[Federal Register Volume 85, Number 171 (Wednesday, September 2, 2020)]
[Rules and Regulations]
[Pages 54638-54740]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-15902]
[[Page 54637]]
Vol. 85
Wednesday,
No. 171
September 2, 2020
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; Final Rule
Federal Register / Vol. 85 , No. 171 / Wednesday, September 2, 2020 /
Rules and Regulations
[[Page 54638]]
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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; Order No. 872]
Qualifying Facility Rates and Requirements Implementation Issues
Under the Public Utility Regulatory Policies Act of 1978
AGENCY: Federal Energy Regulatory Commission.
ACTION: Final rule.
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SUMMARY: In this Order, the Federal Energy Regulatory Commission issues
its final rule approving certain revisions to its regulations
implementing sections 201 and 210 of the Public Utility Regulatory
Policies Act of 1978 (PURPA). These changes will enable the Commission
to continue to fulfill its statutory obligations under sections 201 and
210 of PURPA.
DATES: This rule is effective December 31, 2020.
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
Paragraph
Nos.
I. Introduction............................................. 1
II. Overview................................................ 5
A. The Commission's PURPA Regulations, as Revised by 6
This Final Rule, Continue To Encourage the Development
of QFs Within the Requirements of PURPA's Statutory
Limitations............................................
1. Avoided Cost Cap on QF Rates..................... 13
2. Limitation on Small Power Production Facilities 17
Located at the Same ``Site''.......................
3. Termination of Purchase Obligation for QFs With 18
Nondiscriminatory Access to Certain Competitive
Markets............................................
4. Final Rule's Updating of the PURPA Regulations... 20
B. The Final Rule Ensures That the Commission's 28
Implementation of PURPA Continues To Benefit QFs,
Purchasing Electric Utilities, and Electric Consumers..
C. The Commission Is Not Eliminating Fixed Rate Pricing 35
for QFs, But Rather Is Giving States the Flexibility To
Require the Same Variable Energy Rate/Fixed Capacity
Rate Construct That Applies Throughout the Electric
Industry...............................................
D. The Rate Changes Implemented by This Final Rule Put 39
QF Rates on the Same Footing as Electric Utility Rates
and Are Not Discriminatory.............................
E. The PURPA Compliance Issues Raised by Some Commenters 42
Are Outside the Scope of This Rulemaking Proceeding....
III. Background............................................. 47
A. Passage of PURPA in 1978 and the Commission's 47
Promulgation of Its PURPA Regulations in 1980..........
B. Circumstances Leading to the Commission's Re- 51
evaluation of the PURPA Regulations and the Issuance of
the NOPR...............................................
C. Summary of Changes to the PURPA Regulations 56
Implemented by This Final Rule.........................
IV. Discussion.............................................. 67
A. General Legal Standards Under PURPA.................. 67
1. Encouragement of QFs............................. 68
a. Comments..................................... 68
b. Commission Determination..................... 70
2. Discrimination................................... 79
a. Comments..................................... 79
b. Commission Determination..................... 82
3. Unlawful Delegation and the Role of Nonregulated 89
Electric Utilities.................................
a. Comments..................................... 89
b. Commission Determination..................... 93
B. QF Rates............................................. 96
1. Overview......................................... 96
2. Use of Competitive Market Prices To Set As- 103
Available Avoided Cost Rates.......................
a. NOPR Proposal................................ 104
b. Comments..................................... 107
c. Commission Determination..................... 114
3. LMP as a Permissible Rate for Certain As- 124
Available Avoided Cost Rates.......................
a. NOPR Proposal................................ 124
b. Comments..................................... 129
i. Comments in Opposition................... 129
(a) Utilizing Western EIM To Establish 137
Avoided Costs..............................
ii. Comments in Support..................... 138
(a) Utilizing Western EIM To Establish 145
Avoided Costs..............................
iii. Comments in Support With Requested 146
Modifications/Clarifications...............
c. Commission Determination..................... 151
i. Arguments Against the NOPR Proposal...... 155
ii. Requests for Modification or 173
Clarification of the NOPR..................
iii. Western EIM............................ 177
4. Use of Market Hub Prices as a Permissible Rate 180
for Certain As-Available QF Energy Sales...........
a. NOPR Proposal................................ 180
b. Comments..................................... 182
i. Comments in Support...................... 182
ii. Comments in Opposition.................. 184
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iii. Commission Determination............... 189
c. Proposed Modifications....................... 195
i. Comments................................. 195
ii. Commission Determination................ 200
5. Use of Formulas Based on Natural Gas Prices To 203
Establish a Permissible Rate for Certain As-
Available QF Energy Sales..........................
a. NOPR Proposal................................ 203
b. Comments..................................... 206
c. Commission Determination..................... 211
6. Permitting the Energy Rate Component of a 217
Contract To Be Fixed at the Time of the LEO Using
Forecasted Values of the Estimated Stream of Market
Revenues...........................................
a. Comments..................................... 219
b. Commission Determination..................... 227
7. Providing for Variable Energy Rates in QF 232
Contracts..........................................
a. Background................................... 232
b. NOPR Proposal................................ 234
c. General Comments on the NOPR Proposal........ 245
i. Comments in Support of NOPR Proposal..... 245
ii. Comments in Opposition to NOPR Proposal. 248
iii. Commission Determination............... 253
d. Whether the Current Approach Has Resulted in 265
Payments to QFs in Excess of Avoided Costs.....
i. Comments in Support of NOPR Proposal..... 265
ii. Comments in Opposition to NOPR Proposal. 272
iii. Commission Determination............... 283
e. Whether the Proposed Change Would Violate the 294
Statutory Requirement That the PURPA
Regulations Encourage QFs......................
i. Comments................................. 294
i. Commission Determination................. 295
f. Discrimination............................... 297
i. Comments in Support of NOPR Proposal..... 297
ii. Comments in Opposition to NOPR Proposal. 298
iii. Commission Determination............... 302
g. Effect of Variable Energy Rates on Financing. 304
i. Comments in Support of the NOPR Proposal. 304
ii. Comments in Opposition to the NOPR 312
Proposal...................................
iii. Commission Determination............... 335
h. Other Claimed Benefits of Fixed Avoided Cost 350
Energy Rates...................................
i. Comments................................. 350
ii. Commission Determination................ 351
i. Potential Modifications to NOPR Proposal..... 354
i. Comments................................. 354
ii. Commission Determination................ 357
8. Consideration of Competitive Solicitations To 361
Determine Avoided Costs............................
a. NOPR Proposal................................ 361
b. Comments..................................... 368
i. Comments in Opposition................... 368
ii. Comments in Support..................... 375
iii. Comments Requesting Modifications/ 383
Clarifications.............................
(a) Requests for Clarification and/or 383
Separate Proceedings.......................
(b) Requests Regarding Proposed Criteria.... 390
(c) Other Requests.......................... 400
c. Commission Determination..................... 411
i. Requests for Clarification and/or 415
Separate Proceedings.......................
ii. Proposed Criteria....................... 420
iii. Other Requests......................... 439
C. Relief from Purchase Obligation in Competitive Retail 442
Markets................................................
1. NOPR Proposal.................................... 442
2. Comments......................................... 444
3. Commission Determination......................... 456
D. Evaluation of Whether QFs Are at Separate Sites...... 458
1. Rebuttable Presumption of Separate Sites......... 458
a. NOPR Proposal................................ 458
b. Commission Determination..................... 466
c. Need for Reform.............................. 470
i. Comments................................. 470
ii. Commission Determination................ 472
d. Site Definition.............................. 473
i. Comments................................. 473
ii. Commission Determination................ 476
e. Distance Between Facilities.................. 482
i. Comments................................. 482
ii. Commission Determination................ 490
f. Factors...................................... 497
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i. Comments................................. 497
ii. Commission Determination................ 508
g. Exemptions................................... 512
i. Comments................................. 512
ii. Commission Determination................ 514
2. Electrical Generating Equipment.................. 515
a. NOPR Proposal................................ 515
b. Comments..................................... 518
c. Commission Determination..................... 521
E. QF Certification Process............................. 525
1. NOPR Proposal.................................... 525
2. Comments......................................... 530
3. Commission Determination......................... 547
F. Corresponding Changes to the FERC Form No. 556....... 570
1. NOPR Proposal.................................... 570
2. Comments......................................... 577
3. Commission Determination......................... 584
G. PURPA Section 210(m) Rebuttable Presumption of 597
Nondiscriminatory Access to Markets....................
1. PURPA Section 210(m) Implementation.............. 597
a. NOPR Proposal................................ 597
b. Comments in Opposition....................... 602
i. Insufficient Evidentiary Support......... 603
ii. Administrative Burden and Complex Market 611
Rules......................................
c. Comments in Support.......................... 614
d. Comments Requesting Modifications/ 617
Clarifications.................................
e. Commission Determination..................... 624
2. Reliance on RFPs and Liquid Market Hubs To 648
Terminate Purchase Obligation Under PURPA Section
210(m).............................................
a. NOPR Discussion.............................. 648
b. Comments..................................... 651
i. Comments in Opposition................... 651
ii. Comments in Support..................... 655
c. Commission Determination..................... 659
H. Legally Enforceable Obligation....................... 663
1. NOPR Proposal.................................... 663
2. Comments......................................... 666
a. Comments in Opposition....................... 666
b. Comments in Support.......................... 673
c. Comments Requesting Modification............. 676
i. Studies.................................. 677
ii. Commercial Viability.................... 679
iii. Financial Viability.................... 681
iv. Rejecting QF Purchases and Expanded 683
Curtailment Rights.........................
3. Commission Determination......................... 684
V. Information Collection Statement......................... 697
VI. Environmental Analysis.................................. 702
A. Comments............................................. 703
B. Commission Determination............................. 710
1. No EIS or EA is Required......................... 712
a. There Is No Project That Defines the Scope 712
and Limits of QF Development...................
b. A Categorical Exclusion Applies.............. 720
i. Changes That Are Clarifying in Nature.... 721
ii. Changes That Are Corrective in Nature... 722
iii. Changes That Are Procedural in Nature.. 727
2. The NEPA Analysis for Promulgation of the 728
Original PURPA Regulations in 1980 Cannot Be
Replicated Here....................................
3. This Proceeding Does Not Trigger Any ESA 737
Consultation Requirement...........................
VII. Regulatory Flexibility Act Certification............... 743
VIII. Document Availability................................. 750
IX. Effective Dates and Congressional Notification.......... 753
I. Introduction
1. In this Order, the Federal Energy Regulatory Commission
(Commission) issues its final rule approving certain revisions to its
regulations (PURPA Regulations) \1\ implementing sections 201 and 210
of the Public Utility Regulatory Policies Act of 1978 (PURPA).\2\
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\1\ 18 CFR part 292 (2019). In connection with the revisions to
the PURPA Regulations, the Commission also is revising its
delegation of authority to Commission staff in 18 CFR pt. 375.
\2\ 16 U.S.C. 796(17)-(18), 824a-3.
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2. On September 19, 2019, the Commission issued a notice of
proposed rulemaking (NOPR) proposing to modify its PURPA
Regulations.\3\ Those regulations were promulgated in 1980 and have
been modified in only specific respects since then. Approximately 130
separate comments were submitted in response to the NOPR,\4\ several of
which were submitted on behalf of multiple parties. In total, over
1,600 pages of comments were submitted, and in addition thousands of
pages of exhibits
[[Page 54641]]
were attached to the comments. The entities that filed comments are
listed in Appendix A. This final rule addresses comments received in
response to the NOPR.
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\3\ Qualifying Facility Rates and Requirements Implementation
Issues Under the Public Utility Regulatory Policies Act of 1978, 168
FERC ] 61184 (2019) (NOPR).
\4\ See Appendix for list of commenters.
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3. We largely adopt the NOPR proposals. However, this final rule
makes certain modifications to the NOPR proposals, as further discussed
below.
4. Given the Commission's expressed intent in the NOPR to propose
revisions to the PURPA Regulations that more closely adhere to the
goals and terms of PURPA,\5\ we considered comments regarding whether
these proposals are consistent with the requirements of PURPA. Based on
that review and further consideration, we adopt the following changes
to the proposals in the NOPR, among certain others described below:
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\5\ NOPR, 168 FERC ] 61,184 at P 31.
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We establish a rebuttable presumption, rather than a per
se rule, that locational marginal prices (LMPs) may reflect a
purchasing electric utility's avoided energy costs;
We provide that any competitive solicitations used to
establish avoided capacity costs must adhere to the Commission's
Allegheny \6\ standard for evaluating competitive solicitations;
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\6\ Allegheny Energy Supply Co., LLC, 108 FERC ] 61,082, at P 18
(2004) (Allegheny).
