(1) Physical characteristics including such common characteristics
as: Infrastructure, property ownership, interconnection agreements,
control facilities, access and easements, interconnection facilities up
to the point of interconnection to the distribution or transmission
system, collector systems or facilities, points of interconnection,
motive force or fuel source, off-take arrangements, property leases,
and connections to the electrical grid; and (2) ownership/other
characteristics, including such characteristics as whether the
facilities in question are: Owned or controlled by the same person(s)
or affiliated persons(s), operated and maintained by the same or
affiliated entity(ies), selling to the same electric utility, using
common debt or equity financing, constructed by the same entity within
12 months, managing a power sales agreement executed within 12 months
of a similar and affiliated facility in the same location, placed into
service within 12 months of an affiliated project's commercial
operation date as specified in the power sales agreement, or sharing
engineering or procurement contracts. The Commission solicits comments
on whether the Commission should rely on some or any of these factors,
or other factors, or whether the various factors should be considered
together and weighed.
106. Finally, for its PURPA Regulations, the Commission generally
relies on the definition of an ``affiliate'' provided in its
regulations at Sec. 35.36(a)(9). The Commission will continue to rely
on this definition and notes that subsection (iii) of the Commission's
regulation provides that the Commission may determine, after
appropriate notice and opportunity for hearing, that a person stands in
such relation to a specified company that there is likely to be an
absence of arm's-length bargaining in transactions between them as to
make it necessary or appropriate in the public interest or for the
protection of investors or consumers that the person be treated as an
affiliate.\148\ The Commission intends, when applying its rules on
separate facilities, to consider this provision of its regulations,
when entities otherwise would not be deemed affiliates under the other
provisions of the definition, to determine whether a person
nevertheless should be treated as an affiliate. In doing so, the
Commission could take into consideration many of the same factors that
would reasonably be considered in evaluating whether facilities located
over one and less than ten miles apart are a single facility or
separate facilities.
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\148\ 18 CFR 35.36(a)(9)(iii).
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107. The Commission believes that this change, together with the
proposed definition of ``electrical generating equipment'' and revision
to the FERC Form No. 556 discussed below, would more closely align with
Congress's requirement that QFs seeking to certify as small power
production facilities are in fact below the statutory limit for such
facilities.\149\
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\149\ See 16 U.S.C. 796(17)(A)(ii) (defining small power
production facility as inter alia ``a facility which is an eligible
solar, wind, waste, or geothermal facility, or a facility which--. .
. 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 megawatts.'').
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b. Electrical Generating Equipment
108. The Commission proposes defining ``electrical generating
equipment'' to refer to all boilers, heat recovery steam generators,
prime movers (any mechanical equipment driving an electric generator),
electrical generators, photovoltaic solar panels and/or inverters, fuel
cell equipment and/or other primary power generation equipment used in
the facility, excluding equipment for gathering energy to be used in
the facility. The Commission expects that each wind turbine on a wind
farm and each solar panel in a solar facility would be considered
``electrical generating equipment'' because each wind turbine and each
solar panel is independently capable of producing electric energy. We
seek comments on this approach, and on what--if not individual wind
turbines and solar panels--should be considered ``electrical generating
equipment'' for wind and solar plants.
109. The Commission also proposes specifying how to measure the
distance between facilities that have multiple separate sets of
``electrical generating equipment'' such as wind farms and solar
facilities. In this NOPR, the Commission proposes measuring the
distance between the nearest ``electrical generating equipment'' of any
two facilities such that, for the facilities to be considered
irrebuttably separate, all such equipment of one QF must be at least
ten miles away from all such equipment of another QF. We believe this
is the appropriate way to measure the distance between affiliated sets
of ``electrical generating equipment'' because this reflects the
distance between the components directly tied to producing electric
energy.
110. The Commission seeks comment on this approach, and whether
alternative approaches would be more appropriate. For example, some
parties have suggested in QF certification proceedings that the
Commission could use the geographic center of the plant footprint or a
weighted average of the locations of the individual pieces of
``electrical generating equipment.'' \150\ The Commission is concerned
these approaches may be easily gamed, but seeks comment on whether they
may be constructed in a way that would prevent gaming, and whether such
formulations would be preferable to the approach proposed above.
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\150\ See Beaver Creek Wind II, LLC, 160 FERC ] 61,052, at P 9
(2017).
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3. Corresponding Changes to the FERC Form No. 556
111. If the changes to the evaluation of whether QFs are separate
facilities are implemented as proposed above, the Commission proposes
corresponding changes to the FERC Form No. 556. Currently, item 8a of
Form No. 556 requires that the applicant identify any facilities with
electrical generating equipment within one mile of the instant
facility's electrical generating equipment, as shown below in Figure 1.
[[Page 53262]]
[GRAPHIC] [TIFF OMITTED] TP04OC19.005
112. The Commission proposes adding a new item 8b,\151\ which would
be similar to the current item 8a, except that it would cover
affiliated facilities whose nearest electrical generating equipment is
greater than 1 mile and less than 10 miles from the electrical
generating equipment of the instant facility.
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\151\ Subsequent items in that section of the form would be
retained, but re-numbered and moved down accordingly.
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113. The Commission proposes that the instructions for the new item
8b would also allow applicants with facilities identified under item 8b
(i.e., facilities more than one mile apart and less than ten miles
apart) to, if they choose, explain (in the Miscellaneous section
starting on page 19 of the form) why the facilities identified under
item 8b should be considered separate facilities, considering the
relevant physical and ownership factors. We further propose to provide
reference, in the instructions to the new item 8b, to the paragraphs of
the final rule under this rulemaking which discuss the relevant
physical and ownership factors that may be asserted to defend against
rebuttal.
114. The Commission seeks comment on whether item 8a (existing)
should be revised and item 8b (as newly proposed) written to require
that the applicant specify the distance from the instant facility to
each affiliated facility listed. We also seek comment on whether items
8a and (new) 8b should require the applicant to document (in the
Miscellaneous section on page 19 of the Form No. 556) how the distances
reported were calculated. Specifically, we seek comment on whether the
applicant should be required to identify the particular electrical
generating equipment and associated geographic coordinates used in
calculating the distance(s) between the facility(ies).
115. The Commission notes that item 8a currently requires
applicants to list all affiliated ``facilities.'' Under this
requirement, an applicant would have to list all affiliated QFs and
affiliated non-QFs. We request comment on whether such a requirement is
more burdensome than necessary. It is not clear that requiring the
listing of affiliated non-QFs is necessary in monitoring for compliance
with the relevant QF regulations, which are concerned only with the
distance between affiliated QFs. Particularly under the newly proposed
item 8b, where applicants would list facilities located more than one
mile apart but less than ten miles apart, many more facilities are
likely to be listed than are currently listed in the existing item 8a.
As such, we seek comment on whether we should revise item 8a (existing)
and write item 8b (as newly proposed) to require that applicants list
only affiliated QFs, or whether there is reason to continue to require
all affiliated facilities to be listed.
116. The Commission also seeks comment on whether item 3c
(geographic coordinates) and the Geographic Coordinates instructions on
page 4 of the current Form No. 556 should be modified such that
reporting of geographic coordinates should be required for all
applications, rather than only for applications where there is no
facility street address (as is now the case). We believe such
information may provide more transparency in approximate distances
between facilities, and that such transparency may be useful for both
the public and Commission staff in monitoring compliance with the
Commission's QF regulations.
117. We note, as we did in Order No. 732,\152\ and as we do in the
general form instructions on page 4 of the Form No. 556, that such
coordinates can be obtained through certain free online map services
(with links and instructions available through the Commission's QF
website); GPS devices (including smartphones, which are now nearly
ubiquitous); Google Earth; property surveys; various engineering or
construction drawings; property deeds; or municipal or county maps
showing property lines. We also note that the Commission has a link on
its QF web page (www.ferc.gov/QF) which provides assistance with
determining geographic coordinates of facilities. As such, we believe
that the burden that would be created by requiring every QF to provide
geographic coordinates would be limited. Even so, we seek comment on
whether the value of the information to the public and the Commission
would outweigh the limited burden.
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\152\ Revisions to Form, Procedures, and Criteria for
Certification of Qualifying Facility Status for a Small Power
Production or Cogeneration Facility, Order No. 732, 130 FERC ]
61,214, at P 100 (2010).
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D. PURPA Section 210(m) Rebuttable Presumption of Nondiscriminatory
Access to Markets
118. In accordance with PURPA section 210(m), the PURPA Regulations
permit an electric utility to file an application with the Commission
requesting relief from the requirement to enter into new contracts or
obligations to purchase electric energy from a QF if the Commission
finds that a QF has nondiscriminatory access to certain markets. As
relevant here, the PURPA Regulations establish a rebuttable presumption
that QFs with a net power production capacity at or below 20 MW lack
nondiscriminatory access to such markets. The Commission now proposes
[[Page 53263]]
to revise the PURPA Regulations to reduce the capacity level at which
this presumption attaches for small power production facilities, but
not cogeneration facilities, from 20 MW to 1 MW.\153\
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\153\ The Commission also proposes to revise the PURPA
Regulations to replace ``Midwest Independent Transmission System
Operator, Inc. (Midwest ISO)'' and ``ISO New England, Inc.'' in 18
CFR 292.309(e), with ``Midcontinent Independent System Operator,
Inc. (MISO)'' and ``ISO New England Inc.,'' respectively.
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1. Background
119. In 2005, Congress amended PURPA section 210 to add section
210(m), which was intended to reflect the fact that organized electric
markets have been created in RTOs/ISOs that provide alternative markets
for sales by QFs. Section 210(m) provides for termination of the
requirement that an electric utility enter into a new obligation or
contract to purchase from a QF if the QF, in fact, has
nondiscriminatory access to certain defined types of markets.\154\
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\154\ See 16 U.S.C. 824a-3(m).
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120. In Order No. 688, the Commission identified certain specified
markets as qualifying for section 210(m) relief from the PURPA
mandatory purchase obligation, provided that QFs, in fact, have
nondiscriminatory access to such markets.\155\ Because section 210(m)
requires the Commission to make a final determination on applications
to terminate the requirement to enter into new obligations or contracts
to purchase from QFs within 90 days of the application, the Commission
established certain rebuttable presumptions to make the processing of
the applications possible given this 90-day action requirement.
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\155\ New PURPA Section 210(m) Regulations Applicable to Small
Power Production and Cogeneration Facilities, Order No. 688, 117
FERC ] 61,078, at PP 9-12 (2006), order on reh'g, Order No. 688-A,
119 FERC ] 61,305 (2007), aff'd sub nom. Am. Forest & Paper Ass'n v.
FERC, 550 F.3d 1179 (D.C. Cir. 2008).
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121. As relevant here, one of those rebuttable presumptions,
contained in Sec. 292.309(d)(1) of the PURPA Regulations,\156\ is that
a QF with a net power production capacity at or below 20 MW does not
have nondiscriminatory access to markets. In creating this rebuttable
presumption, the Commission found persuasive arguments that some QFs
may, in practice, not have nondiscriminatory access to markets in light
of their small size.
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\156\ 18 CFR 292.309(d)(1).
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122. The Commission noted that there was agreement among commenters
representing both QFs and utilities that small size could affect a QF's
ability to access markets.\157\ The Commission explained that smaller
QFs often are interconnected at the distribution level and that QFs
interconnected at the distribution level may, in practice, lack the
same level of access to markets as those connected to transmission
lines.\158\ The Commission also explained that smaller QFs were more
likely to have to overcome obstacles that larger QFs would not have to
overcome, such as jurisdictional differences, pancaked delivery rates,
and administrative burdens to obtaining access to distant buyers.
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\157\ E.g., Order No. 688, 117 FERC ] 61,078 at PP 72-73; Order
No. 688-A, 119 FERC ] 61,305 at P 103.