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We do not adopt the proposed rule permitting states with
retail competition to allow relief from the purchase obligation but
instead clarify that the Commission's existing PURPA Regulations
already require that states, to the extent practicable, must account
for reduced loads in setting QF capacity rates;
We clarify terminology we used in the NOPR relating to the
determination of whether small power production facilities are separate
facilities to focus not on whether they are separate facilities, but
rather to mirror the statutory language and thus focus on whether they
are at ``the same site'';
We clarify in the regulations that protests may be made to
initial self-certifications and applications for Commission
certification, but only to self-recertifications and applications for
Commission recertification making substantive changes to the existing
certification;
We identify additional factors that can be considered for
small power production qualifying facilities (QFs) located more than
one but less than 10 miles apart, such as evidence of shared control
systems, common permitting and land leasing, and shared step-up
transformers;
We revise the regulations to lower the rebuttable
presumption of small power production QFs' nondiscriminatory access to
5 MW, rather than 1 MW as proposed in the NOPR, and include factors
that a small power production QF sized greater than 5 MW could rely on
to rebut the presumption that it has nondiscriminatory access to
markets defined in PURPA sections 210(m)(1); and
We revise the proposed requirements to establish a legally
enforceable obligation (LEO) to provide that with regard to the issue
of obtaining permits, QFs need only have applied for all required
permits, instead of being required to have already obtained those
permits.
II. Overview
5. Before discussing each of the individual changes to the PURPA
Regulations adopted herein, this final rule first addresses certain
overall themes raised in the comments on the NOPR, both those
supporting the NOPR and those opposing.
A. The Commission's PURPA Regulations, as Revised by This Final Rule,
Continue To Encourage the Development of QFs Within the Requirements of
PURPA's Statutory Limitations
6. PURPA section 210(a) requires that the Commission prescribe
rules that it determines necessary to encourage the development of
qualifying small power production facilities and cogeneration
facilities.
7. The bulk of the criticism of the Commission's proposed rule
changes is based on a widespread misunderstanding, as reflected in the
comments on the NOPR, that PURPA and the PURPA Regulations were
intended to encourage QF development without any limit, and that the
rule changes proposed in the NOPR improperly reduce or even eliminate
encouragement in contravention of the statute. Those commenters
opposing the NOPR proposals argue that the Commission has determined,
in contravention of the statute, that there no longer is a need to
encourage QFs, or eliminated any provision that provides such
encouragement.\7\ Many of the commenters supporting the changes
proposed in the NOPR applaud the Commission for eliminating what they
argue amounts to an improper subsidy of QFs.\8\
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\7\ See, e.g., Biological Diversity Comments at 14; ConEd
Development Comments at 2; Harvard Electricity Law Comments at 4;
New England Small Hydro Comments at 4; NIPPC, CREIA, REC, and OSEIA
Comments at 3, 21, 28; Public Interest Organizations Comments at 9,
39; Solar Energy Industries Comments at 4; Southeast Public Interest
Organizations Comments at 17.
\8\ See Competitive Enterprise Institute Comments at 3;
Progressive Policy Institute Comments at 1-2; SBE Council Comments
at 2; Mr. Moore Comments at 1-2.
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8. Neither side is correct about either what PURPA and the current
PURPA Regulations require, or the basis for the changes to the PURPA
Regulations proposed in the NOPR.
9. As an initial matter, PURPA was not a directive to the
Commission to encourage QF development without limitation. Indeed, as
explained below, Congress included several limitations in PURPA. By
reading the statute as a whole, and the PURPA Regulations as a whole as
revised by this final rule, it is clear that the PURPA Regulations
continue to encourage the development of QFs consistent with PURPA.\9\
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\9\ 16 U.S.C. 824a-3(a).
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10. We also emphasize that we do not by this final rule change
other elements to the Commission's existing PURPA Regulations that
continue to encourage QF development. These elements include, but are
not limited to, rules that: (1) Require electric utilities to provide
backup electric energy to QFs on a non-discriminatory basis and at just
and reasonable rates; (2) require electric utilities to interconnect
with QFs; and (3) provide exemptions to QFs from many provisions of the
Federal Power Act (FPA) and state laws governing utility rates and
financial organization.\10\ These provisions encourage the development
of QFs by relieving them of certain regulatory burdens otherwise
imposed on sellers of power and ensure they can operate their
facilities. Moreover, we stress that, besides the changes to the PURPA
Regulations regarding applications to terminate a purchasing electric
utility's mandatory purchase obligation under PURPA section 210(m) (see
infra section IV.G), nothing in this final rule eliminates QFs' rights
to sell electric energy or capacity as provided under PURPA.
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\10\ See 18 CFR 292.303(c), 292.305, 292.601-02.
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11. As discussed in greater detail below, while PURPA provided for
the encouragement of cogeneration and small power production, PURPA
also provided that the Commission could not prescribe a rule that
provided for ``a rate which exceeds the incremental cost to the
electric utility of alternative electric energy.'' \11\ Furthermore,
PURPA requires the Commission to ``insure'' that the resulting rates
``shall be just and reasonable to the electric consumers of
[[Page 54642]]
the electric utility and in the public interest[.]'' \12\ Likewise,
while PURPA provided for the encouragement of small power production,
PURPA also limited the facilities which could be encouraged to those
facilities with no more than 80 MW power production capacity at the
same site.\13\
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\11\ Compare id. with 16 U.S.C. 824a-3(b).
\12\ 16 U.S.C. 824a-3(b)(1).
\13\ Compare 16 U.S.C. 824a-3(a) with 16 U.S.C. 796(17)(A)(ii).
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12. Nothing in the text of PURPA requires the establishment of a
subsidy for QFs. This point was confirmed in the Conference Report
accompanying PURPA's passage: ``The provisions of this section are not
intended to require the rate payers of a utility to subsidize
cogenerators or small power producers.'' \14\ Congress thus structured
PURPA both specifically to give effect to its intent that QFs not be
subsidized and also to impose other mandatory limits on the
Commission's ability to encourage QFs that are relevant to this final
rule, as briefly summarized below.
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\14\ H.R. Rep. No. 95-1750, at 98 (1978) (Conf. Rep.).
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1. Avoided Cost Cap on QF Rates
13. PURPA section 210(b) sets out the standards governing the rates
purchasing utilities must pay to QFs.\15\ Sections 210(b)(1) and (b)(2)
provide that QF rates ``shall be just and reasonable to the electric
consumers of the electric utility and in the public interest'' and
``shall not discriminate against qualifying cogenerators or qualifying
small power producers.'' \16\ After establishing these standards,
Congress then placed, in the final sentence of section 210(b), a cap on
the level of the rates utilities could be required to pay QFs: ``No
such rule prescribed under subsection (a) shall provide for a rate
which exceeds the incremental cost to the electric utility of
alternative electric energy.'' \17\ As the Conference Report for PURPA
explains:
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\15\ 16 U.S.C. 824a-3(b).
\16\ Id.
\17\ Id. (emphasis added). The statute defines an electric
utility's ``incremental costs'' as ``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.'' 16 U.S.C. 824a-3(d); see also 18 CFR
292.101(b)(6) (implementing same and defining such ``incremental
costs'' as ``avoided costs'').
[T]he utility would not be required to purchase electric energy
from a qualifying cogeneration or small power production facility at
a rate which exceeds the lower of the rate described above, namely a
rate which is just and reasonable to consumers of the utility, in
the public interest, and nondiscriminatory, or the incremental cost
of alternate electric energy. This limitation on the rates which may
be required in purchasing from a cogenerator or small power producer
is meant to act as an upper limit on the price at which utilities
can be required under this section to purchase electric energy.\18\
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\18\ Conf. Rep. at 98 (emphasis added).
14. This upper limit on QF rates established in section 210(b),
equal to a purchasing utility's incremental costs, commonly called
``avoided costs,'' implements Congress's intent that QFs not be
subsidized. It ensures that the purchasing utility cannot be required
to pay more for power purchased from a QF than it would otherwise pay
to generate the power itself or to purchase power from a third party.
15. Consistent with the statutory standard, when the Commission
issued its PURPA Regulations in 1980, it set the rates for QFs at, but
not above, the statutorily defined incremental or avoided cost of
alternative electric energy.\19\ The PURPA Regulations applied this
limitation generally to QF rates, without distinguishing between as-
available energy \20\ and the fixed energy and capacity rate option
applicable to long-term contracts or other legally enforceable
obligations.\21\ In either case, though, the PURPA Regulations
essentially capped the rate paid to QFs at the purchasing electric
utility's avoided costs.\22\
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\19\ Compare 16 U.S.C. 824a-3(b) & (d) with 18 CFR
292.101(b)(6), 292.304(a)(2) & (b)(2).
\20\ 18 CFR 292.304(d)(1).
\21\ 18 CFR 292.304(d)(2) (providing QFs the right to elect
avoided costs calculated at the time of delivery or avoided costs
calculated at the time the obligation is incurred). In this final
rule, we refer to the QF's option for avoided costs calculated at
the time the obligation is incurred as the fixed energy and capacity
rate option. 18 CFR 292.304(d)(2).
\22\ The regulations, however, also allowed both for negotiated
rates that differed from the rates that would otherwise be
applicable, see 18 CFR 292.301(b), and for rates to be set based on
estimates of avoided costs even though such rates might differ from
avoided costs at the time of delivery. See 18 CFR 292.304(b)(5).
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16. Order No. 69, in which the Commission promulgated the PURPA
Regulations,\23\ makes clear that the Commission also recognized that
allowing the option for a fixed energy and capacity rate option for
long-term contracts or other legally enforceable obligations could
result in a rate that, at times, exceeded incremental or avoided cost
of alternative electric energy. The Commission acknowledged in this
regard that some commenters had asserted that, ``if the avoided cost of
energy at the time it is supplied is less than the price provided in
the contract or obligation, the purchasing utility would be required to
pay a rate for purchases that would subsidize the qualifying facility
at the expense of the utility's other ratepayers.'' \24\ In response,
the Commission stated that it ``recognize[d] this possibility, but is
cognizant that in other cases, the required rate will turn out to be
lower than the avoided cost at the time of purchase.'' \25\ The
Commission concluded that any over- and under-recoveries compared to
avoided cost ``will balance out'' and, based on this conclusion, found
that the fixed energy and capacity rate option applicable to long-term
contracts or other legally enforceable obligations did not violate the
statutory cap.\26\ But, to be clear, the option the Commission
implemented in 1980 was not based on any determination by the
Commission that the rates in QF contracts may routinely exceed avoided
costs in the ordinary course of events in order to encourage QFs.
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\23\ 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 30,880 (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., Inc. v. Am. Elec.
Power Serv. Corp., 461 U.S. 402 (1983) (API).
\24\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,880.
\25\ Id.
\26\ Id.
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2. Limitation on Small Power Production Facilities Located at the Same
``Site''
17. Another way in which Congress set boundaries on the
Commission's ability to encourage development of QFs was to define
small power production facilities, one of the categories of generators
that under the statute is to be encouraged. The definition of small
power production facilities applies to almost all renewable resources
that wish to be QFs, requiring that those facilities have ``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.'' \27\ In order to comply with this statutory requirement
that the capacity of all small power production facilities ``located at
the same site'' cannot exceed 80 MW, the Commission is required to
define what constitutes a ``site.'' The Commission determined in 1980
that, essentially, those facilities that are owned by the same or
affiliated entities and using the same energy resource should be deemed
to be at the same site ``if they are located within one mile of the
facility for which
[[Page 54643]]
qualification is sought.'' \28\ This definition, known as the ``one-
mile rule,'' interpreted Congress's limitation of 80 MW located at the
same site to apply to just those affiliated small power production
qualifying facilities located within one mile of each other.
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\27\ 16 U.S.C. 796(17)(A)(ii).
\28\ 18 CFR 292.204(a)(ii).
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3. Termination of Purchase Obligation for QFs With Nondiscriminatory
Access to Certain Competitive Markets
18. Finally, Congress amended PURPA in 2005 to further limit the
statute. Congress amended PURPA section 210 to add section 210(m),
which 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 has nondiscriminatory access to certain defined types of
markets.\29\ This amendment reflected Congress's judgment that non-
discriminatory access to these markets provided adequate encouragement
for those QFs.
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\29\ See 16 U.S.C. 824a-3(m).
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19. Congress directed the Commission to implement this requirement,
which it did in Order No. 688. In that order, the Commission identified
certain markets in which utilities would no longer be subject to the
PURPA mandatory purchase obligation under PURPA section 210(m) because
certain QFs have nondiscriminatory access to such markets.\30\ Although
not required in the new PURPA section 210(m), the Commission
established a rebuttable presumption that a QF with a net power
production capacity at or below 20 MW does not have nondiscriminatory
access to such markets.\31\ In creating this rebuttable presumption,
the Commission found persuasive arguments that some QFs may not have
nondiscriminatory access to markets in light of their small size.
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\30\ 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).
\31\ 18 CFR 292.309(d)(1).
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4. Final Rule's Updating of the PURPA Regulations
20. In this final rule, we are amending the PURPA Regulations,
principally with regard to the three statutory provisions described
above, i.e.: (1) The avoided cost cap on QF rates; (2) the 80 MW
limitation applicable to the combined capacity of affiliated small
power production QFs located at the same site; and (3) the termination
of the mandatory purchase obligation for QFs with nondiscriminatory
access to certain markets. Contrary to commenters' assertions that the
Commission has determined that it no longer is necessary to encourage
QFs and therefore that the Commission is making these changes in an
impermissible attempt to undo PURPA,\32\ we are modifying the PURPA
Regulations based on demonstrated changes in circumstances since the
current PURPA Regulations were first adopted to ensure that the
regulations continue to comply with PURPA's statutory requirements
established by Congress.
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\32\ Biomass Power Comments at 2; Biological Diversity at 12;
EPSA Comments at 6 (``[T]he NOPR changes `would effectively gut'
PURPA.''); NIPPC, CREA, REC, and OSEIA Comments at 28-29; Public
Interest Groups Comments at 25 (``[T]he changes proposed in the NOPR
will gut PURPA-mandated measures to encourage QF development.'');
Solar Energy Industries Comments at 8-14.
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21. For example, as explained in more detail below, the
Commission's expectation expressed in 1980 that over- and under-
recovery in rates compared to avoided cost ``will balance out'' \33\
was critical to the Commission's determination in 1980 that the fixed
energy and capacity rate option applicable to long-term contracts or
other legally enforceable obligations did not violate the statutory
avoided cost cap on QF rates. However, record evidence now demonstrates
that this expectation no longer is necessarily accurate. The
Commission's change to the PURPA Regulations adopted in this final
rule, giving states the ability to require variable energy rates in
long-term contracts or other legally enforceable obligations, allows
the states to better ensure that QF rates are at, but do not exceed,
the statutory maximum rate established by Congress.
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\33\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,880.
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22. This change is important for purposes of compliance with
PURPA's statutory mandates. As explained below, setting QF rates at
avoided costs allows the Commission to comply with the statutory goals
of encouraging QFs and providing for nondiscriminatory rates while at
the same time ensuring that such rates are just and reasonable to
consumers and do not subsidize QFs. The record shows that on some
occasions long-term fixed QF rates were well above actual avoided
costs, thereby causing consumers to subsidize those QFs in
contravention of PURPA and the Commission's expectations.
23. Similarly, the changes implemented by the Commission in this
final rule to the one-mile rule are intended to better ensure
compliance with the statutory requirement that small power production
facilities located at the same site cannot exceed 80 MW. And, 15 years
after Congress added PURPA section 210(m), because the Commission can
now make the determination, described below, that smaller QFs have non-
discriminatory access to RTO/ISO markets, an update to the rebuttable
presumption regarding non-discriminatory access to those markets is
appropriate to better ensure compliance with the statute.
24. Some commenters incorrectly assert that the final rule
impermissibly revises the PURPA Regulations in a way that no longer
encourages QFs. PURPA section 210(a) provides not simply that the
Commission is to prescribe rules that encourage QFs, but rather that
the Commission is to ``prescribe, and from time to time thereafter
revise, such rules as it determines necessary to encourage'' QFs.
Carrying out Congress's directive to ``from time to time thereafter
revise'' the rules is at the heart of what the Commission is doing in
this final rule. Consistent with this directive, the Commission is
considering revisions to ``such rules as it determines necessary to''
encourage QFs in light of current industry circumstances.\34\
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\34\ We view the revisions to our rules implementing PURPA that
we adopt in this final rule as consistent with Congress's explicit
directive that the Commission ``from time to time thereafter [to]
revise'' the rules. We do not view Congress as intending that the
Commission only ever consider the circumstances that existed in the
late 1970s and not current circumstances, 40 years later.
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25. The changes adopted in this final rule result from the need for
the PURPA Regulations to continue to comply with the directives
Congress established when it enacted PURPA in 1978, and then again when
Congress amended PURPA in 2005. These changes are not based on any
determination by the Commission that the encouragement directed by
PURPA is no longer needed. The question of whether QFs should continue
to be encouraged or not remains a question for Congress.
26. Moreover, PURPA also requires the Commission to insure that the
rates for QF purchases be ``just and reasonable to the electric
consumers of the electric utility and in the public interest[.]'' \35\
The obligation to encourage is also limited by the requirement that,
``No such rule prescribed under subsection (a) [the encouragement
provision] shall provide for a rate which exceeds the incremental cost
to the electric utility of alternative electric energy.'' \36\
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\35\ 16 U.S.C. 824a-3(b).
\36\ 16 U.S.C. 824a-3(b).
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27. We recognize that some of the comments opposing the NOPR may
[[Page 54644]]
have been influenced by the Commission's recitation in the Background
section of the NOPR of the broad changes in circumstances since the
PURPA Regulations were first promulgated 40 years ago, including the
discovery of significant new natural gas reserves, the evolution of the
electric industry to include a significant independent power presence,
the establishment of organized competitive markets, and the advances in
renewable energy technologies.\37\ We clarify that the Commission
referenced this general background information in the NOPR primarily to
explain why it decided to re-evaluate its PURPA Regulations at all and
as Congress said we should, and not necessarily to support the
individual proposals included in the NOPR. The facts we rely on to
propose specific changes, which include some, but not all, of those
background facts, were cited in the specific sections of the NOPR
describing those proposed changes. And the facts on which we rely to
promulgate the specific changes in this final rule again are cited in
the specific sections describing those changes.
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\37\ NOPR, 168 FERC ] 61,184, at PP 15-27.
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B. The Final Rule Ensures That the Commission's Implementation of PURPA
Continues To Benefit QFs, Purchasing Electric Utilities, and Electric
Consumers
28. The final rule implements additional changes consistent with
PURPA that also are designed to benefit QFs, purchasing utilities, and
electric consumers. The changes to the PURPA Regulations adopted in
this final rule will enable the Commission to continue satisfying the
statutory requirement that the Commission promulgate rules to encourage
QF development consistent with PURPA's requirements. Claims to the
contrary by commenters to the effect that the ``proposals are uniformly
biased against QF development'' \38\ have no merit.
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\38\ Harvard Electricity Law Comments at 1.
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29. As an initial matter, we are not changing the determination in
the PURPA Regulations that QF rates must equal a purchasing electric
utility's full avoided costs.\39\ As the Supreme Court noted in API,
the full avoided cost rate requirement represents the maximum rate
permitted under PURPA, and thereby provides important encouragement to
QFs.\40\ The Court explained that the full avoided cost rate
requirement encourages QF development because QFs ``retain an incentive
to produce energy under the full-avoided-cost rule so long as their
marginal costs did not exceed the full avoided cost of the purchasing
utility.'' \41\
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\39\ See 18 CFR 292.304(b)(2); NOPR, 168 FERC ] 61,184 at P 34.
\40\ API, 461 U.S. at 413. PURPA does not use the terms
``avoided cost'' or ``full avoided cost''; rather, PURPA uses the
term ``incremental cost of alternative electric energy.'' The
Commission's regulations and subsequent decisions have used the term
``avoided cost'' to explain the Commission's application of the
``incremental cost'' standard. The API decision and early Commission
precedents referred to ``full'' avoided costs to distinguish between
the Commission's decision to set QF rates at avoided costs and
proposals from certain parties that rates be set at something less
than avoided costs. We continue to use the terms avoided costs and
full avoided costs as being consistent with the statutory term
incremental cost.
\41\ Id. at 416.
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30. In addition, several of the changes to the current PURPA
Regulations implemented by this final rule are based expressly on a
finding that they are beneficial to QFs as well as to purchasing
utilities and ratepayers. For example, the provisions of the final rule
allowing for energy rates to be based on transparent, competitive
market prices--in appropriate circumstances--are supported by comments
submitted at the Technical Conference, where representatives of QFs and
utilities both expressed a preference for transparent prices for
QFs.\42\ This conclusion is supported by the Fitch Report, cited by
NIPPC, CREA, REC, and OSEIA, explaining how Fitch evaluates the
financial strength of renewable energy projects. In this report, Fitch
states that it gives a ``stronger'' evaluation to projects with power
sales contract prices that are ``indexed using simple, broad-based
publicly available indexation formulas.'' \43\
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\42\ See American Forest & Paper Association, Comments, Docket
No. AD16-16-000, at 8 (filed June 8, 2016) (``To the extent
possible, these determinations [of avoided costs] should not be made
in a `black box', but rather, as part of an open and transparent
method and process.''); Edison Electric Institute (EEI) Comments,
Docket No. AD16-16-000, at 3 (filed June 30, 2016) (``Where
transparent competitive markets with day ahead prices exist, there
is no reason to adhere to second-best avoided cost pricing
mechanisms.'').
\43\ NIPPC, CREA, REC, and OSEIA Comments at 37-38 (citing
FitchRatings, Global Infrastructure & Project Finance, Renewable
Energy Project Rating Criteria,'' at 3 (Feb. 26, 2019), https://www.fitchratings.com/site/re/10061770).
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31. Setting prices that are indexed using simple, broad-based
publicly available formulas is precisely what the Commission's changes
permitting reference to competitive market prices will achieve. Such
prices reflect avoided costs in a simpler, more transparent, and
predictable manner than through an administrative process, which should
encourage the development of QFs while at the same time providing
benefits to utilities and consumers. Using transparent market prices to
establish as-available avoided cost rates also allows QFs, utilities,
and the states to avoid the expenditure of the time and resources
involved in litigating administratively-set avoided cost rates, and
allows those rates to automatically adjust--up and down--as avoided
costs change.
32. Similarly, the provisions regarding competitive solicitations
adopted herein were added at the suggestion of both NARUC and certain
developers of renewable resource QFs, such as Solar Energy Industries.
These competitive solicitations can provide a fair and transparent
method for QFs to establish full avoided cost rates. As Solar Energy
Industries stated in its comments, ``[c]ompetitive solicitations, with
adequate safeguards, can deliver substantial value.'' \44\ Competitive
solicitations may be an especially appropriate tool in those regions
outside of Regional Transmission Organizations (RTOs) and Independent
System Operators (ISOs) where there are no organized competitive
markets where QFs can make sales.
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\44\ Solar Energy Industries Comments at 38. Solar Energy
Industries agreed that the competitive solicitation provisions
proposed in the NOPR ``set forth many important safeguards,'' but
recommended that additional safeguards be implemented. Those
comments are discussed below, and we have specifically adopted Solar
Energy Industries request made earlier in this proceeding that all
competitive solicitations must be conducted pursuant to the
Commission's Allegheny standard. See Solar Energy Industries
Supplemental Comments, Docket No. AD16-16-000, at 32-34 (filed Aug.
28, 2019).
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33. Likewise, the LEO provisions adopted herein provide important
benefits to QFs. Under the current PURPA Regulations, a LEO gives QFs
the enforceable right to require utilities to purchase the QFs' power
at avoided cost rates.\45\ This is an important right that contributes
to a QF owner's ability to obtain financing, especially the development
financing needed to engage in the activities necessary to subsequently
obtain construction and permanent financing. However, the PURPA
Regulations are silent as to when and how a LEO is established, which
can leave QFs uncertain as to when this key right has been established.
By providing more specific guidance as to when a LEO is established,
the new rule creates greater certainty for QFs (and utilities) on this
important element of QF development.
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\45\ See 18 CFR 292.304(d)(2). Although the final rule gives
states the flexibility to require that energy rates vary over the
term of the LEO and be calculated at the time of delivery, the final
rule retains the QF's option to choose a fixed capacity rate
calculated at the time the LEO is established.
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[[Page 54645]]
34. Some commenters assert that the guidance provided by the
Commission may make it more difficult to obtain a LEO.\46\ Their
specific concerns are discussed in detail below. But what those
commenters ignore is that, by establishing objective and reasonable
state-determined criteria limited to demonstrating commercial viability
and financial commitment, we also are protecting QFs against onerous
requirements for a LEO that hinder financing, such as a requirement for
a utility's execution of an interconnection agreement \47\ or power
purchase agreement,\48\ or requiring that QFs file a formal complaint
with the state commission,\49\ or limiting LEOs to only those QFs
capable of supplying firm power,\50\ or requiring the QF to be able to
deliver power in 90 days.\51\ By making clear in the PURPA Regulations
that such conditions are not permitted, but describing which
prerequisites a state may impose to establish a LEO to determine which
QFs are commercially viable and financially committed, we are providing
objective criteria to clarify when a LEO commences, which we find will
encourage the development of QFs.