\158\ Order No. 688-A, 119 FERC ] 61,305 at PP 94-103.
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123. The Commission found that such difficulties supported a
rebuttable presumption that smaller QFs have ``substantially less
ability to access wholesale markets than do larger QFs.'' \159\ The
Commission further explained that it set this rebuttable presumption at
20 MW, rather than at a much smaller size of one or two MW, to reflect
its understanding of ``the general nature of QFs' interconnection
practices and the relative capabilities of small entities'' to
participate in markets.\160\ The Commission acknowledged that ``[t]here
is no perfect bright line that can be drawn,'' but stated that it
``reasonably exercised [its] discretion in adopting a 20 MW or below
demarcation for purposes of determining which QFs are unlikely to have
nondiscriminatory access to markets.'' \161\
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\159\ Id. P 96.
\160\ Id. P 101.
\161\ Id. P 95.
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124. Order No. 688 placed the burden of proof on the electric
utility to demonstrate that a smaller QF has nondiscriminatory access
to energy markets.\162\ The Commission, in Order No. 688, did not
specify what evidence a utility could set forth to rebut the
presumption, but noted that ``relevant evidence may include the extent
to which the QF has been participating in the market or is owned by, or
is an affiliate of, a[n] entity that has been participating in the
relevant market.'' \163\
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\162\ 18 CFR 292.310(d)(2) (to the extent an electric utility
seeks relief from the purchase obligation with respect to a QF 20 MW
or smaller, the electric utility bears burden to prove the QF has
nondiscriminatory access to the wholesale markets).
\163\ Order No. 688, 117 FERC ] 61,078 at P 78. In saying this,
however, the Commission did not intend to suggest that these two
facts alone would necessarily be a basis for granting relief from
PURPA's mandatory purchase obligation. PPL Elec. Utils. Corp., 145
FERC ] 61,053, at P 23 & n.25 (2013), order denying reh'g, 148 FERC
] 61,207 (2014).
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125. The Commission in Order No. 688 stated that ``[t]here is
nothing in section 210(m) of PURPA to suggest that Congress intended to
ensure a QF's commercial viability. Nor does the statute require the
Commission to find that the `economic and technical equivalent to
mandatory purchase is available through a competitive market' before it
terminates the requirement that an electric utility enters into a new
contract or obligation to purchase electric energy from QFs.'' \164\
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\164\ Order No. 688, 117 FERC ] 61,078 at P 37.
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2. Commission Proposal
126. In 2006, when Order No. 688 was issued, the organized electric
markets had been in existence for only a few years and were not well
understood by all market participants. Now, twelve years later, the
markets are more mature, and the mechanics of participation in such
markets are improved and better understood. Consequently, the
Commission believes that small power production facilities below 20 MW
should be able to participate in such markets under most circumstances.
The Commission therefore proposes to revise Sec. 292.309(d) of the
PURPA Regulations to reduce the net power production capacity level at
which the presumption of nondiscriminatory access to a market attaches
for small power production facilities, but not cogeneration facilities,
from 20 MW to 1 MW.
127. The Commission believes that, in light of the maturation of
organized electric markets, such a reduction is consistent with
Congress's intent to relieve electric utilities of their obligation to
purchase when a QF has nondiscriminatory access to competitive markets.
Under current market conditions, it is fair to expect that small power
production facilities above 1 MW can acquire the administrative and
technical expertise necessary to obtain nondiscriminatory access to a
market.
128. The Commission, in establishing the presumption that QFs whose
net power production capacity was 20 MW or below lacked
nondiscriminatory access to markets defined in sections 210(m)(1)(A)-
(C) of PURPA, acknowledged that ``there is no unique and distinct
megawatt size that uniquely determines if a generator is small.'' \165\
In using 20 MW to separate the presumption that large QFs had
nondiscriminatory access and small QFs lacked such access, the
Commission recognized: (1) Order No. 671's exemption for QFs that are
20 MW or smaller from sections 205 and 206 of the FPA; and (2) Order
Nos. 2006 and 2006-
[[Page 53264]]
A's setting 20 MW as the demarcation for different interconnection
standards between small and large generators.\166\ While the Commission
has not (and does not here) propose to revise the exemptions for QFs
from sections 205 and 206 of the FPA, the Commission has taken steps to
ease both interconnection and market access for generation resources
with small capacities since it first implemented section 210(m) of
PURPA.
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\165\ Order No. 688-A, 119 FERC ] 61,305 at P 97.
\166\ See Order No. 688, 117 FERC ] 61,078 at P 76, order on
reh'g, Order No. 688-A, 119 FERC ] 61,305 at P 97; see also 18 CFR
292.601(c)(1) (``sales of energy or capacity made by qualifying
facilities 20 MW or smaller, or made pursuant to a contract executed
on or before March 17, 2006 or made pursuant to a state regulatory
authority's implementation of section 210, the Public Utility
Regulatory Policies Act of 1978, 16 U.S.C. 824a-1, shall be exempt
from scrutiny under sections 205 and 206''); Revised Regulations
Governing Small Power Production and Cogeneration Facilities, Order
No. 671, 114 FERC ] 61,102, at P 98 (2006), order on reh'g, Order
No. 671-A, 115 FERC ] 61,225 (2006) (establishing exemption for QFs
20 MW or below from 205 and 206 of FPA); Standardization of Small
Generator Interconnection Agreements and Procedures, Order No. 2006,
111 FERC ] 61,220, at P 75, order on reh'g, Order No. 2006-A, 113
FERC ] 61,195 (2005), order granting clarification, Order No. 2006-
B, 116 FERC ] 61,046 (2006).
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129. For example, the Commission has required public utilities to
provide a Fast-Track interconnection process for some interconnection
customers whose capacity is up to and including 5 MW (up from the
previous 2 MW threshold),\167\ and has required each RTO/ISO to revise
its tariff to include a participation model for electric storage
resources that establishes a minimum size requirement for participation
in the RTO/ISO markets that does not exceed 100 kW.\168\ While both of
these changes do not apply only to generation types that could become
QFs or to RTOs/ISOs, we believe they generally show that small power
production facilities below 20 MW, specifically those whose capacity
exceeds 1 MW now have greater access to the markets defined in section
210(m)(1) of PURPA than they did when the Commission first established
the presumptions of market access. Under this proposal, like QFs over
20 MW today, small power production facilities over 1 MW would be able
to rebut the presumption of access due to operational characteristics
or transmission constraints.\169\
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\167\ Small Generator Interconnection Agreements and Procedures,
Order No. 792, 145 FERC ] 61,159, at P 103 (2013), clarifying, Order
No. 792-A, 146 FERC ] 61,214 (2014).
\168\ Electric Storage Participation in Markets Operated by
Regional Transmission Organizations and Independent System
Operators, Order No. 841, 162 FERC ] 61,127, at P 265 (2018).
\169\ See 18 CFR 292.309(c), (e), (f).
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130. The Commission does not propose to make the same reduction
applicable to cogeneration facilities. Unlike small power production
facilities, which are constructed solely to produce and sell
electricity, cogeneration facilities seeking QF certification after
February 2, 2006 are statutorily required to show that they are
intended primarily to provide heat for an industrial, commercial,
residential or institutional process rather than fundamentally for sale
to an electric utility.\170\ Consequently, the production and sale of
electricity is a byproduct of these processes, and owners of
cogeneration facilities might not be as familiar with energy markets
and the technical requirements for such sales. Retention of the
existing 20 MW level for the presumption of access to markets therefore
would be appropriate for cogeneration facilities.
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\170\ See 16 U.S.C. 824a-3(n); 18 CFR 292.205(d)(3). We
recognize that cogeneration facilities seeking certification 5 MW or
smaller after February 2, 2006 are presumed to satisfy this
requirement. 18 CFR 292.205(d)(4).
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3. Reliance on RFPs and Liquid Market Hubs To Terminate Purchase
Obligation
131. NARUC has proposed that the Commission allow utilities to rely
on RFPs (in combination with liquid market hubs) to establish
eligibility to terminate a utility's purchase obligation pursuant to
PURPA section 210(m)(1)(C).\171\ After describing generally how such a
proposal might be structured, NARUC suggests that ``[t]he Commission
should create a yardstick of characteristics that describe in detail
how a utility could qualify for an exemption under subparagraph (C).''
\172\
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\171\ See NARUC Supplemental Comments, Docket No. AD16-16-000
(Oct. 17, 2018).
\172\ Id., attach. A at 9.
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132. Under the PURPA Regulations, electric utilities already may
seek to terminate their mandatory purchase obligation pursuant to PURPA
section 210(m)(1)(C) by demonstrating that a particular market is of
comparable competitive quality to markets described in PURPA section
210(m)(1)(A) and (B).\173\ The current PURPA Regulations are not
prescriptive about how an electric utility must make such a
demonstration and nothing in the PURPA Regulations or precedent would
bar an electric utility from arguing that RFPs in combination with
liquid market hubs are sufficient to satisfy PURPA section
210(m)(1)(C).
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\173\ Order No. 688-A, 119 FERC ] 61,305 at P 43 (``Congress
believed the two types of markets identified in subparagraphs (A)
and (B), while distinct between themselves, contain certain
competitive qualities that justify termination of the purchase
requirement for any QF with nondiscriminatory access to those
markets. Subparagraph (C) directs the Commission to consider these
competitive qualities when analyzing whether there are other markets
that, while not meeting the specific requirements of subparagraphs
(A) and (B), are sufficiently competitive to justify termination of
the purchase requirement.''); cf. Pub. Serv. Co. of N.M., 140 FERC ]
61,191, at PP 29-38 (2012) (denying application to terminate
mandatory purchase obligation on the grounds that the Four Corners
Hub is not of comparable competitive quality to markets in sections
210(m)(1)(A) and (B) of PURPA).
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133. The Commission believes that a properly structured proposal
along the lines proposed by NARUC potentially could satisfy the
statutory requirements under PURPA section 210(m)(1)(C) and will
consider such proposals on a case-by-case basis. Although the
Commission does not in this NOPR propose additional criteria a utility
or utilities may rely on to satisfy PURPA section 210(m)(1)(C), the
Commission seeks comments on any specific factors that would be useful
to consider in determining how a utility or utilities may satisfy PURPA
section 210(m)(1)(C).
E. Legally Enforceable Obligation
134. Section 292.304(d) of the PURPA Regulations provides that a QF
can choose to have its rates based on the avoided cost calculated at
the time of delivery or at the time a LEO is incurred. However, the
PURPA Regulations do not specify when or how a LEO is established.\174\
To date, the Commission has not identified specific criteria that
states must follow in determining when a LEO is established.
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\174\ But see, e.g., FLS, 157 FERC ] 61,211 at P 23
(``[R]equiring a QF to tender an executed interconnection agreement
is equally inconsistent with PURPA and our regulations. Such a
requirement allows the utility to control whether and when a legally
enforceable obligation exists--e.g., by delaying the facilities
study or by delaying the tendering by the utility to the QF of an
executable interconnection agreement.''); Memorandum of Agreement
between Idaho Public Utilities Commission and Federal Energy
Regulatory Commission at 2 (Dec. 24, 2013), available at https://www.ferc.gov/legal/mou/mou-idaho-12-2013.pdf (Idaho Commission
acknowledging that ``a legally enforceable obligation may be
incurred prior to the formal memorialization of a contract to
writing'').
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135. Although not specifying such criteria, the Commission has
found that certain prerequisites to QFs obtaining a LEO imposed by some
states--such as a utility's execution of an interconnection agreement
or power purchase agreement--are unreasonable.\175\ The
[[Page 53265]]
Commission does not propose to overturn this precedent because the
Commission continues to believe that imposition of the prerequisites
addressed in its precedent is unreasonable and does not satisfy PURPA's
requirement that the Commission prescribe rules as necessary to
encourage the development of QFs.