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\46\ See NIPPC, CREA, REC, and OSEIA Comments at 81 (``[A]ny
requirement to demonstrate financing to create a LEO violates the
fundamental rule that the utility's actions should not be allowed to
deny the QF a LEO because the utility could prevent creation of a
LEO simply by refusing to sign the PPA needed to secure such
financing.''); Public Interest Organizations Comments at 98 (``[T]he
Commission's proposal to require QFs to demonstrate commercial
viability in order to obtain a LEO will prevent many QFs from ever
attaining commercial viability at all. Creating a new administrative
obstacle to QF financing in this way flies in the face of PURPA's
mandate to reduce barriers to QF development.''); Solar Energy
Industries Comments at 41 (``Establishing higher barriers to a
determination of `commercial viability' will only lead QF developers
to invest additional development capital and will simply weed out
those smaller companies that choose not to, or are unable to, invest
heavily in early-stage development activity before an avoided cost
rate is known. It is unjust and unreasonable to cause QFs to invest
tens of millions of dollars in site control, permit acquisition,
interconnection, and other development costs simply to secure the
opportunity to negotiate with the purchasing utility for a
contractual commitment.''); Southeast Public Interest Organizations
Comments at 41 (describing proposal as ``discourag[ing] QF
development since achieving some of the indicia suggested by the
Commission often circularly requires that QF developers have already
obtained financing'').
\47\ See, e.g., FLS Energy, Inc., 157 FERC ] 61,211, at P 26
(2016) (FLS) (stating that requiring signed interconnection
agreement as prerequisite to LEO is inconsistent with PURPA
Regulations).
\48\ See, e.g., 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 LEO is inconsistent
with PURPA Regulations.
\49\ See, e.g., Grouse Creek Wind Park, LLC, 142 FERC ] 61,187,
at P 40 (2013).
\50\ Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380, 400 (5th
Cir. 2014).
\51\ Power Resource Group, Inc. v. Public Utility Comm'n of
Texas, 422 F.3d 231, (5th Cir. 2005).
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C. The Commission Is Not Eliminating Fixed Rate Pricing for QFs, But
Rather Is Giving States the Flexibility To Require the Same Variable
Energy Rate/Fixed Capacity Rate Construct That Applies Throughout the
Electric Industry
35. Another misconception reflected in several comments is that the
Commission proposed in the NOPR to eliminate fixed rate pricing for
QFs. Commenters argue that QFs cannot obtain financing without fixed
rates, and from this they claim that the proposal to give states the
flexibility to require variable energy rates would have a devastating
effect on future QF development.\52\
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\52\ See, e.g., Public Interest Organizations Comments at 35-38
(allowing variable rates will further discourage wind and solar QF
development); Allco Comments at 9-11 (without the ability to obtain
a fixed long-term forecasted rate, QF solar energy development will
not exist).
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36. This assertion that the Commission has eliminated fixed rates
for QFs is not correct. The NOPR proposal (which we adopt in this final
rule) gave states the flexibility, should they choose to take advantage
of this flexibility, to require that the avoided cost energy rates in
QF contracts must vary depending on avoided costs at the time of
delivery (rather than being fixed at the time a LEO is incurred). The
NOPR thus made clear: ``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.'' \53\ We are retaining in this final rule the option granted
to QFs to fix their capacity rates for the term of their contracts at
the time the LEO is incurred.
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\53\ See NOPR, 168 FERC ] 61,184 at P 66.
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37. The fact that we are giving states the flexibility to either
require QF contracts to have fixed capacity and variable energy rates
or to continue as before to provide QFs the option of fixed capacity
and fixed energy rates--has important consequences for the ability of
QF owners to finance their projects. The energy rates of purchasing
electric utilities, upon which avoided cost energy rates would be
based, typically reflect mainly the variable costs of producing energy,
such as the cost of fuel and variable operations and maintenance (O&M),
especially for a fossil fuel generator. Meanwhile, a purchasing
electric utility's capacity rates, upon which avoided cost capacity
rates would be based, tend to reflect fixed costs, including the
financing costs of facilities (i.e., debt repayment and a return on the
equity invested in the facility).\54\ Consequently, a fixed capacity
rate in a QF contract based on a purchasing electric utility's capacity
rates should typically be sufficient to recover the QF's financing
costs and should therefore continue to facilitate QF financing. We
recognize that a QF's financing costs may be different from the
purchasing electric utility's avoided costs and, therefore, the full
avoided cost rate that the QF receives may not support the financing of
a QF. But this is a consequence of how Congress structured PURPA, which
sets rates based on the avoided costs of the purchasing utility rather
than on the actual costs the QF incurs producing the power being
sold.\55\
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\54\ See Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,865.
\55\ See API, 461 U.S. at 414, 415 (stating that ``Congress did
not intend to impose traditional ratemaking concepts on sales by
qualifying facilities to utilities'' and that QFs ``would retain an
incentive to produce energy under the full-avoided-cost rule so long
as their marginal costs did not exceed the full avoided cost of the
purchasing utility'').
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38. Another important aspect of the variable energy rate/fixed
capacity rate construct is that this is the standard rate structure
used throughout the electric industry for power sales agreements that
include the sale of capacity.\56\ That states will be allowed to
require QF contracts to be structured similarly to the contract
structure used in the rest of the electric industry has important
implications. In particular, this provides flexibility to states to
ensure that the avoided cost rate will be closer to the actual rate the
purchasing electric utility and its customers would have paid if the
purchasing electric utility had generated this electric energy itself
or purchased such electric energy from another source. Furthermore, the
record evidence demonstrating significant amounts of non-QF generation
facilities in operation today shows that the owners of such facilities
are able to obtain financing based on this same variable energy rate/
fixed capacity rate
[[Page 54646]]
construct.\57\ This represents important evidence that QFs likewise
should be able to obtain financing under the same rate construct,
especially considering that QFs benefit from the statutory right to
sell pursuant to a mandatory purchase obligation while non-QFs do not
have that right.\58\
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\56\ Cf. Town of Norwood v. FERC, 962 F.2d 20, 21, 24 (D.C. Cir.
1992) (``The rate design before us, like most wholesale electric
rates, consists of separate monthly demand and energy charges. The
demand component is calculated to recover NEPCO's fixed (or
capacity-related) costs, such as construction and debt service,
which it incurs regardless of how much electricity it produces. The
energy charge is designed to recover the company's variable costs,
which it incurs only in the course of actually producing
electricity; fuel is a prime example. . . . With the cost outlook
constantly in flux due to changing economic conditions, some degree
of volatility is necessary if prices are to signal the market
accurately--as accurately, that is, as current prices can anticipate
future costs. Price volatility alone, therefore, cannot provide a
ground for overturning a marginal cost rate structure.'').
\57\ EIA, Form EIA-860 detailed data with previous form data
Early Release (EIA-860A/860B) (June 2, 2020), https://www.eia.gov/electricity/data/eia860/ shows 77.6 GW of operational QF nameplate
capacity and 450.453.5 GW of operational non-QF independent power
producer nameplate capacity as of end 2019.
\58\ Some commenters raise concerns with the Commission's
reliance on the financing of non-QF generation facilities to support
the conclusion that QFs could obtain financing with variable energy
rate contracts, pointing out that the Commission has not identified
any QFs that have obtained financing under this structure. The
reason for this, however, is that QFs typically do not employ this
structure because currently they are entitled to a fixed energy
rate/fixed capacity rate construct. Accordingly, evidence regarding
the financing of similar types of independently owned generation
projects by non-QFs using such a construct constitutes the best and
most relevant evidence of how it would affect QF financing.
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D. The Rate Changes Implemented by This Final Rule Put QF Rates on the
Same Footing as Electric Utility Rates and Are Not Discriminatory
39. The fact that variable energy rate/fixed capacity rate
contracts are standard in the electric industry also explains why,
contrary to assertions made by a number of commenters, allowing states
to require such contracts for QFs is not discriminatory.\59\ QFs
selling at wholesale pursuant to such contracts will be selling under
the same rate structure employed in the power sales contracts typically
used elsewhere in the electric industry, including by public utilities
when they make sales at wholesale to each other, and QFs will be doing
so at full avoided cost rates--the highest rates permitted under PURPA.
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\59\ See, e.g., EPSA Comments at 9 (``The NOPR avoided rate
proposal must therefore be rejected because it puts QFs at a
disadvantage to utility-owned generation, in violation of the non-
discrimination mandate under PURPA.''); Public Interest
Organizations Comments at 51 (``[L]imiting QFs to contracts
providing no price certainty for energy values, while non-QF
generation regularly obtains fixed price contracts and utility-owned
generation receives guaranteed cost recovery from captive
ratepayers, constitutes discrimination.'').
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40. It is true that electric utilities with franchised service
territories that make sales at retail are often effectively guaranteed
the recovery of their energy costs in their retail rates by their state
regulatory authorities--provided that such costs are prudently
incurred. But the electric utilities' retail rates are cost-based, such
that their rates are set based on costs they actually incur to produce
electricity for their customers. Importantly, moreover, the incremental
energy costs that an electric utility will recover from its retail
customers at an incremental level would be the same energy costs that
are used in determining the electric utilities' avoided costs that
will, in turn, set the as-available avoided cost rates to be charged by
QFs.
41. Thus, QF variable energy rate/fixed capacity rate contracts not
only would be structured similarly to the standard wholesale power
sales agreements used in the electric industry, but application of
traditional cost-based ratemaking principles to sales by QFs is exactly
what would be required in order to provide QFs with the same guaranteed
cost recovery that applies to electric utilities. Guaranteeing QFs cost
recovery is fundamentally inconsistent with PURPA, which sets the rate
the QF is paid at the purchasing electric utility's avoided cost, not
at the QF's cost. Such a rate structure is not discriminatory.
E. The PURPA Compliance Issues Raised by Some Commenters Are Outside
the Scope of This Rulemaking Proceeding
42. Finally, several commenters assert that certain states located
outside of RTO/ISO markets are dominated by large integrated public
utilities whose state commissions do not implement PURPA correctly.\60\
They argue that, as a consequence, there is little development of
independent generation--QFs or otherwise--in those states. They assert
that the proposals in the NOPR might be appropriate in states with RTO/
ISO markets that are subject to significant competition, but would only
make matters worse outside of the RTO/ISO markets.
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\60\ American Dams Comments at 5-6; Biological Diversity
Comments at 13; CA Cogeneration Comments at 6-7; Con Edison Comments
at 2; ELCON Comments at 7-8; EPSA Comments at 1-2; IdaHydro Comments
at 5; NIPPC, CREA, REC, and OSEIA Comments at 14-15; Solar Energy
Industries Comments at 15-20, 24; SC Solar Alliance Comments at 3-4;
Two Dot Wind Comments at 14-19.
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43. As explained above, several changes implemented by this final
rule ensure that the PURPA Regulations will continue to encourage QF
development. Other changes, such as allowing variable energy rates in
QF contracts, not only ensure the PURPA Regulations are consistent with
PURPA but also address some states' primary concern with the current
PURPA Regulations, i.e., the Commission's now allowing states the
flexibility to set variable energy rates could mitigate the states'
reluctance to implement PURPA in a way that better encourages
development of QFs. For example, the Idaho Commission has indicated
that its current policy of limiting QF contracts to two years is based
on its concern about fixed QF rates, and that the ability to require
variable energy rates could lead to longer contract terms.\61\ We
expect that these changes could facilitate QF development in states
where little QF capacity has been added to date.
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\61\ See Idaho Commission Comments at 4 (stating that an energy
rate established at the time of contract formation that provides 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'' would
allow states to consider longer term contracts without putting
ratepayers at risk).
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44. Further, commenters' claims about lack of QF development
outside of the RTO/ISO markets appear to be overstated. For example,
the most recent data from the U.S. Energy Information Administration
(EIA) on the total amount of wind and solar QF capacity in each state
shows that 9 of the 20 states with the greatest combined wind and solar
QF capacity are located outside of the RTO/ISO markets.\62\ Of these 9
states, three are located in the Southeast--the region asserted by
commenters to be the most hostile to PURPA--including North Carolina,
which has the highest total amount of wind and solar QF capacity in the
country.\63\ Other states in the top 20 include Idaho--with the fourth
most wind and solar QF capacity--and Oregon,\64\ two states that have
been criticized as being hostile to PURPA. EIA data also shows that
five of the top 10 states in terms of renewable QF capacity additions
from 2008-17 are located outside of the RTO/ISO markets, including
North Carolina (with the most renewable QF capacity additions), Idaho,
Georgia, and Oregon,\65\ each of
[[Page 54647]]
which commenters have identified as being hostile to PURPA.