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\175\ See, e.g., FLS, 157 FERC ] 61,211 at P 26 (requiring
signed interconnection agreement as prerequisite to legally
enforceable obligation is inconsistent with PURPA Regulations);
Grouse Creek Wind Park, LLC, 142 FERC ] 61,187, at P 40 (2013)
(Grouse Creek) (finding that requiring a QF to file complaint as
prerequisite to a legally enforceable obligation is inconsistent
with PURPA Regulations); Murphy Flat Power, LLC, 141 FERC ] 61,145,
at P 24 (2012) (finding that requiring a signed and executed
contract with an electric utility as a prerequisite to a legally
enforceable obligation is inconsistent with PURPA Regulations);
Rainbow Ranch Wind, LLC, 139 FERC ] 61,077 (2012) (same); Cedar
Creek Wind, LLC, 137 FERC ] 61,006, at P 36 (2011) (Cedar Creek)
(same).
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136. As discussed below, however, the Commission proposes to amend
Sec. 292.304(d) of the PURPA Regulations to require that a QF
demonstrate its commercial viability and financial commitment to
construct its facility through objective and reasonable state-
determined criteria before being entitled to a LEO.
1. Background and Need for Reform
137. The Commission created the concept of a LEO in Order No. 69
``to prevent a utility from circumventing the requirement that provides
capacity credit for an eligible qualifying facility merely by refusing
to enter into a contract with the qualifying facility.'' \176\ The
Commission has held that requiring a fully-executed contract or
executed interconnection agreement as a condition precedent to
obtaining a LEO is inconsistent with PURPA.\177\
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\176\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,880.
\177\ FLS, 157 FERC ] 61,211 at P 26; Cedar Creek, 137 FERC ]
61,006 at P 35.
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138. The record indicates that some QFs believe that informing a
utility that the QF intends to sell energy to that utility at some
point in the future is sufficient to create a LEO and thereby establish
the price for future deliveries, regardless of whether the QF project
being considered ever generates electricity.\178\ This approach, Xcel
explains, puts the electric utility and its customers at risk since the
utility is required to reliably plan its system and resources for a QF
that will not be operational for many years, or not at all, thereby
creating uncertainty for the utility and its consumers.\179\
Conversely, QF developers argue generally that they need the certainty
of a LEO to obtain the financing to build their facilities in the first
place, as QFs do not have the same ability that the electric utilities
have to ``rate base'' their facilities and, thereby, guarantee capital
recovery.\180\
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\178\ See, e.g., EEI Supplemental Comments, attach. A at 7.
\179\ See Xcel Comments, Docket No. AD16-16-000, at 15-16 (Nov.
7, 2016) (``If a utility is required to enter into a LEO with a QF,
it will (or may be required to) factor the capacity associated with
that LEO into its resource planning efforts. And if that project
does not materialize--for whatever reason--the utility's resource
plan will need to change. Depending on the amount of capacity
associated with the LEO or LEOs that the utility has pending, the
utility may have to scramble to replace the capacity associated with
the now non-existent LEO(s). Such a scramble would very likely
result in payment of above-market prices for capacity and energy,
again violating the indifference standard. Moreover, additional
capacity over and above the capacity associated with the non-
existent QF might have been procured, at additional cost to
customers, to manage the variability of that anticipated QF. Of
greater concern would be a situation where additional capacity is
simply not available to make up for the capacity that the QF was
expected to provide under the LEO, putting system reliability at
risk and potentially putting the utility at risk of violations of
NERC reliability standards approved by the Commission. Further,
attempting to lock in long-term prices far in advance of the start
date of deliveries under a LEO creates significant potential for
payments in excess of avoided cost rates.'').
\180\ Compare EEI Supplemental Comments, attach. A at 7 with
Renewable Energy Coalition Comments, Docket No. AD16-16-000, at 11-
12 (Nov. 7, 2016) (``Long-term contracts allow existing QFs to
remain economically viable in times of long resource sufficiency
periods with low avoided cost rates. . . . Unlike utilities, which
can spread the costs of resource acquisition over the entire useful
life of a facility, QFs do not have this option because doing so
could expose ratepayers to unnecessary risk from deviations in
avoided costs.''); and Northwest and Intermountain Power Producers
Coalition Comments, Docket No. AD16-16-000, at 5 (Nov. 4, 2016)
(``To earn a return on investment, there must first be the prospect
of a return on investment. It takes at least 15 years in most cases
involving [Northwest and Intermountain Power Producers Coalition]
members to recover their invested capital and to retire the debt
incurred to build a renewable energy facility. It takes a contract
term of 20 years to earn a justifiable return on that
investment.'').
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139. While it is up to states to reasonably determine the
circumstances and thus when a legally enforceable obligation
arises,\181\ states may not impose obstacles that make it unreasonably
difficult to obtain a LEO.\182\ Given the significant changes in the
electric industry since PURPA's enactment, as discussed above, the
Commission finds that it now may be appropriate to: (1) Specify the
commercial viability of a QF and financial commitment to construct the
proposed project as the necessary pre-requisites for obtaining a LEO;
and (2) provide guidance for states as to what types of criteria may be
applied to make the necessary demonstration.
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\181\ W. Penn Power Co., 71 FERC ] 61,153, at 61,495 (1995)
(West Penn) (``It is up to the States, not this Commission, to
determine the specific parameters of individual QF power purchase
agreements, including the date at which a legally enforceable
obligation is incurred under State law. Similarly, whether the
particular facts applicable to an individual QF necessitate
modifications of other terms and conditions of the QF's contract
with the purchasing utility is a matter for the States to determine.
This Commission does not intend to adjudicate the specific
provisions of individual QF contracts.'' (footnotes omitted)).
\182\ See, e.g., Cedar Creek, 137 FERC ] 61,006 at P 35 & n.57
(citing West Penn, 71 FERC ] 61,153 at 61,495).
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2. Commission Proposal
140. The Commission proposes to add regulatory text in Sec.
292.304(d)(3) of the PURPA Regulations to require QFs to demonstrate
that a proposed project is commercially viable and the QF has a
financial commitment to construct the proposed project pursuant to
objective, reasonable, state-determined criteria in order to be
eligible for a LEO. The Commission further proposes to provide that,
although a showing of commercial viability and the QF's financial
commitment to construct the project is required, states have
flexibility as to what constitutes an acceptable showing of commercial
viability and financial commitment.
141. Our objective in requiring a showing of commercial viability
and the QF's financial commitment to construct the project is to ensure
that no electric utility obligation is triggered for those QF projects
that are not sufficiently advanced in their development and, therefore,
for which it would be unreasonable for a utility to include in its
resource planning, while at the same time ensuring that the purchasing
utility does not unilaterally and unreasonably decide when its
obligation arises. States may require a showing, for example, that a QF
has satisfied, or is in the process of undertaking, at least some of
the following prerequisites: (1) Obtaining site control adequate to
commence construction of the project at the proposed location; (2)
filing an interconnection application with the appropriate entity; (3)
securing local permitting and zoning; or (4) other similar, objective,
reasonable criteria that allow a QF to demonstrate its commercial
viability and financial commitment to construct the facilities. These
indicia are not intended to be exhaustive and the Commission seeks
comment on these indicia and others that also might be appropriate for
consideration.
142. We believe requiring QFs to demonstrate their commercial
viability and financial commitment to construct the facilities based on
such indicia before obtaining a LEO will allow electric utilities to
reliably plan for their systems ensuring resource adequacy.
Additionally, states' development and definition of objective and
reasonable factors to determine commercial viability and financial
commitment to construct a facility encourage the development of QFs by
providing QFs
[[Page 53266]]
with more certainty as to when they will obtain a LEO.\183\
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\183\ Because QFs already in operation have necessarily
demonstrated a commitment to construct the project, the Commission
does not intend commercial viability and financial commitment
requirements to serve as prerequisites to QFs already in operation
with existing LEOs to obtaining new LEOs.
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F. QF Certification Process
1. Background and Need for Reform
143. The Commission provides two paths for an entity to obtain QF
status: self-certification and Commission certification.\184\ Self-
certification, the procedures for which are contained in Sec.
292.207(a) of the PURPA Regulations,\185\ is the more common method of
certification. When an applicant self-certifies (or self-recertifies),
it certifies that its facility satisfies the requirements for QF
status. Under the self-certification (or self-recertification) approach
a QF is assigned a docket number, and Commission staff reviews the
filing to discern that the information required in Form No. 556 appears
to have been included, but a notice of the self-certification typically
is not published in the Federal Register and Commission staff does not
otherwise evaluate whether the applicant meets the requirements for QF
status.
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\184\ There is no fee for a self-certification; there is,
however, a fee for Commission certification. 18 CFR 381.505. For
2018, an application for Commission certification requires a filing
fee of $23,330 for small power production facilities and $26,410 for
cogeneration facilities. In recent years, the Commission has
received approximately 5 applications per year for Commission-
certification, with the remaining applicants (approximately 3,400
per year) filing for self-certification of their facilities. See
Commission Information Collection Activities, Notice of information
Collection and Request for Comments, Docket No. IC19-16-000, 84 FR
9317, 9318 (Mar. 7, 2019). The Commission will not issue notice of
nor process an application for Commission certification without
receipt of the applicable fee.
\185\ 18 CFR 292.207(a).
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144. The Commission recognized that the self-certification process
may not always satisfy the needs of certain stakeholders or interested
entities. Accordingly, the Commission established, in Sec. 292.207(b)
of the PURPA Regulations,\186\ what is called the ``optional
procedure'' for QF status. Under the optional procedure, an entity may
file an application for a determination by the Commission that a
facility meets the requirements for QF status. The application is
noticed in the Federal Register, the Commission decides whether the
applicant meets the requirements for QF status, and then issues an
order either granting or denying the requested certification.
---------------------------------------------------------------------------
\186\ 18 CFR 292.207(b).
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145. After the enactment of EPAct 2005, which imposed new
requirements for QF status for ``new'' cogeneration facilities,\187\
the Commission issued Order No. 671,\188\ which implemented new
requirements for QF status including a formal filing requirement for
all QFs claiming QF status whether through self-certification or
Commission certification.\189\ As part of that implementation, for the
first time, notices of some (but not all) self-certifications were
required to be published in the Federal Register. Specifically, Sec.
292.207(a)(iv) provides that self-certifications or self-
recertifications, other than for ``new'' cogeneration facilities, would
not be published in the Federal Register. In 2010, in Order No. 732,
the Commission adopted an exemption from the filing requirement for
generating facilities with net power production capacities of 1 MW or
less.\190\
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\187\ ``New'' cogeneration facilities are defined as any
cogeneration facility that was either not certified a qualifying
cogeneration facility on or before August 8, 2005, or that had not
filed a notice of self-certification, self-recertification or an
application for Commission certification or Commission
recertification as a qualifying cogeneration facility prior to
February 2, 2006. 18 CFR 292.205(d)(1).
\188\ Order No. 671, 114 FERC ] 61,102, order on reh'g, Order
No. 671-A, 115 FERC ] 61,225 (2006).
\189\ See 18 CFR 292.203(a)(3), (b)(2).
\190\ Revisions to Form, Procedures, and Criteria for
Certification of Qualifying Facility Status for a Small Power
Production or Cogeneration Facility, Order No. 732, 130 FERC ]
61,214 (2010).
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146. The Commission has explained that, to challenge the self-
certification of a QF, an entity must file a petition for declaratory
order and pay the associated filing fee, which currently is $28,990.
The Commission in Chugach Electric Association, Inc. explained that
Order No. 671 did not create a right for a challenging entity to submit
a motion for revocation in response to a notice of self-certification.
Rather, the Commission explained that QF self-certification is
effective upon filing, and therefore challenging a self-certification
requires a separate petition for declaratory order asking that the
Commission revoke QF status.\191\
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\191\ Chugach Elec. Assoc., Inc., 121 FERC ] 61,287, at PP 51-54
(2007); see also Hydro Investors, Inc. v. Trafalgar Power, Inc., 94
FERC ] 61,207, at 61,780, reh'g denied, 95 FERC ] 61,120 (2001).
---------------------------------------------------------------------------
147. A concern with the existing procedures with respect to self-
certification is whether protestors should bear the burden of filing a
separate petition for declaratory order and paying the associated
filing fee for a declaratory order to object to a questionable self-
certification.\192\
---------------------------------------------------------------------------
\192\ EEI Supplemental Comments, attach. A at 16.
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2. Commission Proposal
148. The Commission proposes to change Sec. 292.207(a) of the
PURPA Regulations to allow a party to intervene and to file a protest
of a self-certification or self-recertification of a facility without
the necessity of filing a separate petition for declaratory order and
without having to pay the filing fee required for a declaratory order.
Because an applicant for self-certification or self-recertification is
required to serve a copy of its submission on interested electric
utilities (principally those it is interconnected with and those it
will be selling to) as well as the relevant state regulatory
authorities, the Commission will allow interested persons 30 days from
the date of filing at the Commission to intervene and/or to file a
protest (without paying a filing fee).\193\
---------------------------------------------------------------------------
\193\ 18 CFR 292.207(c)(1).
---------------------------------------------------------------------------
149. Any party submitting a protest would have the burden of
specifying facts that make a prima facie demonstration that the
facility described in the self-certification or self-recertification
does not satisfy the requirements for QF status.\194\ General
allegations that the facility is not a QF without reference to the
specific regulatory provision that has not been satisfied (and without
an explanation why the provision has not been satisfied), or
unsupported assertions that the self-certification does not satisfy an
aspect of the PURPA Regulations, would not satisfy this burden and
would not be a basis for denial of certification. However, if this
prima facie burden is met, then the burden would shift to the applicant
submitting the self-certification or self-recertification to
demonstrate that the claims raised in the protest are incorrect and
that certification is, in fact, warranted.
---------------------------------------------------------------------------
\194\ See 18 CFR 385.211.
---------------------------------------------------------------------------
150. As explained above, QF self-certification is effective upon
filing, and remains effective if a protest is filed, until such time as
the Commission rules that certification is revoked. The Commission
proposes that it would issue an order within 90 days of the date the
protest is filed. The Commission also reserves the right to request
more information from the protester, the entity seeking QF status, or
both.\195\ If
[[Page 53267]]
the Commission requests more information, the time period for the
Commission order would be extended to 60 days from the filing of a
complete answer to the information request.
---------------------------------------------------------------------------
\195\ Such information requests could be issued by the
Commission or by staff under any applicable delegated authority. For
example, the Director of the Office of Energy Market Regulation is
authorized under 18 CFR 375.307(b)(3)(ii) to ``[i]ssue and sign
requests for additional information regarding applications, filings,
reports and data processed by the Office of Energy Market
Regulation.''
---------------------------------------------------------------------------
151. There may be instances, however, when the Commission needs
additional time to review the record in light of the nature of the
protests. In those cases, the Commission proposes that, in addition to
any extension resulting from a request for information, the Commission
also may toll the 90-day period during which the Commission commits to
act for one additional 60-day period. The Commission proposes to
delegate to the Commission's Secretary, or the Secretary's designee,
the authority to toll the 90-day period for this purpose.
152. The Commission believes these procedures will allow for timely
but thorough review of protested self-certifications and re-
certifications. The Commission seeks comment on whether these
procedures impose an undue burden on the QF even though the QF remains
certified pending the review.
III. Information Collection Statement
153. The Paperwork Reduction Act \196\ requires each federal agency
to seek and obtain the Office of Management and Budget's (OMB) approval
before undertaking a collection of information (including reporting,
record keeping, and public disclosure requirements) directed to ten or
more persons or contained in a rule of general applicability. OMB
regulations require approval of certain information collection
requirements contemplated by proposed rules (including deletion,
revision, or implementation of new requirements).\197\ Upon approval of
a collection of information, OMB will assign an OMB control number and
an expiration date. Respondents subject to the filing requirements of a
rule will not be penalized for failing to respond to the collection of
information unless the collection of information displays a valid OMB
control number.
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\196\ 44 U.S.C. 3501-21.
\197\ See 5 CFR 1320.11.
---------------------------------------------------------------------------
Public Reporting Burden: In this NOPR, the Commission proposes to
revise its regulations implementing PURPA. The principal changes that
affect information collection, i.e., the Form No. 556, are as follows:
first, the Commission proposes to change 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, by allowing electric
utilities, state regulatory authorities, or other interested parties to
show that facilities over one and less than ten miles apart actually
are a single facility; and second, to allow a party to protest a self-
certification or self-recertification of a facility without a fee.
The estimated changes to the burden and cost \198\ of the
information collection affected by this NOPR, i.e., Form No. 556,
follow.
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\198\ The burden costs are based on FERC's 2018 average annual
salary plus benefits of $164,820 (or $79/hour). The Commission
believes that industry is similarly situated in terms of staff costs
and skill sets.
\199\ Not required to file.
FERC-556, as Modified by the NOPR in Docket Nos. RM19-15-000 and AD16-16-000
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Annual number of Average burden
Facility type Filing type Number of responses per Total number of hours & cost per Total annual burden hours & Cost per
respondents respondent responses response total annual cost respondent ($)
.................. (1)................ (2)................ (1) * (2) = (3).... (4)................ (3) * (4) = (5).................. (5) / (1)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Cogeneration Facility > 1 MW.... Self-certification 10................. 1.25............... 12.5............... 8 hrs.; $632....... 100 hrs.; $7,900................. $790.
Cogeneration Facility > 1 MW.... Application for 1.................. 1.25............... 1.25............... 55 hrs.; $4,345.... 68.75 hrs.; $5,431.25............ $5,431.25.
FERC
certification.
Small Power Production Facility Self-certification 20................. 1.25............... 25................. 8 hrs.; $632....... 200 hrs.; $15,800................ $790.
> 1 MW, > 1 Mile, < 10 Miles
from Affiliated Facility.
Small Power Production Facility Application for 1.................. 1.25............... 1.25............... 55 hrs.; $4,345.... 68.75 hrs.; $5,431.25............ $5,431.25.
> 1 MW, > 1 Mile, < 10 Miles FERC
from Affiliated Facility. certification.
Cogeneration and Small Power Self-certification 312................ 1.25............... 390................ 4 hrs.; $316....... 1,560 hrs.; $123,240............. $395.
Production Facility <= 1 MW
(Self-Certification) \199\.
Small Power Production Facility Self-certification no change.......... no change.......... no change.......... no change.......... no change........................ no change.
> 1 MW, <= 1 Mile from
Affiliated Facility.
Small Power Production Facility Application for 1.................. 1.25............... 1.25............... 55 hrs.; $4,345.... 68.75 hrs.; $5,431.25............ $5,431.25.
> 1 MW, <= 1 Mile from FERC
Affiliated Facility. certification.
Small Power Production Facility Self-certification 1,980.............. 1.25............... 2,475.............. 8 hrs.; $632....... 19,800 hrs.; $1,564,200.......... $790.
> 1 MW, >= 10 Miles from
Affiliated Facility.
Small Power Production Facility Application for no change.......... no change.......... no change.......... no change.......... no change........................ no change.
> 1 MW, >= 10 Miles from FERC
Affiliated Facility. certification.
-----------------------------------
Total....................... .................. ................... ................... ................... ................... 22,235 hrs.; $1,727,433.75....... ...................
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[[Page 53268]]
Title: FERC-556, Certification of Qualifying Facility (QF) Status
for a Small Power Production or Cogeneration Facility.
Action: Revisions to existing collection FERC-556.
OMB Control No.: 1902-0075.
Respondents: Facilities that are self-certifying their status as a
cogenerator or small power producer or that are submitting an
application for Commission certification of their status as a
cogenerator or small power producer; and electric utilities, state
regulatory authorities, or other entities submitting comments on, or
protests to, the self-certification or application for Commission
certification.
Frequency of Information: Ongoing.
Necessity of Information: The Commission proposes the changes in
this NOPR in order to revise its implementation of PURPA in light of
changes in the electric industry since the enactment of PURPA in 1978.
Internal Review: The Commission has reviewed the proposed changes
and has determined that such changes are necessary. These requirements
conform to the Commission's need for efficient information collection,
communication, and management within the energy industry.
Interested persons may obtain information on the reporting
requirements by contacting the Federal Energy Regulatory Commission,
888 First Street NE, Washington, DC 20426 [Attention: Ellen Brown,
Office of the Executive Director], by email to [email protected],
by phone (202) 502-8663, or by fax (202) 273-0873.
Comments concerning the collection of information and the
associated burden estimate may also be sent to: Office of Information
and Regulatory Affairs, Office of Management and Budget, 725 17th
Street NW, Washington, DC 20503 [Attention: Desk Officer for the
Federal Energy Regulatory Commission]. Due to security concerns,
comments should be sent electronically to the following email address:
[email protected]. Comments submitted to OMB should refer to
FERC-556 and OMB Control No. 1902-0075.
IV. Environmental Analysis
154. The Commission is required to prepare an Environmental
Assessment (EA) or an Environmental Impact Statement (EIS) for any
action that may have a significant adverse effect on the quality of the
human environment.\200\ Whether and how the revisions proposed here,
however, would affect QF development and the environment is
speculative.
---------------------------------------------------------------------------
\200\ Regulations Implementing the National Environmental Policy
Act, Order No. 486, FERC Stats. & Regs. ] 30,783 (1987) (cross-
referenced at 41 FERC ] 61,284).
---------------------------------------------------------------------------
155. The proposed changes to the PURPA Regulations do not authorize
or fund particular QFs, nor do they license QFs or issue permits for
QFs to operate. They do not authorize or prohibit a generator's use of
any particular technologies or fuels, nor do they mandate or limit
where QFs should or should not be built. They do not exempt QFs from
any Federal, state or local environmental, siting, or other similar
laws or regulatory requirements. And while the Commission establishes
factors that are to be taken into account by the states in setting QF
rates, it is the states and not the Commission that set QF rates. It is
impossible to know what actions the states may take in response to the
revisions proposed here, and how any such actions would, on balance,
impact QF development and the environment going forward--especially
given that QFs include not only renewable resources such as solar and
wind resources but also renewable resources that, per Congress'
directive, depend on waste (such as waste coal) as an energy input
\201\ and cogeneration that often depends on fossil fuels as an energy
input.\202\ Moreover, as explained above, PURPA requires that the
Commission must prescribe, and from time to time thereafter revise,
such rules as the Commission determines necessary to encourage
QFs,\203\ and the Commission's rules as revised as proposed here would
continue to encourage QFs. Given these facts any environmental impacts
analysis of the revisions proposed here would be speculative and not
meaningfully inform the Commission or the public of the revisions'
impact on QF development or, correspondingly, of any associated
potential impacts on the environment; there are, in short, no
reasonably foreseeable environmental impacts for the Commission to
consider.\204\ Therefore, the Commission will not prepare an
environmental document.
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\201\ 16 U.S.C. 796(17); 18 CFR 292.202(b), 292.204(b).
\202\ 16 U.S.C. 796(18); 18 CFR 292.205.
\203\ 16 U.S.C. 824a-3(a).