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\62\ EIA, Form EIA-860 detailed data with previous form data
(EIA-860A/860B) Release date (June 2, 2020), https://www.eia.gov/electricity/data/eia860/. The top 20 states with combined QF solar
and wind nameplate capacity in 2018 were: (1) California, Texas,
Minnesota, Oklahoma, Massachusetts, New Mexico, Nebraska, New
Jersey, Michigan, New York, Illinois (all fully or partially inside
RTOs/ISOs); and (2) North Carolina, Idaho, Utah, South Carolina,
Georgia, Oregon, Colorado, Arizona, Wyoming(outside of RTOs/ISOs).
We note that some of these states are located in both RTO/ISO and
non-RTO/ISO regions.
\63\ Id. We note that five of the 20 states with the most solar
capacity--perhaps a better measure of the Southeast Region's PURPA
compliance given the lack of wind resources in this region--are
located in the Southeast.
\64\ Id.
\65\ See EIA, PURPA-qualifying capacity increases, but it's
still a small portion of added renewables (Aug. 16, 2018), https://www.eia.gov/todayinenergy/detail.php?id=36912.
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45. But whether any individual state has or has not failed to
implement the PURPA Regulations properly is not an issue for this final
rule, which implements changes to the PURPA Regulations but does not
modify Commission's rules for addressing claims that states are not
complying with the Commission's existing PURPA Regulations. We
promulgate this final rule based on the expectation that the states
will fulfill their legal obligation to implement the Commission's PURPA
Regulations as revised.\66\
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\66\ 16 U.S.C. 824a-3(f)(1). The same obligation to implement
the Commission's PURPA Regulations as revised, we note, is imposed
on nonregulated electric utilities. 16 U.S.C. 824-3(f)(2).
---------------------------------------------------------------------------
46. Further, although Congress required the Commission to establish
the general parameters for establishing QF rates, Congress delegated to
the states--not the Commission--the role to set QF rates.\67\ To the
extent that any entity believes a state is failing to implement the
Commission's PURPA Regulations, PURPA section 210(h) provides that
entity an avenue to seek relief.\68\
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\67\ See 16 U.S.C. 824a-3(f)(1) (``[E]ach State regulatory
authority shall, after notice and opportunity for public hearing,
implement such rule (or revised rule) for each electric utility for
which it has ratemaking authority.'').
\68\ If the Commission, in response to a petition for
enforcement under PURPA section 210(h) against a state regulatory
authority, chooses not to initiate an enforcement action within 60
days of the filing of the petition, the statute authorizes the
petitioning electric utility or QF to itself initiate a suit
directly against the state in U.S. District Court. 16 U.S.C. 824a-
3(h)(2)(B). The same statutory provision similarly governs petitions
for enforcement against nonregulated electric utilities. Id. PURPA
section 210(g) also provides for review of state regulatory
authorities and nonregulated electric utilities in state fora. 16
U.S.C. 824a-3(g). The Commission's policies with respect to PURPA
enforcement are more fully set out in its Policy Statement Regarding
the Commission's Enforcement Role Under Section 210 of the Public
Utility Regulatory Policies Act of 1978, 23 FERC ] 61,304 (1983).
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III. Background
A. Passage of PURPA in 1978 and the Commission's Promulgation of Its
PURPA Regulations in 1980
47. 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
traditional fossil fuels (i.e., oil, natural gas and coal) 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.
48. To accomplish this goal, PURPA section 210(a) directs 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,'' \69\ including rules
requiring electric utilities to offer to sell electricity to, and
purchase electricity from, QFs. PURPA section 210(f) required each
state regulatory authority and nonregulated electric utility (together,
states) to implement the Commission's rules.
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\69\ 16 U.S.C. 824a-3(a).
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49. In 1980, the Commission issued Order Nos. 69 and 70, which
promulgated the required rules that, with limited exceptions, remain in
effect today.\70\ The Commission explained that, at the time of the
passage of PURPA, cogenerators and small power producers faced three
major obstacles: (1) Electric utilities were not required to purchase
these generators' electric output or to make purchases at an
appropriate rate; (2) electric utilities sometimes charged
discriminatorily high rates for backup services; and (3) cogenerators
and small power producers ran the risk of being considered public
utilities themselves and thus being subject to state and federal
regulation as utilities.\71\ Further, at that time, there was no open
access transmission and little competition in electric wholesale
markets. Electric utilities were vertically-integrated and held
dominant market positions. As a result of their control over
transmission access, it was virtually impossible for third parties--
whether independent power producers or other electric utilities--to
compete with them to make sales of electricity.
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\70\ Order No. 69, FERC Stats. & Regs. ] 30,128; 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).
\71\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,863. See
infra P 78 & note 112 (addressing how the PURPA Regulations as
revised continue to address these obstacles).
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50. 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.\72\ The Commission also
directed that electric utilities provide backup electric energy to QFs
on a non-discriminatory basis and at just and reasonable rates,\73\ and
that electric utilities interconnect with QFs.\74\ Pursuant to section
210(e) of PURPA,\75\ the Commission further provided exemptions from
many provisions of the FPA and state laws governing utility rates and
financial organization.\76\
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\72\ 18 CFR 292.304(a)(2); see API, 461 U.S. at 412-18.
\73\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,887-90;
see also 18 CFR 292.305.
\74\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,874; see
also 18 CFR 292.303(c).
\75\ 16 U.S.C. 824a-3(e).
\76\ 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. Circumstances Leading to the Commission's Re-Evaluation of the PURPA
Regulations and the Issuance of the NOPR
51. In the NOPR, the Commission described three important changes
in the circumstances that had originally prompted Congress to pass
PURPA in 1978. First, as the Commission explained, the United States
has seen an unprecedented change in the dynamics of the natural gas
market and the relevant supply and demand.\77\ Led by advancements in
production technologies, primarily in accessing shale reserves, natural
gas supplies increased dramatically.\78\ Further, the EIA forecasted
continued supply growth over the next 25 years.\79\ In short, as the
Commission found in issuing the NOPR, there no longer are shortages of
natural gas supply.
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\77\ NOPR, 168 FERC ] 61,184 at P 19.
\78\ Domestic natural gas production, which appeared to peak in
the early 1970s at 21.7 Tcf per year, increased from 18.1 Tcf in
2005 to 30.4 Tcf in 2018. 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/.
\79\ EIA's forecast showed supplies increasing to nearly 40 Tcf
by 2035 and 43 Tcf by 2050. 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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52. Second, the Commission found that, since 1978, the outlook for
the development of alternatives to natural gas and oil-fired generation
resources, such as renewable resources, has changed equally
dramatically.\80\ The once-nascent renewables industry has grown and
matured over the past 40
[[Page 54648]]
years and has only accelerated subsequent to the Energy Policy Act of
2005's amendment of PURPA. The Commission noted that the cost of
building renewable facilities has decreased substantially to the point
that the cost of renewable resources is now or is shortly expected to
approach the cost of traditional electric generation.\81\ The
Commission also recognized that renewable resources (including hydro)
provide a significant share of the electricity currently generated in
the United States,\82\ that most renewable resources today are not
QFs,\83\ and that 65 percent of capacity additions in 2019 were
expected to come from renewable resources.\84\
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\80\ NOPR, 168 FERC ] 61,184 at P 20.
\81\ Id. (citing EIA, Updated Capital Cost Estimates for Utility
Scale Electricity Generating Plants, https://www.eia.gov/analysis/studies/powerplants/capitalcost/; 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; Lawrence Berkeley National Lab, Wind
Technologies Market Report, https://emp.lbl.gov/wind-technologies-market-report/). However, EIA has cautioned 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.
EIA, Levelized Cost and Levelized Avoided Cost of New Generation
Resources in the Annual Energy Outlook 2019, at 2 (Feb. 2019),
https://www.eia.gov/outlooks/archive/aeo19/pdf/electricity_generation.pdf.
\82\ NOPR, 168 FERC ] 61,184 at P 21 (citing EIA, August 2019
Monthly Energy Review at Figure 7.2a, https://www.eia.gov/totalenergy/data/monthly; Office of Energy Projects, Energy
Infrastructure Update For July 2019 at 4 (July 2019), https://www.ferc.gov/legal/staff-reports/2019/july-energy-infrastructure.pdf).
\83\ NOPR, 168 FERC ] 61,184 at P 22.
\84\ Id. (citing 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).
---------------------------------------------------------------------------
53. 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.\85\ In
addition, RTOs and ISOs have developed competitive wholesale electric
markets that serve roughly two-thirds of electricity consumers in the
United States.\86\
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\85\ NOPR, 168 FERC ] 61,184 at P 25. The Commission cited to
data showing that that net generation of energy by non-utility owned
renewable resources in the United States escalated from 51.7 TWh in
2005 when EPAct 2005 was passed, to 340 TWh in 2018. This also
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 increased from 3.6 TWh in 2005 to 19.5 TWh in 2012, and
to 42.5 TWh in 2018. 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. 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. NOPR, 168 FERC ] 61,184 at P 27 (citing
data taken from EIA's Electricity Data Browser, www.eia.gov/electricity/data/browser (select net generation, other renewables,
independent power producers)).
\86\ ISO/RTO Council, The Role of ISOs and RTOs, https://isorto.org.
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54. In PURPA section 210(a), Congress directed not only that the
Commission prescribe regulations, but that the Commission revise those
regulations ``from time to time thereafter.'' \87\ The Commission
determined in the NOPR that, in light of these dramatic changes in
circumstances since the passage of PURPA, it was appropriate to review
the PURPA Regulations to determine whether changes to those regulations
were warranted consistent with our statutory mandate.\88\
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\87\ 16 U.S.C. 824a-3(a).
\88\ 16 U.S.C. 824a-3(b).
---------------------------------------------------------------------------
55. After identifying these three important changes in the industry
that have taken place since 1980, we further identified evidence
demonstrating that overestimations of avoided cost have not been
balanced by underestimations, and that this trend may persist with the
general decline in the cost of electricity.\89\
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\89\ See NOPR, 168 FERC ] 61,184 at P 30. Evidence submitted in
response to the NOPR shows that, as a result, customers may be
paying more than avoided costs. See infra PP 265 (``Duke Energy
claims that, among the factors contributing to this overpayment of
$2.26 billion for the remainder of these QF contracts, the primary
factor has been the requirement to offer fixed avoided cost energy
rates during a period of rapidly declining energy prices''), 268
(``Massachusetts DPU argues that a 10-year, fixed energy rate based
on current New England wholesale energy market prices is highly
likely to diverge from actual energy market prices over the ten-year
contract term and could significantly harm ratepayers'').
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C. Summary of Changes to the PURPA Regulations Implemented by This
Final Rule
56. We now are revising our PURPA Regulations based on the record
of this proceeding, including comments submitted in the technical
conference in Docket No. AD16-16-000 (Technical Conference),\90\ the
record evidence cited in the NOPR, and the comments submitted in
response to the NOPR. These changes, including modifications to the
proposals made in the NOPR, are summarized below.\91\
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\90\ 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 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.
\91\ In its post-NOPR comments, Bloom Energy requested that the
Commission ``[u]pdate the definition of `useful thermal energy
output' of a topping-cycle cogeneration facility to reflect the
commercialization of solid oxide fuel cells that produce heat for
the industrial purpose of producing hydrogen, a fuel that the fuel
cells use to generate electricity.'' Bloom Energy Comments at 2. We
do not take action on this request in this proceeding because we do
not view this proposal as a logical outgrowth of the NOPR.
---------------------------------------------------------------------------
57. First, we grant states the flexibility to require that energy
rates (but not capacity rates) in QF power sales contracts and other
LEOs \92\ vary in accordance with changes in the purchasing electric
utility's as-available avoided costs at the time the energy is
delivered. Under this change, if a state exercises this flexibility, a
QF no longer would have the ability to elect to have its energy rate be
fixed, but would continue to be entitled to a fixed capacity rate for
the term of the contract or LEO.\93\
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\92\ 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.
\93\ 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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58. Second, we 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.
59. Third, we grant states flexibility to set ``as-available'' QF
energy rates as follows: We are establishing a rebuttal presumption,
rather than a per se rule as proposed in the NOPR, that the LMP
established in the organized electric markets defined in 18 CFR
292.309(e), (f), or (g) represents the as-available avoided costs of
electric utilities located in these markets.\94\ So long as this
[[Page 54649]]
presumption is not rebutted, a state can at its option establish as-
available energy avoided cost rates for QFs selling to such electric
utilities at the LMP. With respect to QFs selling to electric utilities
located outside of the organized electric markets defined in 18 CFR
292.309(e), (f), or (g), states have the option to set as-available
energy avoided cost rates at competitive prices from liquid market hubs
or calculated from a formula based on natural gas price indices and
specified heat rates, provided that the states first determine that
such prices represent the purchasing electric utilities' avoided costs.
The states would have the flexibility to choose to adopt one or more of
these options or to continue setting QF rates under the standards long
established in the PURPA Regulations.