\204\ While courts have held that NEPA requires ``reasonable
forecasting,'' an agency is not required ``to engage in speculative
analysis'' or ``to do the impractical, if not enough information is
available to permit meaningful consideration.'' N. Plains Res.
Council v. Surface Transp. Board, 668 F.3d 1067, 1078 (9th Cir.
2011).
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V. Regulatory Flexibility Act Certification
156. The Regulatory Flexibility Act of 1980 (RFA) \205\ generally
requires a description and analysis of proposed rules that will have
significant economic impact on a substantial number of small entities.
In lieu of preparing a regulatory flexibility analysis, an agency may
certify that a proposed rule will not have a significant economic
impact on a substantial number of small entities.\206\
---------------------------------------------------------------------------
\205\ 5 U.S.C. 601-12.
\206\ 5 U.S.C. 605(b).
---------------------------------------------------------------------------
157. The Small Business Administration's (SBA) Office of Size
Standards develops the numerical definition of a small business.\207\
The SBA size standard for electric utilities is based on the number of
employees, including affiliates.\208\ Under SBA's current size
standards, the threshold for a small entity (including its affiliates)
is 250 employees for cogeneration and small power production applicants
in the following NAICS \209\ categories:
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\207\ 13 CFR 121.101.
\208\ SBA Final Rule on ``Small Business Size Standards:
Utilities,'' 78 FR 77,343 (Dec. 23, 2013).
\209\ The North American Industry Classification System (NAICS)
is an industry classification system that Federal statistical
agencies use to categorize businesses for the purpose of collecting,
analyzing, and publishing statistical data related to the U.S.
economy. United States Census Bureau, North American Industry
Classification System, https://www.census.gov/eos/www/naics/
(accessed April 11, 2018).
---------------------------------------------------------------------------
NAICS code 221114 for Solar Electric Power Generation
NAICS code 221115 for Wind Electric Power Generation
NAICS code 221116 for Geothermal Electric Power Generation
NAICS code 221117 for Biomass Electric Power Generation
NAICS code 221118 for Other Electric Power Generation
The threshold for a small entity (including its affiliates) is 500
employees for NAICS code 221111 for Hydroelectric Power Generation.
This proposed rule directly affects QFs, the majority of which the
Commission estimates are small businesses. But, as reflected in the
burden and cost estimates provided above, the Commission does not
anticipate that any additional reporting burden or cost imposed on QFs,
regardless of their status as a small or large business, would be
significant.\210\ The proposed revisions may result in additional
information being submitted
[[Page 53269]]
by some small power production QF applicants and self-certifiers (those
with affiliated small power production facilities using the same fuel
source located over one and less than ten miles away, and with a
combined total capacity greater than 80 MW). The Commission estimates
that less than ten percent of QF applications and self-certifications
meet these criteria.
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\210\ The average cost per response is estimated to be $594.39
(or $1,727,433.75/2,906.25 responses).
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158. Accordingly, pursuant to section 605(b) of the RFA, the
Commission certifies that this proposed rule will not have a
significant economic impact on a substantial number of small entities.
VI. Comment Procedures
159. The Commission invites interested persons to submit comments
on the matters and issues proposed in this notice to be adopted,
including any related matters or alternative proposals that commenters
may wish to discuss. Comments are due December 3, 2019. Comments must
refer to Docket No. RM19-15-000 and AD16-16-000, and must include the
commenter's name, the organization they represent, if applicable, and
their address in their comments.
160. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's website at https://www.ferc.gov. The Commission accepts most standard word processing
formats. Documents created electronically using word processing
software should be filed in native applications or print-to-PDF format
and not in a scanned format. Commenters filing electronically do not
need to make a paper filing.
161. Commenters that are not able to file comments electronically
must send an original of their comments to: Federal Energy Regulatory
Commission, Secretary of the Commission, 888 First Street NE,
Washington, DC 20426.
162. All comments will be placed in the Commission's public files
and may be viewed, printed, or downloaded remotely as described in the
Document Availability section below. Commenters on this proposal are
not required to serve copies of their comments on other commenters.
VII. Document Availability
163. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
internet through the Commission's Home Page (https://www.ferc.gov) and
in the Commission's Public Reference Room during normal business hours
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE, Room 2A,
Washington, DC 20426.
164. From the Commission's Home Page on the internet, this
information is available on eLibrary. The full text of this document is
available on eLibrary in PDF and Microsoft Word format for viewing,
printing, and/or downloading. To access this document in eLibrary, type
the docket number excluding the last three digits of this document in
the docket number field.
165. User assistance is available for eLibrary and the Commission's
website during normal business hours from the Commission's Online
Support at 202-502-6652 (toll free at 1-866-208-3676) or email at
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at
[email protected].
List of Subjects in 18 CFR Part 292
Electric power; Electric power plants; Electric utilities.
By direction of the Commission. Commissioner Glick is dissent in
part with a separate statement attached.
Issued: September 19, 2019.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
In consideration of the foregoing, the Commission proposes to amend
Parts 292 and 375, Chapter I, Title 18, Code of Federal Regulations, as
follows.
PART 292--REGULATIONS UNDER SECTIONS 201 AND 210 OF THE PUBLIC
UTILITY REGULATORY POLICIES ACT OF 1978 WITH REGARD TO SMALL POWER
PRODUCTION AND COGENERATION
0
1. The authority citation for part 292 continues to read as follows:
Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352.
0
2. Amend Sec. 292.101 by adding paragraphs (b)(12) through (16) to
read as follows:
Sec. 292.101 Definitions.
* * * * *
(b) * * *
(12) Locational marginal price means the price for energy at a
particular location as determined in a market defined in Sec.
292.309(e), (f), or (g).
(13) Competitive Price means a Market Hub Price or a Combined Cycle
Price.
(14) Market Hub Price means a price for as-delivered energy
determined pursuant to Sec. 292.304(b)(7)(i).
(15) Combined Cycle Price means a price for as-delivered energy
determined pursuant to Sec. 292.304(b)(7)(ii).
(16) Competitive Solicitation Price means a price for energy and/or
capacity determined pursuant to Sec. 292.304(b)(8).
0
3. Amend Sec. 292.202 by adding paragraph (t) to read as follows:
Sec. 292.202 Definitions.
* * * * *
(t) Electrical generating equipment means all boilers, heat
recovery steam generators, prime movers (any mechanical equipment
driving an electric generator), electrical generators, photovoltaic
solar panels and/or inverters, fuel cell equipment and/or other primary
power generation equipment used in the facility, excluding equipment
for gathering energy to be used in the facility.
0
4. Amend Sec. 292.204 by revising paragraph (a) to read as follows:
Sec. 292.204 Criteria for qualifying small power production
facilities.
(a) Size of the facility--(1) Maximum size. Except as provided in
paragraph (a)(4) of this section, the power production capacity of a
facility for which qualification is sought, together with the power
production capacity of any other small power production facilities that
use the same energy resource, are owned by the same person(s) or its
affiliates, and are located at the same site, may not exceed 80
megawatts.
(2) Method of calculation. (i)(A) For purposes of this paragraph
(a)(2)(i)(A), there is an irrebuttable presumption that facilities
located one mile or less from the facility for which qualification is
sought are located at the same site as the facility for which
qualification is sought.
(B) For purposes of this paragraph (a)(2)(i)(B), for facilities for
which qualification is filed on or after [DATE 60 DAYS AFTER DATE OF
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], there is an
irrebuttable presumption that facilities located ten miles or more from
the facility for which qualification is sought are facilities located
at separate sites from the facility for which qualification is sought.
(C) For purposes of this paragraph (a)(2)(i)(C), for facilities for
which qualification is filed on or after [DATE 60 DAYS AFTER DATE OF
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], there is a
rebuttable presumption that facilities located over one and less than
ten miles from the facility for which qualification is sought are
facilities located at separate sites from the facility for which
qualification is sought.
[[Page 53270]]
(D) For hydroelectric facilities, facilities are considered to be
located at the same site as the facility for which qualification is
sought if they are located within one mile of the facility for which
qualification is sought and use water from the same impoundment for
power generation.
(ii) For purposes of making the determination in clause (i), the
distance between facilities shall be measured from the electrical
generating equipment of the facility for which qualification is sought
and the nearest electrical generating equipment of the other facility
using the same energy resource and owned by the same person(s) or its
affiliates.
(3) Rebuttal. (i) Filing a Protest. Any person who opposes either a
self-certification submitted pursuant to Sec. 292.207(a) or a
Commission certification filed pursuant to Sec. 292.207(b) may submit
a protest attempting to rebut the presumption that facilities located
over one mile and less than ten miles from the facility for which
qualification is sought are separate facilities at separate sites from
the facility for which qualification is sought.
(ii) Limitations on rebuttal. Once the Commission has affirmatively
certified an applicant's QF status either in response to a protest
opposing a self-certification or in a Commission certification
proceeding, any later challenge to a QF's certification asserting that
facilities more than one mile and less than ten miles apart are located
at the same site must demonstrate a material change in the relevant
circumstances that calls into question the continued validity of the
certification.
(4) Waiver. The Commission may modify the application of paragraph
(a)(2) of this section, for good cause.
(5) Exception. Facilities meeting the criteria in section 3(17)(E)
of the Federal Power Act (16 U.S.C. 796(17)(E)) have no maximum size,
and the power production capacity of such facilities shall be excluded
from consideration when determining the maximum size of other small
power production facilities less than ten miles of such facilities.
* * * * *
0
5. Amend Sec. 292.207 by revising paragraphs (a) and (b) to read as
follows:
Sec. 292.207 Procedures for obtaining qualifying status.
(a) Self-certification. (1) Form No. 556. The qualifying facility
status of an existing or a proposed facility that meets the
requirements of Sec. 292.203 may be self-certified by the owner or
operator of the facility or its representative by properly completing a
Form No. 556 and filing that form with the Commission, pursuant to
Sec. 131.80 of this chapter, and complying with paragraph (c) of this
section.
(2) Factors. For small power production facilities pursuant to
Sec. 292.204, the owner or operator of the facility or its
representative may, when completing the Form No. 556, provide
information asserting factors showing that the facility for which
qualification is sought is at a separate site from other facilities
using the same energy resource and owned by the same person(s) or its
affiliates.
(3) Protests and Interventions. Any protest to and any intervention
in a self-certification must be filed in accordance with Sec. Sec.
385.211 and 385.214 of this chapter, on or before 30 days from the date
the self-certification is filed. Any protest must provide evidence to
substantiate the claims in the protest.
(4) Commission action. Self-certification is effective upon filing.
If no protests are timely filed, no further action by the Commission is
required for a self-certification to be effective. If protests are
timely filed, a self-certification will remain effective until the
Commission issues an order revoking QF certification. The Commission
will act on the protest within 90 days from the date the protest is
filed; provided that, if the Commission requests more information from
the protester, the entity seeking QF certification, or both, the time
for the Commission to act will be extended to 60 days from the filing
of a complete answer to the information request. In addition to any
extension resulting from a request for information, the Commission also
may toll the 90-day period for one additional 60-day period if so
required to rule on a protest. Authority to toll the 90-day period for
this purpose is delegated to the Secretary or the Secretary's designee.
(b) Optional procedure--Commission certification. (1) Application
for Commission certification. In lieu of the self-certification
procedures in paragraph (a) of this section, an owner or operator of an
existing or a proposed facility, or its representative, may file with
the Commission an application for Commission certification that the
facility is a qualifying facility. The application must be accompanied
by the fee prescribed by part 381 of this chapter, and the applicant
for Commission certification must comply with paragraph (c) of this
section.
(2) General contents of application. The application must include a
properly completed Form No. 556 pursuant to Sec. 131.80 of this
chapter. For small power production facilities pursuant to Sec.