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\94\ These are the markets operated by Midcontinent Independent
System Operator, Inc. (MISO); PJM Interconnection, L.L.C. (PJM); ISO
New England Inc. (ISO-NE); New York Independent System Operator,
Inc. (NYISO); Electric Reliability Council of Texas (ERCOT);
California Independent System Operator, Inc. (CAISO); and Southwest
Power Pool, Inc. (SPP).
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60. Fourth, 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 consistent
with the Commission's Allegheny standard, described in this final rule.
61. Fifth, we do not adopt the proposed rule permitting states with
retail competition to allow relief from the purchase obligation. We
instead clarify in this final rule that the Commission's existing PURPA
Regulations already require that states, to the extent practicable,
must account for reduced loads in setting QF capacity rates.
62. Sixth, we modify the Commission's ``one-mile rule'' for
determining whether generation facilities are considered to be at the
same site for purposes of determining qualification as a qualifying
small power production facility. Specifically, we allow electric
utilities, state regulatory authorities, and other interested parties
to show that affiliated small power production facilities that use the
same energy resource and are more than one mile apart and less than 10
miles apart actually are at the same site (with distances one mile or
less apart still irrebuttably at the same site, and distances 10 miles
or more apart irrebuttably at separate sites). We also allow a small
power production facility seeking QF status to provide further
information in its certification (whether a self-certification or an
application for Commission certification) or recertification (whether a
self-recertification or an application for Commission recertification)
to defend preemptively against subsequent challenges, by identifying
factors affirmatively demonstrating that its facility is indeed at a
separate site from other affiliated small power production qualifying
facilities. We further add a definition of the term ``electrical
generating equipment'' to the PURPA Regulations to clarify how the
distance between facilities is to be calculated.
63. Seventh, we allow an entity to challenge an initial self-
certification or self-recertification without being required to file a
separate petition for declaratory order and to pay the associated
filing fee. However, we clarify in this final rule that such protests
may be made to new certifications (both self-certifications and
applications for Commission certification) but to only self-
recertifications and applications for Commission recertifications
making substantive changes to the existing certification.
64. Eighth, we revise the Commission's 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. We update the rebuttable
presumption for small power production facilities (but not cogeneration
facilities) from 20 MW to 5 MW and, in this final rule, revise the
regulations to include examples of factors, among others, that QFs may
argue show that they lack nondiscriminatory access to such markets.
65. Finally, we clarify that a QF must demonstrate commercial
viability and a financial commitment to construct its facility pursuant
to objective and reasonable state-determined criteria before the QF is
entitled to a contract or LEO. States may not impose any requirements
for a LEO other than a showing of commercial viability and a financial
commitment to construct the facility. We also clarify in this final
rule that, to the extent that the permitting factor is relied upon, a
QF need only show that it has applied for all required permits and paid
all applicable fees, and not that it has obtained such permits.
66. As explained in detail in the relevant sections below, these
changes will enable the Commission to continue to fulfill its statutory
obligations under sections 201 and 210 of PURPA. We emphasize that
these changes are effective prospectively for new contracts or LEOs and
for new facility certifications and recertifications filed on or after
the effective date of this final rule; we do not by this final rule
permit disturbance of existing contracts or LEOs or existing facility
certifications.
IV. Discussion
A. General Legal Standards Under PURPA
67. Several comments were submitted regarding: (1) The requirement
in PURPA section 210(a) that ``the Commission shall prescribe, and from
time to time thereafter revise, such rules as it determines necessary
to encourage cogeneration and small power production''; and (2) the
requirement in PURPA section 210(b) that rates paid by purchasing
utilities to QFs ``shall not discriminate against qualifying
cogenerators or qualifying small power producers.'' \95\ In addition, a
claim was made that the Commission has unlawfully delegated its
authority to the states. These comments apply to several of the
revisions implemented by this final rule and therefore are discussed
prior to the discussion of specific revisions implemented herein.
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\95\ 16 U.S.C. 824a-3(a), (b).
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1. Encouragement of QFs
a. Comments
68. Commenters make two general arguments regarding the statutory
requirement that the Commission's PURPA Regulations should encourage
QFs. First, they note that the statutory requirement that the PURPA
Regulations encourage QFs is mandatory and that the Commission has no
discretion to determine that such encouragement no longer is necessary.
Harvard Electricity Law states that ``Congress'[s] mandate to encourage
QFs is not contingent on industry conditions and does not expire.''
\96\ Further, they assert, ``[t]he Commission may not overwrite
Congress's instruction to issue rules that it `determines necessary to
encourage cogeneration and small power production.' '' \97\ Public
Interest Organizations similarly object to the NOPR as violating the
encouragement requirement because, they assert, the NOPR ``reflect[s] a
belief that the current rules support too much QF development and a
desire to reduce the incentives in current rules for QF development.''
\98\ NIPPC, CREA, REC, and OSEIA assert that ``[t]he Commission cannot
take it
[[Page 54650]]
upon itself to change the underlying policy directives to encourage
QFs.'' \99\
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\96\ Harvard Electricity Law Comments at 1.
\97\ Id. at 4 (quoting PURPA section 210(a)).
\98\ Public Interest Organizations Comments at 10.
\99\ NIPPC, CREA, REC, and OSEIA Comments at 29.
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69. Public Interest Organizations advance a second general argument
based on the encouragement requirement, arguing that ``[t]o amend the
rules, the Commission must first determine that the actual changes it
proposes increase development and utilization of QFs.'' \100\
Similarly, Allco attacks the NOPR on the grounds that ``the proposed
changes do not encourage QF generation.'' \101\
---------------------------------------------------------------------------
\100\ Public Interest Organizations Comments at 11.
\101\ Allco Comments at 8.
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b. Commission Determination
70. We agree with commenters that PURPA does not provide discretion
to the Commission to determine whether QFs should be encouraged. That
is a determination left to Congress, and we have not premised this
final rule on a belief that QFs should not be encouraged. However, the
requirement that the Commission promulgate regulations necessary to
encourage QFs is not unbounded. Instead, as noted briefly earlier,
there are statutory limitations on the extent that the PURPA
Regulations can encourage QFs.
71. First, PURPA section 210(b) sets out standards with which the
Commission must comply in setting QF rates. The last sentence of PURPA
section 210(b) sets out an upper limit on such rates. ``No such rule
prescribed under subsection (a) shall provide for a rate which exceeds
the incremental cost to the electric utility of alternative electric
energy.'' \102\
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\102\ Furthermore, PURPA section 210(b)(1) requires that QF
rates be ``just and reasonable to the electric consumers of the
electric utility and in the public interest.'' 16 U.S.C. 824a-
3(b)(1). Although the exact scope of the ``just and reasonable to
the electric consumers'' criterion has never been addressed
explicitly, the Supreme Court held in API that the requirement in
the PURPA Regulations that QF rates be set at full avoided costs
does not violate this criterion. API, 461 U.S. at 415-16. This
``just and reasonable to the electric consumers'' criterion likely
would be violated if the Commission were to allow a rate above the
purchasing electric utility's avoided costs.
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72. If there were any doubt from the statutory language that
incremental costs (avoided costs) are intended to be a hard cap on QF
rates, such doubt is dispelled by the Conference Report to PURPA, which
provided: ``This limitation on the rates which may be required in
purchasing from a cogenerator or small power producer is meant to act
as an upper limit on the price at which utilities can be required under
this section to purchase electric energy.'' \103\ The Conference Report
also described the reason for the avoided cost cap on QF rates. ``The
provisions of this section are not intended to require the rate payers
of a utility to subsidize cogenerators or small power produc[er]s.''
\104\
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\103\ Conf. Rep. at 98 (emphasis added).
\104\ Id. (emphasis added).
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73. Therefore, PURPA section 210(b) imposes an important limit on
the Commission's ability to encourage QFs by imposing an upper boundary
on the rates at which QFs may require electric utilities to purchase
their electric energy. The Commission cannot require QF rates that
exceed the avoided costs of the purchasing electric utility.\105\
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\105\ 16 U.S.C. 824a-3(b)(1).
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74. Second, another way in which Congress limited the Commission's
ability to encourage QFs was to define small power production
facilities, the PURPA category applicable to almost all renewable
resources that wish to be QFs, as having ``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.''
\106\ The statutory 80 MW limitation, as well as any definition of
``the same site'' that may be established by the Commission, will of
necessity have an effect on the encouragement of QFs, because it will
limit the capacity of QFs both ab initio and also for those located at
the same site to 80 MW.
---------------------------------------------------------------------------
\106\ 16 U.S.C. 796(17)(A)(ii).
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75. Third, Congress amended PURPA section 210 to add section
210(m), which 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 has nondiscriminatory access to certain defined
types of markets.\107\ We interpret this amendment as reflecting
Congress's judgment that these markets provide adequate encouragement
for those QFs having nondiscriminatory access to such markets. To the
extent that a party asserts that the termination of the purchase
obligation for QFs with nondiscriminatory access to these markets
discourages QFs, that party's argument is not with the Commission, but
rather with Congress. PURPA section 210(m) obligates the Commission to
grant any request to terminate a utility's obligation to purchase from
a QF with nondiscriminatory access to the specified markets.\108\
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\107\ See 16 U.S.C. 824a-3(m).
\108\ Id. (``[N]o electric utility shall be required to enter
into a new contract or obligation to purchase electric energy from a
[QF] if the Commission finds that the [QF] has nondiscriminatory
access to [specified markets].'').
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76. Finally, we disagree with any suggestion that a rule originally
adopted in 1980 cannot be changed once adopted, or that our revised
regulations cannot be different in how they encourage QFs than the
regulations the Commission issued in 1980.\109\ For one thing, as
explained above, PURPA itself includes certain limitations on the
Commission's ability to encourage QFs, and a provision in the final
rule intended to comply with these statutory limitations cannot be
found to violate PURPA even if such a provision individually does not
affirmatively encourage QFs to the same degree now as in 1980. As
explained herein, we do not seek, through this final rule, to cease
encouraging the development of QFs. Instead, this final rule is
intended to ensure that the Commission is compliant with the statute in
how it does encourage the development of QFs. In doing so, the
Commission may end up encouraging QF development differently from the
current PURPA Regulations, but the Commission's regulations continue to
encourage QF development, as contemplated by PURPA.
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\109\ See 18 U.S.C. 824a-3(a).
---------------------------------------------------------------------------
77. Many of the commenters' assertions seem to be based on a
reading of the statute that requires that every individual change made
to the PURPA Regulations in isolation must individually encourage QFs
notwithstanding the statute's provisions. But, as discussed above,
Congress established boundaries in PURPA that must be considered, such
as the ``cap'' on incremental costs; just and reasonable rates for
electric customers; the 80 MW limit; and whether QFs have
nondiscriminatory access to markets. Furthermore, the statutory
requirement to encourage QF development applies to the PURPA
Regulations--``such rules as [the Commission] determines necessary''--
as a whole.\110\
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\110\ See 16 U.S.C. 824a-3(a) (emphasis added).
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78. In that regard, we find that the Commission's PURPA Regulations
as a whole when modified by this final rule continue to encourage the
development of QFs, consistent with PURPA. The PURPA Regulations in
particular, continue to require that QF rates be set at full avoided
costs, a provision the Supreme Court described as ``provid[ing] the
maximum incentive for the development of cogeneration and small power
production.'' \111\ In addition, this final rule retains provisions of
the PURPA Regulations adopted in 1980 that provide encouragement
through other means
[[Page 54651]]
recognized by the Supreme Court in FERC v. Miss.\112\ (e.g., certain
regulatory relief,\113\ interconnection provisions,\114\ and
requirements that utilities sell power to QFs that will enable QFs to
continue operations).\115\ Moreover, several of the changes implemented
by this final rule also provide additional encouragement for QFs as
described in more detail below.
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\111\ API, 461 U.S. at 418.
\112\ 456 U.S. 742, 750-51 (1982) (holding that Congress ``felt
that two problems impeded the development of nontraditional
generating facilities: (1) Traditional electricity utilities were
reluctant to purchase power from, and to sell power to, the
nontraditional facilities, and (2) the regulation of these
alternative energy sources by state and federal utility authorities
imposed financial burdens upon the nontraditional facilities and
thus discouraged their development'' (internal citations omitted)).
\113\ 18 CFR 292.601-02.
\114\ 18 CFR 292.303(c).
\115\ 18 CFR 292.305.
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2. Discrimination
a. Comments
79. Commenters opposing the proposals in the NOPR also cite to the
statutory requirement in PURPA section 210(b)(1) that QF rates ``shall
not discriminate against'' QFs. EPSA asserts that ``[n]otably, this
standard is more restrictive than the [FPA's] prohibition against
`unduly discriminatory' rates.'' \116\ Public Interest Organizations
state that ``[i]n other statutes, prohibiting price discrimination
without the modifiers `unreasonable' or `undue,' means any difference
in price for the same commodity.'' \117\
---------------------------------------------------------------------------
\116\ EPSA Comments at 8.
\117\ Public Interest Organizations Comments at 47 (citing FTC
v. Anheuser-Busch, Inc., 363 U.S. 536, 549 (1960)).
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80. In discussing the requirement that QF rates not be
discriminatory, some commenters compare the treatment afforded to QFs
under the NOPR with the rate treatment applicable to public utilities.
For example, NIPPC, CREA, REC, and OSEIA point out that ``[u]tilities
can rate-base long-term investments, thereby ensuring that they can
recover their capital investments plus an authorized return, and then
also recover their actual operating costs under traditional cost-of-
service ratemaking.'' \118\ By contrast, Harvard Electricity Law
asserts, ``QFs do not have the same ability that the electric utilities
have to `rate base' their facilities and, thereby, guarantee capital
recovery.'' \119\
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\118\ NIPPC, CREA, REC, and OSEIA Comments at 36; see also
IdaHydro Comments at 11; Industrial Energy Consumers Comments at 12-
13; SC Solar Alliance Comments at 5-10; Solar Energy Industries
Comments at 33, 36-38.
\119\ Harvard Electricity Law Comments at 28.
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81. Based on this difference between utilities and QFs, commenters
allege that certain aspects of the NOPR are discriminatory, including
those provisions of the NOPR regarding the use of LMPs and other
competitive rates to set as-available energy rates,\120\ to allow for
variable energy rates in QF contracts,\121\ and to allow avoided costs
to be set through competitive solicitations (i.e., requests for
proposals (RFPs)).\122\
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\120\ See, e.g., Public Interest Organizations Comments at 64
(stating that the use of competitive prices to set as-available
energy avoided cost rates is discriminatory because non-QF
generators are not limited to competitive prices and utilities can,
and regularly do, pay effective prices for energy that exceed the
price determined by competitive prices).
\121\ See, e.g., EPSA Comments at 9 (``The NOPR avoided rate
proposal must therefore be rejected because it puts QFs at a
disadvantage to utility-owned generation, in violation of the non-
discrimination mandate under PURPA.''); Public Interest
Organizations Comments at 51 (``[L]imiting QFs to contracts
providing no price certainty for energy values, while non-QF
generation regularly obtains fixed price contracts and utility-owned
generation receives guaranteed cost recovery from captive
ratepayers, constitutes discrimination.'').
\122\ See, e.g., Allco Comments at 12 (stating that allowing a
state commission to use a competitive solicitation price is simply
giving another tool to a state commission to kill QF projects).
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b. Commission Determination
82. As an initial matter, we agree with EPSA that the statutory
requirement in PURPA section 210(b)(1) that QF rates ``shall not
discriminate against'' QFs is more restrictive than the FPA's
prohibition against 'unduly discriminatory' rates.\123\ However, the
avoided cost cap on QF rates that limits the Commission's ability to
encourage QFs, discussed above, also applies to the Commission's
ability to address these claims of discrimination under PURPA. PURPA
section 210(b) makes clear that ``[n]o such rule prescribed under
subsection (a) shall provide for a rate which exceeds the incremental
cost to the electric utility of alternative electric energy.'' \124\
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\123\ EPSA Comments at 8.
\124\ Furthermore, as noted above, PURPA section 210(b)(1)
requires that QF rates also be ``just and reasonable to the electric
consumers of the electric utility and in the public interest.'' See
supra note 102.
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83. We are retaining in this final rule the requirement that QF
rates be set at a purchasing utility's full avoided costs. The Supreme
Court held in API that ``the full-avoided-cost rule plainly satisfies
the nondiscrimination requirement.'' \125\ Although the Court did not
provide a detailed explanation for this holding, the reasoning is
apparent. If the purchasing utility is paying the same rate to a QF for
power that it otherwise would have paid for incremental power, by
definition such a rate could not be discriminatory. But even if it were
possible to posit a situation where the payment of a full avoided cost
rate to a QF somehow were discriminatory, the Commission nevertheless
would be prohibited by PURPA section 210(b) from requiring a rate to be
paid to the QF that is above the full avoided costs of the purchasing
electric utility.
---------------------------------------------------------------------------
\125\ API, 461 U.S. at 413.
---------------------------------------------------------------------------
84. For the same reasons, Public Interest Organizations are
mistaken when they assert that, without the modifiers ``unreasonable''
or ``undue,'' any difference in price for the same commodity violates
PURPA.\126\ So long as a QF's rate is set at the purchasing utility's
full avoided cost, the QF's rate should be the same as the rate the
purchasing utility otherwise would be paying or the cost it would be
incurring, and such a rate would not be discriminatory. And, in any
event, as noted above, the Commission cannot require a rate that is any
higher.
---------------------------------------------------------------------------
\126\ Public Interest Organizations Comments at 47 (citing FTC
v. Anheuser-Busch, Inc., 363 U.S. at 549).
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85. With respect to comparisons between QFs, with no guarantee of
cost recovery, and electric utilities, which if they have a franchised
service territory and sell at retail in that territory are effectively
guaranteed the opportunity to seek to recover prudently-incurred costs
in their retail rates, we observe that Congress acknowledged this
difference when enacting PURPA. As emphasized in the PURPA Conference
Report:
The conferees recognize that cogenerators and small power
producers are different from electric utilities, not being
guaranteed a rate of return on their activities generally or on the
activities vis a vis the sale of power to the utility and whose risk
in proceeding forward in the cogeneration or small power production
enterprise is not guaranteed to be recoverable.\127\
---------------------------------------------------------------------------
\127\ Conf. Rep. at 97-98 (emphasis added).
86. In recognizing this difference and yet not seeking to eliminate
it, Congress also made clear its intent not to treat QFs like electric
---------------------------------------------------------------------------
utilities in this regard:
It is not the intention of the conferees that [QFs] become
subject . . . to the type of examination that is traditionally given
to electric utility rate applications to determine what is the just
and reasonable rate that they should receive for their electric
power.\128\
---------------------------------------------------------------------------
\128\ Id. at 97.
87. Based on this legislative history, the Supreme Court concluded
in API that, ``Congress did not intend to impose traditional ratemaking
concepts on sales by qualifying facilities to utilities.'' \129\ But
application of traditional cost-based ratemaking principles to sales by
QFs is
[[Page 54652]]
exactly what would be required in order to provide QFs with the same
guaranteed cost recovery that applies to electric utilities. Also,
guaranteeing QFs cost recovery is fundamentally inconsistent with
PURPA, which sets the rate the QF is paid at the utility's avoided
cost, not at the QF's cost.
---------------------------------------------------------------------------
\129\ API, 461 U.S. at 414.
---------------------------------------------------------------------------
88. It therefore is clear that Congress did not intend for the
PURPA nondiscrimination criterion to require that QF rates be set in a
way that guarantees recovery of a QF's own costs, even as Congress
recognized that franchised electric utilities selling at retail
typically do have such guarantees for their own costs. Congress thus
withheld from the Commission the authority to provide to QFs the same
opportunity to recover costs at retail that franchised electric
utilities have to recover their costs at retail; it was done by
Congress intentionally and cannot be impermissibly discriminatory.\130\
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\130\ See 16 U.S.C. 824a-3(a) (rules Commission is directed to
prescribe ``may not authorize a [QF] to make any sale for purposes
other than resale'').
---------------------------------------------------------------------------
3. Unlawful Delegation and the Role of Nonregulated Electric Utilities
a. Comments
89. Allco argues that PURPA section 210(f) requires states to
``implement'' the Commission's rules, and that those rules cannot
redelegate the Commission's authority. Allco claims that the statutory
requirement to implement the Commission's rules cannot simply be a
fa[ccedil]ade for delegating broad authority to states to undercut
PURPA's directive that QF small power production must be encouraged.
Allco concludes that Congress intended for the Commission to adopt
actual rules rather than ``a menu of factors'' that essentially leaves
states with all the discretion as to what to implement in order to
encourage QF generation.\131\
---------------------------------------------------------------------------
\131\ Allco Comments at 39-40.
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90. Allco also asserts that the NOPR's proposed delegation of
authority to nonregulated electric utilities is an unconstitutional
delegation. According to Allco, such a delegation would mean that
nonregulated electric utilities (some of which are among the largest
utilities in the United States) were regulating themselves. Allco
argues that a private entity such as a nonregulated electric utility
cannot constitutionally be delegated regulatory power.\132\
---------------------------------------------------------------------------
\132\ Id. at 40 (citing Ass'n of Am. R.R. v. DOT, 721 F.3d 666,
677 (D.C. Cir. 2013), vacated on other grounds, 135 S. Ct. 1225
(2015)).
---------------------------------------------------------------------------
91. Nebraska Board states that there is no state agency in Nebraska
that has ratemaking authority over retail electric suppliers and that
all retail electric suppliers are consumer-owned. Nebraska Board states
its understanding that each retail electric supplier in Nebraska would
have jurisdiction to exercise flexibilities provided to states in the
NOPR.
92. Public Interest Organizations argue that the Commission failed
to comply with PURPA section 210's requirement to consult with federal
and state regulatory agencies with ratemaking authority.\133\
---------------------------------------------------------------------------
\133\ Public Interest Organizations Comments at 19 (citing 16
U.S.C. 824a-3(a)).
---------------------------------------------------------------------------
b. Commission Determination
93. Allco's unlawful delegation claims are misplaced. By enacting
PURPA section 210(f)(1), Congress delegated to the states the
obligation to implement the Commission's PURPA rules, and the
Commission is acting consistent with that delegation. Congress's
delegation to the states was upheld in FERC v. Miss.\134\ and we are
ensuring that the rules we have imposed abide by all the terms of the
statute. Further, the Commission's current PURPA Regulations,
promulgated in 1980, set forth a list of factors that the states are to
consider, ``to the extent practicable,'' in setting QF rates.\135\ In
so doing, the Commission 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 18 CFR
292.304].'' \136\ This final rule adds factors that must be taken into
account to the extent practicable in setting rates, while retaining the
``great latitude'' the states always have had to implement the PURPA
Regulations and which have been an important feature of the
Commission's PURPA Regulations since their inception.
---------------------------------------------------------------------------
\134\ 456 U.S. at 760 (``FERC has declared that state
commissions may implement this by, among other things, `an
undertaking to resolve disputes between qualifying facilities and
electric utilities arising under [PURPA].' '').
\135\ 18 CFR 292.304(e).
\136\ 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.
---------------------------------------------------------------------------
94. With respect to Allco's claim that the NOPR proposed an
unconstitutional delegation to nonregulated electric utilities, we note
that PURPA section 210(f)(2) specifically provides that ``each
nonregulated electric utility shall, after notice and opportunity for
public hearing, implement'' the Commission's rules regarding the rates
to be paid to QFs. Consistent with this statutory provision, the PURPA
Regulations regarding the setting of QF rates have applied to
nonregulated electric utilities since those regulations were
promulgated in 1980.\137\ The final rule does nothing more than
continue to implement this statutory requirement in the same way it
always has been implemented. Given PURPA's unique statutory scheme
involving state regulatory authorities, nonregulated electric
utilities, QFs, and the Commission, we therefore reject Allco's
assertion that the rules proposed in the NOPR--and adopted in this
final rule--establish an unconstitutional delegation of authority to a
private entity.\138\ And it is beyond the Commission's purview to
consider whether this statutory grant is constitutional.\139\
Accordingly, when we refer to states in this final rule, we usually are
referring to both state regulatory authorities and nonregulated
electric utilities.
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\137\ See Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,864
(``The implementation of these rules is reserved to the State
regulatory authorities and nonregulated electric utilities.'').
\138\ See Allco Comments at 40.
\139\ Finnerty v. Cowen, 508 F.2d 979, 982 (2d Cir. 1974)
(explaining that administrative agencies ``have neither the power
nor the competence to pass on the constitutionality of
administrative or legislative action'') (quoting Murray v. Vaughn,
300 F. Supp. 688, 695 (D. R.I. 1969)); see also Gibas v. Saginaw
Mining Co., 748 F.2d 1112, 1117 (6th Cir. 1984) (``[A]dministrative
bodies like the Board do not have the authority to adjudicate the
validity of legislation which they are charged with
administering.''); Spiegel, Inc. v. FTC, 540 F.2d 287, 294 (7th Cir.
1976) (finding that the federal agency erred by making a
constitutional determination); Downen v. Warner, 481 F.2d 642, 643
(9th Cir. 1973) (``Resolving a claim founded solely upon a
constitutional right is singularly suited to a judicial forum and
clearly inappropriate to an administrative board.''); cf. Woodrow v.
FERC, 2020 WL 2198050, at *9 (D.D.C. May 6, 2020) (``When Congress
creates an intricate statutory-review process that incorporates
agency consideration and ultimately an avenue to petition an Article
III court, we assume it wants that scheme to control.'').