292.204, the owner or operator of the facility or its representative
may, when completing the Form No. 556, provide information asserting
factors showing that the facility for which qualification is sought is
at a separate site from other facilities using the same energy resource
and owned by the same person(s) or its affiliates.
* * * * *
0
6. Section 292.303 is revised to read:
Sec. 292.303 Electric utility obligations under this subpart.
(a) Obligation to purchase from qualifying facilities. Subject to
paragraph (b) of this section, each electric utility shall purchase, in
accordance with Sec. 292.304, unless exempted by Sec. 292.309 and
Sec. 292.310, any energy and capacity which is made available from a
qualifying facility:
(1) Directly to the electric utility; or
(2) Indirectly to the electric utility in accordance with paragraph
(e) of this section.
(b) Reduction in purchase obligation. The obligation of an electric
utility to purchase from a qualifying facility may be reduced to the
extent that a purchasing electric utility's supply obligation has been
reduced by a state's retail choice program.
(c) Obligation to sell to qualifying facilities. Each electric
utility shall sell to any qualifying facility, in accordance with Sec.
292.305, unless exempted by Sec. 292.312, energy and capacity
requested by the qualifying facility.
(d) Obligation to interconnect.
(1) Subject to paragraph (d)(2) of this section, any electric
utility shall make such interconnection with any qualifying facility as
may be necessary to accomplish purchases or sales under this subpart.
The obligation to pay for any interconnection costs shall be determined
in accordance with Sec. 292.306.
(2) No electric utility is required to interconnect with any
qualifying facility if, solely by reason of purchases or sales over the
interconnection, the electric utility would become subject to
regulation as a public utility under part II of the Federal Power Act.
(e) Transmission to other electric utilities. If a qualifying
facility agrees, an electric utility which would otherwise be obligated
to purchase energy or capacity from such qualifying facility may
transmit the energy or capacity to any other electric utility. Any
electric utility to which such energy or capacity is transmitted shall
purchase such energy or capacity under this subpart as if the
qualifying facility were supplying energy or capacity directly to such
[[Page 53271]]
electric utility. The rate for purchase by the electric utility to
which such energy is transmitted shall be adjusted up or down to
reflect line losses pursuant to Sec. 292.304(e)(4) and shall not
include any charges for transmission.
(f) Parallel operation. Each electric utility shall offer to
operate in parallel with a qualifying facility, provided that the
qualifying facility complies with any applicable standards established
in accordance with Sec. 292.308.
0
7. Amend Sec. 292.304 by
0
a. Adding paragraphs (b)(6), (b)(7), (b)(8); and
0
b. Revising paragraphs (d), and (e).
The addition and revisions read as follows:
Sec. 292.304 Rates for purchases.
* * * * *
(b) * * *
(6) Locational Marginal Price. A state regulatory authority or
nonregulated electric utility may use a locational marginal price as a
rate for as-available qualifying facility energy sales to purchasing
utilities located in a market operated defined in Sec. 292.309(e),
(f), or (g).
(7) Competitive Price. A state regulatory authority or nonregulated
electric utility may use a Competitive Price as a rate for as-available
qualifying facility energy sales to purchasing electric utilities
located outside a market defined in Sec. 292.309(e), (f), or (g). A
Competitive Price may be either a Market Hub Price or a Combined Cycle
Price, determined as follows:
(i) A Market Hub Price is a price established at a liquid market
hub to which a state regulatory authority or nonregulated electric
utility determines the purchasing electric utility has reasonable
access, based on its evaluation of the relevant factors, including but
not limited to the following:
(A) Whether the hub is sufficiently liquid that prices at the hub
represent a competitive price;
(B) Whether prices developed at the hub are sufficiently
transparent;
(C) Whether the purchasing electric utility has the ability to
deliver power from such hub to its load, even if its load is not
directly connected to the hub; and
(D) Whether the hub represents an appropriate market to derive an
energy price for the purchasing electric utility's purchases from the
relevant QFs given the electric utility's physical proximity to the hub
or other factors.
(ii) A Combined Cycle Price is a price determined pursuant to a
formula established by a state regulatory authority or nonregulated
electric utility using published natural gas price indices and a proxy
heat rate for an efficient natural gas combined-cycle generating
facility. Before establishing such a formula rate, a state regulatory
authority or nonregulated electric utility must determine that the
resulting Combined Cycle Price represents an appropriate approximation
of the purchasing electric utility's avoided cost, based on its
evaluation of the relevant factors, including but not limited to the
following:
(A) 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;
(B) Whether natural gas priced pursuant to particular proposed
natural gas price indices would be available in the relevant market;
(C) 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
(D) Whether the proxy heat rate used in the formula should be
updated regularly to reflect improvements in generation technology.
(8) Competitive Solicitation Price. A state regulatory authority or
nonregulated electric utility may use a price determined pursuant to a
competitive solicitation process to establish qualifying facility
energy and/or capacity rates for sales to purchasing electric
utilities, provided that such competitive solicitation process is
conducted pursuant to procedures ensuring the solicitation is conducted
in a transparent and non-discriminatory manner including, but not
limited to, the following:
(i) The solicitation process is an open and transparent process;
(ii) 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;
(iii) Solicitations are conducted at regular intervals;
(iv) Solicitations are subject to oversight by an independent
administrator; and
(v) Solicitations are certified as fulfilling the above criteria by
the relevant state regulatory authority or nonregulated electric
utility.
* * * * *
(d) Purchases ``as available'' or pursuant to a legally enforceable
obligation. (1) Each qualifying facility shall have the option either:
(i) To provide energy as the qualifying facility determines such
energy to be available for such purchases, in which case the rates for
such purchases shall be based on the purchasing electric utility's
avoided costs calculated at the time of delivery; or
(ii) To provide energy or capacity pursuant to a legally
enforceable obligation for the delivery of energy or capacity over a
specified term, in which case the rates for such purchases shall,
except as provided in subsection (d)(2) below, be based on either:
(A) The avoided costs calculated at the time of delivery; or
(B) The avoided costs calculated at the time the obligation is
incurred.
(iii) The rate for delivery of energy calculated at the time the
obligation is incurred may be based on estimates of the present value
of the stream of revenue flows of future locational marginal prices, or
Competitive Prices during the anticipated period of delivery.
(2) Notwithstanding paragraph (d)(1)(ii)(B) of this section, a
state regulatory authority or nonregulated electric utility may require
that rates for purchases of energy from a qualifying facility pursuant
to a legally enforceable obligation to vary through the life of the
obligation, and to be set at the as-available energy price applicable
to the purchasing electric utility determined at the time of delivery.
(3) Obtaining a legally enforceable obligation. A qualifying
facility must demonstrate commercial viability and financial commitment
to construct its facility pursuant to criteria determined by the state
regulatory authority or nonregulated electric utility as a prerequisite
to a qualifying facility obtaining a legally enforceable obligation.
Such criteria must be objective and reasonable.
(e) Factors affecting rates for purchases. (1) A state regulatory
authority or nonregulated electric utility may establish rates for
purchases of energy from a qualifying facility based on a purchasing
electric utility's locational marginal price calculated by the
applicable market defined in Sec. 292.309(e), (f), or (g), or the
purchasing electric utility's applicable Competitive Price.
Alternatively, a state regulatory authority or nonregulated electric
utility may establish rates for purchases of energy and/or capacity
from a qualifying facility based on a Competitive Solicitation Price.
To the extent that capacity rates are not set pursuant to this section,
capacity rates shall be set pursuant to subsection (2).
(2) To the extent that a state regulatory authority or nonregulated
electric utility does not to set energy and/or capacity rates pursuant
to
[[Page 53272]]
paragraph (e)(1) of this section, the following factors shall, to the
extent practicable, be taken into account in determining rates for
purchases from a qualifying facility:
(i) The data provided pursuant to Sec. 292.302(b), (c), or (d),
including State review of any such data;
(ii) The availability of capacity or energy from a qualifying
facility during the system daily and seasonal peak periods, including:
(A) The ability of the electric utility to dispatch the qualifying
facility;
(B) The expected or demonstrated reliability of the qualifying
facility;
(C) The terms of any contract or other legally enforceable
obligation, including the duration of the obligation, termination
notice requirement and sanctions for non-compliance;
(D) The extent to which scheduled outages of the qualifying
facility can be usefully coordinated with scheduled outages of the
electric utility's facilities;
(E) The usefulness of energy and capacity supplied from a
qualifying facility during system emergencies, including its ability to
separate its load from its generation;
(F) The individual and aggregate value of energy and capacity from
qualifying facilities on the electric utility's system; and
(G) The smaller capacity increments and the shorter lead times
available with additions of capacity from qualifying facilities; and
(iii) The relationship of the availability of energy or capacity
from the qualifying facility as derived in paragraph (e)(2)(ii) of this
section, to the ability of the electric utility to avoid costs,
including the deferral of capacity additions and the reduction of
fossil fuel use; and
(iv) The costs or savings resulting from variations in line losses
from those that would have existed in the absence of purchases from a
qualifying facility, if the purchasing electric utility generated an
equivalent amount of energy itself or purchased an equivalent amount of
electric energy or capacity.
0
8. Amend Sec. 292.309 by revising paragraphs (d), (e), and (f) to read
as follows:
Sec. 292.309 Termination of obligation to purchase from qualifying
facilities.
* * * * *
(d)(1) For purposes of Sec. 292.309(a)(1), (2), and (3), there is
a rebuttable presumption that a qualifying cogeneration facility with a
capacity at or below 20 megawatts does not have nondiscriminatory
access to the market.
(2) For purposes of Sec. 292.309(a)(1), (2), and (3), there is a
rebuttable presumption that a qualifying small power production
facility with a capacity at or below 1 megawatt does not have
nondiscriminatory access to the market.
(3) For purposes of implementing paragraphs (d)(1) and (d)(2) of
this section, the Commission will not be bound by the standards set
forth in Sec. 292.204(a)(2).
(e) Midcontinent Independent System Operator, Inc. (MISO), PJM
Interconnection, L.L.C. (PJM), ISO New England Inc. (ISO-NE), and New
York Independent System Operator, Inc. (NYISO) qualify as markets
described in Sec. 292.309(a)(1)(i) and (ii), and there is a rebuttable
presumption that small power production facilities with a capacity
greater than one megawatt and cogeneration facilities with a capacity
greater than 20 megawatts have nondiscriminatory access to those
markets through Commission-approved open access transmission tariffs
and interconnection rules, and that electric utilities that are members
of such regional transmission organizations or independent system
operators (RTO/ISOs) should be relieved of the obligation to purchase
electric energy from the qualifying facilities. A qualifying facility
may seek to rebut this presumption by demonstrating, inter alia, that:
(1) The qualifying facility has certain operational characteristics
that effectively prevent the qualifying facility's participation in a
market; or
(2) The qualifying facility lacks access to markets due to
transmission constraints. The qualifying facility may show that it is
located in an area where persistent transmission constraints in effect
cause the qualifying facility not to have access to markets outside a
persistently congested area to sell the qualifying facility output or
capacity.
(f) The Electric Reliability Council of Texas (ERCOT) qualifies as
a market described in Sec. 292.309(a)(3), and there is a rebuttable
presumption that small power production facilities with a capacity
greater than one megawatt and cogeneration facilities with a capacity
greater than 20 megawatts have nondiscriminatory access to that market
through Public Utility Commission of Texas (PUCT) approved open access
protocols, and that electric utilities that operate within ERCOT should
be relieved of the obligation to purchase electric energy from the
qualifying facilities. A qualifying facility may seek to rebut this
presumption by demonstrating, inter alia, that:
(1) The qualifying facility has certain operational characteristics
that effectively prevent the qualifying facility's participation in a
market; or
(2) The qualifying facility lacks access to markets due to
transmission constraints. The qualifying facility may show that it is
located in an area where persistent transmission constraints in effect
cause the qualifying facility not to have access to markets outside a
persistently congested area to sell the qualifying facility output or
capacity.
* * * * *
PART 375--THE COMMISSION
0
1. The authority citation for part 375 continues to read as follows:
Authority: 5 U.S.C. 551-557; 15 U.S.C. 717-717w, 3301-3432; 16
U.S.C. 791-825r, 2601-2645; 42 U.S.C. 7101-7352.
0
2. Section 375.302(v) is revised to read:
Sec. 375.302 Delegations to the Secretary.
* * * * *
(v) Toll the time for action on requests for rehearing, and toll
the time for action on protested self-certifications and self-
recertifications of qualifying facilities.
The following will not appear in the Code of Federal Regulations:
Federal Energy Regulatory Commission
------------------------------------------------------------------------
Docket Nos.
------------------------------------------------------------------------
Qualifying Facility Rates and Requirements............ RM19-15-000
Implementation Issues Under the Public Utility AD16-16-000
Regulatory Policies Act of 1978......................
------------------------------------------------------------------------
(Issued September 19, 2019)
GLICK, Commissioner, dissenting in part:
1. I dissent in part from today's notice of proposed rulemaking
(NOPR) because it would effectively gut the Public Utility
Regulatory Policies Act (PURPA).\1\ Our basic
[[Page 53273]]
responsibilities under PURPA are three-fold: (1) To encourage the
development of qualifying facilities (QFs); (2) to prevent
discrimination against QFs by incumbent utilities; and (3) to ensure
that the resulting rates paid by electricity customers remain just
and reasonable and in the public interest.\2\ As discussed further
below, it is not clear from the record or the discussion in today's
NOPR that many of the proposed changes will satisfy those
requirements. Although the record developed in response to this NOPR
will give us a basis to address those issues, I am deeply concerned
that the Commission has failed so far to show that certain aspects
of its proposal satisfy our basic responsibilities under the law.
---------------------------------------------------------------------------
\1\ Public Law 95-617, 92 Stat. 3117 (1978).
\2\ See 16 U.S.C. 824a-3 (2018).
---------------------------------------------------------------------------
2. It appears that the Commission no longer believes that PURPA
is necessary. I disagree. I believe that the goals of PURPA--
including the need to expand competition and reduce our reliance on
fossil fuels \3\--remain as relevant now as ever. But our apparent
disagreement is beside the point. Whether PURPA's goals remain
relevant is a decision for Congress, not an administrative agency.
The Commission should not be seizing the reins from Congress in
order to isolate an important debate about national energy policy
within an independent regulatory agency.
---------------------------------------------------------------------------
\3\ See Am. Paper Inst., Inc. v. Am. Elec. Power Serv. Corp.,
461 U.S. 402, 405 (1983) (describing Congress's intent in enacting
PURPA).
---------------------------------------------------------------------------
I. PURPA's Continuing Relevance Is an Issue for Congress To Decide
3. A fundamental reform to a major energy statute, particularly
one that Congress has been debated for decades, ought to come from
Congress, not an independent regulatory agency. For more than forty
years, the Commission has rather consistently interpreted Congress's
directives in PURPA. During that time, Congress has repeatedly
considered legislation to amend the statute, in some cases to expand
its reach and in others to pare it back. Indeed, almost from the
moment PURPA was passed, Congress began to hear many of the
arguments being used today to justify scaling the law back. Yet
Congress only on one occasion--in 2005--significantly amended the
statute. After a lengthy debate, which included proposals to repeal
PURPA, Congress adopted the Energy Policy Act of 2005 (EPAct 2005),
which left in place PURPA's basic framework but added a series of
provisions that relieved utilities of their requirements in regions
of the country with robust wholesale energy markets.\4\ Over the
course of the last fourteen years, Congress has continued to
consider a wide range of proposals to reform PURPA, some of which
would have enacted into law many of the proposals advanced in this
NOPR. But Congress did not enact any of these reforms.
---------------------------------------------------------------------------
\4\ Public Law 109-58, 119 Stat. 594 (2005).
---------------------------------------------------------------------------
4. Today's NOPR flips that dynamic on its head. It removes an
important debate from the halls of Congress and isolates it within
the Commission. That may help to achieve certain stakeholders'
objectives and, no doubt, some Members of Congress that have
unsuccessfully sought to further reform PURPA will applaud this
outcome. But what should concern all of us is that resolving these
sorts of questions by regulatory edict rather than congressional
legislation is neither a durable nor desirable approach for
developing energy policy.
5. With those concerns in mind, the Commission's explanation of
the purported need for reform rings hollow. The majority recites
statistics to show that the energy landscape has changed over the
last 40 years. And there is no doubt that it has. Renewables are
growing rapidly and, in some parts of the country, are being
financed in large numbers without PURPA's protections.\5\ Natural
gas production has increased in similarly dramatic fashion and
recently surpassed coal as the country's principal source of fuel
for generating electricity.\6\ But reams of statistics do not make a
law irrelevant. The majority and I might disagree about PURPA and
the importance of its objectives, but that is not a dispute that we,
as Commissioners, should resolve. A policy debate about the
continuing relevance of PURPA--which, make no mistake, is what this
NOPR is really about--is an issue for Congress to resolve.
---------------------------------------------------------------------------
\5\ See Qualifying Facility Rates and Requirements;
Implementation Issues Under the Public Utility Regulatory Policies
Act of 1978, 168 FERC ] 61,184, at PP 19-21 (2019) (NOPR).
\6\ U.S. Energy Info. Admin., What is U.S. electricity
generation by energy source?, https://www.eia.gov/tools/faqs/faq.php?id=427&t=3 (last visited Sept. 19, 2019).
---------------------------------------------------------------------------
II. Certain Proposed Revisions Are Inconsistent With Our Statutory
Obligations
6. In addition to my general concerns about the direction and
intent of today's NOPR, I have a number of more discrete objections
regarding aspects of the Commission's proposal. I raise these
concerns in particular because I believe that neither the record
established to date nor the rationale articulated in today's NOPR
suggest that these changes are consistent with our obligations under
PURPA. Accordingly, I am especially interested in reviewing the
record developed in response to these elements of the proposed rule
and I encourage parties to address these issues in detail in their
comments.
A. Avoided Cost
7. No issue has consumed as much attention in the debates over
PURPA as how to set avoided cost. Following PURPA's enactment in
1978, the Commission introduced a framework for setting ``avoided
cost'' that allows each individual state to consider a wide range of
factors in identifying the ``full'' costs that are avoided when a
utility purchases energy and capacity from a QF.\7\ The basic idea
is that the avoided cost figure should reflect the full cost that
the utility would incur but for the purchase of the QF output of
energy or capacity, with each individual state enjoying considerable
flexibility in implementing that concept.\8\ The Commission's
regulations also provide states the flexibility to accommodate
Congress's intent that the rates paid to QFs ``look beyond'' just
``instantaneous cost savings'' in order to consider savings over a
longer time horizon.\9\
---------------------------------------------------------------------------
\7\ See 18 CFR 292.304(e) (2019).
\8\ 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, at 30,865 (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).
\9\ H.R. Rep. 95-1750, at 98-99 (1978) (Conf. Rep.) (``In
interpreting the incremental cost of alternative energy, the
Conferees expect that the Commission and the states may look beyond
the costs of alternative sources which are instantaneously available
to the utility. Rather the Commission and states should look to the
reliability of that power and the cost savings to the utility which
may result at some later date by reasons of supply to the utility at
that time of power from the cogenerate or small power producers.'').
---------------------------------------------------------------------------
8. The NOPR proposes two fundamental changes to how avoided cost
is calculated and applied to QFs. First, it proposes to eliminate
the requirement that a utility must afford a QF the option to enter
a contract at an avoided cost energy rate that is fixed or known for
the duration of the contract.\10\ As things stand now, a QF
generally has two options for selling its output to a utility. Under
the first option, the QF can sell its energy on an as-available
basis and receive an avoided cost rate calculated at the time of
delivery. This is generally known as the as-available option. Under
the second option, a QF can enter into a fixed duration contract at
an avoided cost rate that is fixed either at the time the QF
establishes a legally enforceable obligation or at the time of
delivery. This is generally known as the contract option. The
ability to choose between both types sale options has played an
important role in fostering the development of a variety of QFs. For
example, the as-available option provides a way for QFs whose
principal business is not generating electricity, such as industrial
cogeneration facilities, to monetize their excess electricity
generation. The contract option, by contrast, provides QFs who are
principally in the business of generating electricity, such as small
renewable electricity generators, a relatively stable option that
will allow them to secure financing. Together, the presence of these
two options have allowed the Commission to satisfy its statutory
mandate to encourage the development of QFs and ensure that the
rates they receive are non-discriminatory.
---------------------------------------------------------------------------
\10\ The NOPR proposes to eliminate the contract option for the
energy component, keeping the long-term contract requirement in
place for capacity. That sounds more reasonable than it will often
be in practice. The NOPR later clarifies that the fixed capacity
value may be zero if the state determines that the electric utility
does not have a need for additional capacity resources. See NOPR,
168 FERC ] 61,184 at P 67. That would also mean that, in some
instances, there would be no fixed element in an avoided cost
contract, which would seem inconsistent with the Commission's
rationale justifying variable energy price contracts. See id. P 70.
---------------------------------------------------------------------------
9. I am concerned that the Commission's proposal to allow
utilities to eliminate the
[[Page 53274]]
fixed-price contract option will make it more difficult--or in some
cases impossible--for QFs to obtain financing. The option to enter a
contract with a fixed or known price has played in essential role in
encouraging QF development.\11\ In addition, those contracts have
played an important role in ensuring that QFs receive non-
discriminatory rates, especially in areas of the country with
vertically integrated utilities that are guaranteed to recover the
costs of their prudently incurred investments through retail
rates.\12\ Neither the record nor the rationale in this NOPR
addresses these concerns in a manner that is even remotely
convincing.
---------------------------------------------------------------------------
\11\ See, e.g., June 29, 2016 Technical Conf. Tr. at 26-27
(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.'').
\12\ See Statement of Travis Kavulla, Docket No. AD16-16-000, at
2 (June 29, 2016) (``Whether compensation for a QF is a matter of
market clearing prices or of administrative decision-making is
largely a reflection of how larger or utility-owned generation is
compensated.'').
---------------------------------------------------------------------------
10. Second, I am concerned about the implications of the
Commission's proposal to determine that a locational marginal price
(LMP) is a per se reasonable measure of an as-available avoided cost
for energy and to preliminarily advance several other ``Competitive
Prices'' that would also be sufficient.\13\ Current regulations
require states to consider factors, including reliability and when
the QF is available, when calculating the avoided cost rate. Today's
NOPR proposes to allow states to ignore these factors and, instead,
rely entirely on LMP or a price set at a ``liquid market hub.'' That
rule would apply across the country, irrespective of whether the QF
has access non-discriminatory access to competitive markets.\14\
That is notwithstanding the fact that the evidence the Commission
relies on to justify this proposal comes overwhelmingly from regions
with sophisticated RTO and ISO markets and/or restructured
utilities.
---------------------------------------------------------------------------
\13\ NOPR, 168 FERC ] 61,184 at PP 50, 55-60.
\14\ The NOPR proposes to allow states or utilities to use this
liquid market price only for the ``as-available'' energy sales rate,
not the capacity rate or for QFs that choose the contract option.
But given that the Commission is also proposing to allow utilities
to eliminate the fixed-price contract option for energy sales, QFs
may have no choice but to rely on the ``as-available'' option for
sales of energy.
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11. As an initial matter, I support introducing more competition
into the Commission's implementation of PURPA. Liquid price signals
can be useful and transparent inputs that are worthy of considering
as part of the overall calculation of an appropriate avoided cost
number that includes both the short-term and long-term costs avoided
by the utility's purchases from QFs. But referencing the words
``competitive'' and ``market'' over and over again is not the same
thing as proof that there is sufficient market competition. Many
regions of the country--often the same regions where the debates
about PURPA are most heated--have not established competitive
markets, let alone non-discriminatory access to those markets for
independent generators, even if there are liquid market hubs for
spot energy purchases. When combined with the Commission's proposal
to allow utilities to eliminate the contract option, discussed
above, QFs may be reduced to relying solely on some synthetic
measure of what spot prices would be in a competitive market based
on gas prices and heat rates. I am not persuaded that this will
satisfy our obligation to encourage QFs.
12. Nor am I confident that this proposal will not result in
discriminatory rates. In regions of the country with vertically
integrated utilities (including some parts of RTO/ISO markets) the
relevant utility will almost always receive guaranteed cost-recovery
on its generation investments. Indeed, state regulators will often
effectively pre-approve certain incumbent utility investments
through those utilities' integrated resource plans, making it highly
unlikely that the utility investments will ultimately be disallowed
as imprudent. Under those circumstances, it is not clear to me how a
rule that conclusively presumes that LMP--let alone some other
measure of price--is a non-discriminatory rate in those regions.
13. I recognize that in some regions of the country--such as the
RTOs and ISOs with developed real-time and day-ahead markets and
largely restructured utilities--this may be an appropriate approach
for calculating the as-available rate for energy, at least for
relatively large QFs. But the NOPR's proposed revisions are not
limited to those regions and are not even predicated on utilities
themselves actually relying on LMP, liquid market hubs, or other
calculations of ``Competitive Prices.'' In any case, neither the
record nor the rationale in this NOPR addresses these concerns in a
convincing manner.
B. Reducing the 20 MW Rebuttable Presumption
14. The Commission is also proposing to reduce the threshold for
the rebuttable presumption of non-discriminatory access to
competitive wholesale markets within RTOs and ISOs from 20 MW to 1
MW. This proposal would, in essence, relieve most utilities within
RTOs and ISOs from the must-purchase obligation for any resource
greater than 1 MW based on the theory that those resources have non-
discriminatory access to the RTO and ISO markets.\15\
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\15\ This issue, as much as any other, has been subject to
vigorous debate in Congress. See supra at 3.
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15. The Commission created the rebuttable presumption framework
in response to Congress's enactment of section 210(m) in EPAct 2005.
The Commission explained that QFs smaller than 20 MW often face more
challenges than larger QFs in accessing competitive wholesale
markets and therefore presumptively do not have non-discriminatory
access.\16\ The challenges it identified included issues such as
interconnection at the distribution level, jurisdictional
differences, pancaked delivery rates, and administrative burdens to
obtaining access to distant buyers.\17\
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\16\ New PURPA Section 210(m) Regulations Applicable to Small
Power Production and Cogeneration Facilities, Order No. 688, 117
FERC ] 61,078, at PP 9-12 (2006), order on reh'g, Order No. 688-A,
119 FERC ] 61,305 (2007), aff'd sub nom. Am. Forest & Paper Ass'n v.
FERC, 550 F.3d 1179 (D.C. Cir. 2008).
\17\ NOPR, 168 FERC ] 61,184 at P 121.
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16. Today's NOPR contains precious little justification to
support that change and does not cite a single piece of record
evidence supporting its proposal.\18\ That may be because it seems a
stretch to suggest that a 1 MW resource can generally access and
compete in markets as sophisticated and complex as, for example, PJM
Interconnection, L.L.C., on a similar footing as the resources in
the portfolio of a large vertically integrated utility or merchant
power generator.
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\18\ To the contrary, the Commission has found that QFs less
than 20 MW may not have non-discriminatory access, even within RTO/
ISO markets. In just the last few years, the Commission has
explained that barriers such as transmission constraints are the
very ``circumstances explained in Order No. 688 that gave rise to
the rebuttable presumption that smaller QFs lack nondiscriminatory
access to markets.'' N. States Power Co., 151 FERC ] 61,110, at P 34
(2015). Today's NOPR fails to provide any explanation for the
departure from the Commission's existing policy.
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17. These are among the most important issues presented in this
NOPR. I hope that the parties will assemble a correspondingly robust
record that allows to us to dig into them in detail and evaluate
whether the Commission's proposals are consistent with our
obligations under the statute.
III. PURPA Should Be Revised To Create More Competition, Not Less
18. Insofar as I can tell, the Commission interprets the success
of PURPA since 1978 as evidence that the law is no longer needed and
that the Commission should revise its regulations so that they do
less to encourage QFs. I draw a slightly different conclusion from
the same evidence. I view PURPA's success in deploying gigawatts of
relatively low-cost electricity as proof of the benefits of
introducing competition into the bulk power system.
19. Several proposals in the record would do just that. For
example, the National Association of Regulatory Commissioners
(NARUC) submitted a proposal for how the Commission might implement
section 210(m)(1), which was added by the Energy Policy Act of 2005.
The new provision provided three bases for FERC to terminate a
utility's must-purchase obligation under PURPA, all of which hinged
on QFs' access to competitive wholesale electricity markets.\19\ The
NARUC proposal urged the
[[Page 53275]]
Commission to give meaning to section 210m(1)(C) of the Federal
Power Act by establishing criteria by which a vertically integrated
utility outside of an RTO or ISO could apply to terminate the must-
purchase obligation if it conducts sufficiently competitive auctions
or RFPs for energy and capacity.\20\ In other words, it would use
the pathway established by Congress's amendments to PURPA to create
more opportunity and competition in areas where, for non-incumbent
utilities, PURPA is often the only game in town.
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\19\ Section 210m(1) provides:
(A)(i) Independently administered, auction-based day ahead and
real-time wholesale markets for the sale of electric energy; and
(ii) wholesale markets for long-term sales of capacity and electric
energy; or
(B)(i) transmission and interconnection services that are
provided by a Commission approved regional transmission entity and
administered pursuant to an open access transmission tariff that
affords nondiscriminatory treatment to all customers; and (ii)
competitive wholesale markets that provide a meaningful opportunity
to sell capacity, including long-term and short-term sales, and
electric energy, including long-term, short-term, and real-time
sales, to buyers other than the utility to which the qualifying
facility is interconnected. In determining whether a meaningful
opportunity to sell exists, the Commission shall consider, among
other factors, evidence of transactions within the relevant market;
or
(C) wholesale markets for the sale of capacity and electric
energy that are, at a minimum, of comparable competitive quality as
markets described in subparagraphs (A) and (B).
16 U.S.C. 824a-3(m)(1) (2018)
\20\ National Association of Regulatory Utility Commissioners
Supplemental Comments, Docket No. AD16-16-00 (Oct. 17, 2018),
Attachment A at 8; id. (proposing the Commission's Edgar-Allegheny
criteria as a basis for evaluating whether a proposal was adequately
competitive).
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20. The NARUC proposal was a whitepaper, not a detailed NOPR. It
would surely require more development before we could determine
whether it satisfies PURPA's statutory requirements. Nevertheless it
represented a step in the right direction that would have been
consistent with PURPA's pro-competitive purposes. It was also an
idea that we could have--and should have--amply explored through a
technical conference or other proceeding since the Chairman
indicated his intent to go forward with revisions to PURPA.
21. The Solar Energy Industries Association also put forward a
pro-competitive proposal of the type that I would like to have
explored in more detail in this NOPR.\21\ The proposal would address
competitive solicitations as a means of procuring energy and
capacity from all new generation resources, including QFs. It also
discussed the potential for these competitive solicitations to set
avoided cost under certain circumstances. As with the NARUC
proposal, this proposal would revise PURPA to include more genuine
competition rather simply revising the regulations to do less to
encourage QFs.
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\21\ Solar Energy Industries Association Supplemental Comments,
Docket No. AD16-16-000 (Aug. 28, 2019).
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22. Rather than seeking to expand competition, the majority is
instead using the success of competition in certain parts of the
country as a reason to scale back PURPA throughout the country. In
some areas of the country, particularly those with developed RTO and
ISO markets and with few, if any, vertically integrated utilities,
competition is the norm and PURPA may not be necessary, at least for
generators that are sufficiently large and sophisticated to
participate on an equal footing with other market participants. But
it does not necessarily follow that the healthy competition we see
in those regions means that PURPA does not continue to play a vital
role in other parts of the country, including those without RTO and
ISO markets or where vertically integrated utilities dominate. To
put it bluntly, the success that a QF might have in selling its
energy and capacity within ISO New England Inc. tells you very
little about the success a similar resource might have in the
Southeast or the West, at least without PURPA. I worry that applying
lessons learned in the truly competitive regions of the country to
the less competitive regions will actually result in less
competition and, ultimately, higher prices for consumers.
23. I support certain aspects of this NOPR that I believe are
consistent with the Commission's proper role in administering PURPA
and are supported by the record developed so far. First and
foremost, I agree that it is time to address the ``one-mile'' rule,
which currently provides an irrebuttable presumption that resources
located more than a mile apart are separate QFs.\22\ There is
evidence compiled as part of the Commission's 2016 technical
conference on PURPA that suggests that this rule is susceptible to
gaming and that some developers are splitting what should fairly be
considered one project into a series of discrete projects spread
separated by a mile each.\23\ I do not believe that is what Congress
had in mind when it set out to promote small power production
facilities in PURPA. The NOPR proposes what I believe is a
reasonable framework for addressing this issue and I look forward to
reviewing the comments we receive.
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\22\ 18 CFR 292.204(a) (2019).
\23\ See Statement of Paul Kjellander, Docket No. AD16-16-000,
at 4-5 (June 29, 2016); Portland General Electric Company Comments,
Docket No. AD16-16-000, at 6 (June 29, 2016).
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24. In addition, I support the proposal to require that QFs
demonstrate commercial viability before securing a legally
enforceable obligation with the relevant utility. It seems only fair
to require that a proposed QF demonstrate that it is not speculative
and will likely enter service before a utility incurs an obligation
to purchase that QF's output at any particular price. The proposal
in today's NOPR appears to strike a reasonable balance between
allowing QFs to secure a commitment for purchase early enough in
their development cycle so that they can use it to facilitate
financing while preventing QFs from locking-in avoided-cost rates
too far ahead of their actual delivery of any energy or capacity.
Nevertheless, in contrast to the one-mile rule, the record on this
question is relatively underdeveloped and I hope that parties will
address the specifics of this proposal in detail.
25. Finally, I support the proposal to allow stakeholders to
protest self-certification of QFs. If an entity believes a resource
does not qualify as a QF, it should have the opportunity to protest
the QF's filing in the same way that stakeholders have the
opportunity to protest most other Commission filings. At the very
least, it seems unfair to require them to file a declaratory order,
and pay tens of thousands of dollars, in order to inform the
Commission of their views.
* * *
26. The Commission seems to believe that PURPA's time has
passed. But that is Congress's decision to make, not the
Commission's. So long as PURPA is on the books, we must faithfully
implement the requirements of the law. Although I support certain
elements of today's NOPR, I am concerned that many of the
Commission's proposals will fall short of our statutory obligations.
In addition, I am also disappointed that the Commission is not doing
more to explore using PURPA to expand opportunities for genuine
competition, including through section 210(m)--the avenue for reform
that Congress enacted in 2005. I believe that focusing on expanding
opportunities for genuine competition would far better serve the
public interest than simply rebalancing the scales against QFs,
which seems to be the principal goal of today's NOPR.
For these reasons, I respectfully dissent in part.
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Richard Glick,
Commissioner.
[FR Doc. 2019-20803 Filed 10-3-19; 8:45 am]
BILLING CODE 6717-01-P