---------------------------------------------------------------------------
95. Regarding Public Interest Organizations assertion that the
Commission failed to comply with PURPA section 210's requirement to
consult with federal and state regulatory agencies with ratemaking
authority, we find that the 2016 Technical Conference's invitation to
the public (including state regulatory authorities) to speak, as well
as the notice and comment process on the NOPR itself, encompasses the
required consultation.\140\ The notices soliciting
[[Page 54653]]
comments were open to all state authorities. Indeed, since the
Commission first announced that technical conference and up to our
receipt of comments on the NOPR, representatives from several states
have filed comments expressing their views on how the Commission should
implement PURPA.
---------------------------------------------------------------------------
\140\ See Notice Inviting Post-Technical Conference Comments,
Implementation Issues Under the Public Utility Regulatory Policies
Act of 1978, Docket No. AD16-16-000 (Sept. 6, 2016); Supplemental
Notice of Technical Conference, Implementation Issues Under the
Public Utility Regulatory Policies Act of 1978, Docket No. AD16-16-
000 (Mar. 4, 2016) (announcing preliminary agenda and inviting
interested speakers).
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B. QF Rates
1. Overview
96. PURPA requires that the Commission promulgate rules, to be
implemented by the states,\141\ that ``shall insure'' that the rates
electric utilities pay for purchases of electric energy from QFs meet
the statutory criteria described above, including that ``[n]o such rule
. . . shall provide for a rate which exceeds'' the purchasing utility's
``incremental cost . . . of alternative electric energy.'' \142\ Under
PURPA, such rates must: (1) Be just and reasonable to the electric
consumers of the electric utility and in the public interest; (2) not
discriminate against qualifying cogenerators or qualifying small power
producers; \143\ and, as noted above, (3) not exceed ``the incremental
cost to the electric utility of alternative electric energy,'' \144\
which is ``the cost to the electric utility of the electric energy
which, but for the purchase from such cogenerator or small power
producer, such utility would generate or purchase from another
source.'' \145\ The ``incremental cost to the electric utility of
alternative electric energy'' referred to in prong (3) above, which
sets out a statutory upper bound on a QF rate, has been consistently
referred to by the Commission and industry by the short-hand phrase
``avoided cost,'' \146\ although the term ``avoided cost'' itself does
not appear in PURPA.
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\141\ Nonregulated electric utilities implement the requirements
of PURPA with respect to themselves. An electric utility that is
``nonregulated'' is any electric utility other than a ``state
regulated electric utility.'' 16 U.S.C. 2602(9). The term ``state
regulated electric utility,'' in contrast, means any electric
utility with respect to which a state regulatory authority has
ratemaking authority. 16 U.S.C. 2602(18). The term ``state
regulatory authority,'' as relevant here, means a state agency which
has ratemaking authority with respect to the sale of electric energy
by an electric utility. 16 U.S.C. 2602(17).
\142\ 16 U.S.C. 824a-3(b).
\143\ 16 U.S.C. 824a-3(b)(1)-(2).
\144\ 16 U.S.C. 824a-3(b).
\145\ 16 U.S.C. 824a-3(d) (emphasis added).
\146\ See 18 CFR 292.101(b)(6) (defining avoided costs in
relation to the statutory terms); see also Order No. 69, FERC Stats.
& Regs. ] 30,128 at 30,865 (``This definition is derived from the
concept of `the incremental cost to the electric utility of
alternative electric energy' set forth in section 210(d) of PURPA.
It includes both the fixed and the running costs on an electric
utility system which can be avoided by obtaining energy or capacity
from qualifying facilities.'').
---------------------------------------------------------------------------
97. In addition, the PURPA Regulations currently provide a QF two
options for how to sell its power to an electric utility. The QF may
choose to sell as much of its energy as it chooses when the energy
becomes available, with the rate for the sale calculated at the time of
delivery (frequently referred to as a so-called ``as-available'' sale
and rate).\147\ Alternatively, the QF may choose to sell pursuant to a
legally enforceable obligation or LEO (such as a contract) over a
specified term.\148\
---------------------------------------------------------------------------
\147\ 18 CFR 292.304(d)(1).
\148\ 18 CFR 292.304(d)(2)(i)-(ii); see also FLS, 157 FERC ]
61,211 at P 21 (citing 18 CFR 292.304(d)). The LEO or contract is
frequently referred to as a long-term transaction, when contrasted
with an ``as available'' sale and rate.
---------------------------------------------------------------------------
98. If the QF chooses to sell under the second option, the PURPA
Regulations then provide the QF the further option of receiving, in
terms of pricing, either: (1) The purchasing electric utility's avoided
cost calculated at the time of delivery; \149\ or (2) the purchasing
electric utility's avoided cost calculated and fixed at the time the
LEO is incurred.\150\
---------------------------------------------------------------------------
\149\ 18 CFR 292.304(d)(2)(i).
\150\ 18 CFR 292.304(d)(2)(ii). Rates calculated at the time of
a LEO (for example, a contract) do not violate the requirement that
the rates not exceed avoided costs if they differ from avoided costs
at the time of delivery. 18 CFR 292.304(b)(5).
---------------------------------------------------------------------------
99. In implementing the PURPA Regulations, the Commission
recognized that a contract with avoided costs calculated at the time a
LEO is incurred could exceed the electric utility's avoided costs at
the time of delivery in the future, thereby seemingly violating PURPA's
requirement that QFs not be paid more than an electric utility's
avoided costs. But the Commission believed that the fixed avoided cost
rate might also turn out to be lower than the electric utility's
avoided costs over the course of the contract and that, ``in the long
run, 'overestimations' and `underestimations' of avoided costs will
balance out.'' \151\ The Commission's justification for allowing QFs to
fix their rate at the time of the LEO for the entire life of the
contract was that fixing the rate provides ``certainty with regard to
return on investment in new technologies.'' \152\
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\151\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,880. See
also 18 CFR 292.304(b)(5) (``In the case in which the rates for
purchases are based upon estimates of avoided costs over the
specific term of the contract or other legally enforceable
obligation, the rates for such purchases do not violate this subpart
if the rates for such purchases differ from avoided costs at the
time of delivery.''); Entergy Servs., Inc., 137 FERC ] 61,199, at P
56 (2011) (``Many avoided cost rates are calculated on an average or
composite basis, and already reflect the variations in the value of
the purchase in the lower overall rate. In such circumstances, the
utility is already compensated, through the lower rate it generally
pays for unscheduled QF energy, for any periods during which it
purchases unscheduled QF energy even though that energy's value is
lower than the true avoided cost.'').
\152\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,880.
---------------------------------------------------------------------------
100. In the NOPR, the Commission proposed to revise its PURPA
Regulations to permit states to incorporate competitive market forces
in setting QF rates. Specifically, the Commission proposed to revise
its PURPA Regulations with regard to QF rates to provide states with
the flexibility to:
Require that ``as-available'' QF energy rates paid by
electric utilities located in RTO/ISO markets be based on the market's
LMP, or similar energy price derived by the market, in effect at the
time the energy is delivered.
require that ``as-available'' QF energy rates paid by
electric utilities located outside of RTO/ISO markets be based on
competitive prices determined by: (1) liquid market hub energy prices;
or (2) formula rates based on observed natural gas prices and a
specified heat rate.
require that energy rates under QF contracts and LEOs be
based on as-available energy rates determined at the time of delivery
rather than being fixed for the term of the contract or LEO.
implement an alternative approach of requiring that the
fixed energy rate be calculated based on estimates of the present value
of the stream of revenue flows of future LMPs or other acceptable as-
available energy rates at the time of delivery.
require that energy and/or capacity rates be determined
through a competitive solicitation process, such as an RFP, with
processes designed to ensure that the competitive solicitation is
performed in a transparent, non-discriminatory fashion.\153\
---------------------------------------------------------------------------
\153\ NOPR, 168 FERC ] 61,184 at PP 32-33.
---------------------------------------------------------------------------
101. Although the Commission proposed to modify how the states are
permitted to calculate avoided costs, it did not propose to terminate
the requirement that the states continue to calculate, and to set QF
rates at, such avoided costs.
102. We adopt these proposals in this final rule, with certain
modifications. Each such proposal, and our final determination, is
discussed further below.
2. Use of Competitive Market Prices To Set As-Available Avoided Cost
Rates
103. In addition to commenting on the specific methods for
determining as-available avoided cost rates, several
[[Page 54654]]
commenters addressed more generally the Commission's proposal in the
NOPR that states be given the flexibility to use competitive market
prices to set such rates. Before discussing the specific methods
proposed in the NOPR, we first discuss the determination that the use
of competitive market prices, however determined, can be an appropriate
approach to determining as-available avoided cost rates.
a. NOPR Proposal
104. In the NOPR, the Commission proposed to give the states the
flexibility to use competitive market prices to set as-available
avoided cost rates. The Commission stated its belief that consideration
of transparent, competitive market prices in appropriate circumstances
would help to identify an electric utility's avoided costs in a
simpler, more transparent, and more predictable manner that would, in
conjunction with the Commission's other existing and proposed PURPA
Regulations, act to encourage QFs.\154\
---------------------------------------------------------------------------
\154\ Id. P 13.
---------------------------------------------------------------------------
105. For those utilities located in RTO/ISO markets, the NOPR
identified LMP as a competitive market price that states could choose
to adopt as representing an as-available avoided energy cost. The
Commission explained that LMP could provide an accurate measure of the
varying actual avoided costs for each receipt point on an electric
utility's system where the utility receives power from QFs.\155\ In
addition to these benefits, the Commission observed that LMPs, in
contrast to the administrative pricing methodologies used to set as-
available QF rates by many states, could promote the more efficient use
of the transmission grid, promote the use of the lowest-cost
generation, and provide for transparent price signals.\156\
---------------------------------------------------------------------------
\155\ Id. P 45.
\156\ Id. P 48 (citing Cal. Indep. Sys. Operator Corp., 105 FERC
] 61,140, at PP 48-50 (2003); Cf. Price Formation in Energy and
Ancillary Servs. Mkts Operated by Reg'l Transmission Orgs. and
Indep. Sys. Operators, 153 FERC ] 61,221, at P 2 (2015)).
---------------------------------------------------------------------------
106. For utilities located outside of RTO/ISO markets, the NOPR
proposed to allow states to use two other potential competitively
priced measures of a utility's as-available avoided cost rates: (1)
Energy rates established at liquid market hubs; or (2) energy rates
determined pursuant to formulas based on natural gas price indices and
a proxy heat rate for an efficient natural gas combined-cycle
generating facility. In each such case, though, the state would need to
find that that price reasonably represents a competitive market price
that represents the avoided costs of the purchasing electric
utility.\157\
---------------------------------------------------------------------------
\157\ NOPR, 168 FERC ] 61,184 at P 51.
---------------------------------------------------------------------------
b. Comments
107. Allco argues that the only reason for including the use of
competitive market prices to set as-available energy rates is to create
a menu of prices from which a state regulatory authority or unregulated
electric utility can choose the lowest price. Allco claims this
proposal would not encourage QF generation, would be inconsistent with
the rules of economic dispatch, and would be inconsistent with the
language of PURPA.\158\ BluEarth makes similar arguments.\159\ In
contrast, El Paso Electric argues that state regulatory authorities
should be able to set avoided cost rates based on the lesser of a
market hub price or a combined cycle price.\160\ Similarly, the
California Commission argues that utilities located in organized
markets (not just non-organized markets) should also be expressly
permitted to use any competitive price (whether derived from a market
hub, competitive solicitation, or a combined cycle price) to set
avoided cost rates. The California Commission also argues that states
should have the ability to use competitive prices for not just as-
available energy pricing, but also for capacity pricing, and proposes
minor modifications to the relevant regulation text proposed in the
NOPR in order to clarify these points.\161\
---------------------------------------------------------------------------
\158\ Allco Comments at 8.
\159\ BluEarth Comments at 2.
\160\ El Paso Electric Comments at 3-4.
\161\ California Commission Comments at 23-27.
---------------------------------------------------------------------------
108. The California Commission argues that the proposed regulations
should be modified to: (1) Define the newly permissible avoided cost
methodologies within the definitions section of Part 292; (2) eliminate
any perception that the new methodologies can only be used to set
avoided costs for as-available energy; (3) allow any appropriate
market-based methodology to set avoided-cost rates for energy, capacity
or both; and (4) define ``Organized Electric Market.'' \162\ The
California Commission believes that the new regulations should
indicate: (1) That they do not provide states any more flexibility than
they already have; (2) that utilities located in organized markets may
use any Market Hub Price, Competitive Solicitation Price, or Combined
Cycle Price to establish avoided-cost rates; and (3) that a price based
on LMP or a Competitive Price is just and reasonable and
nondiscriminatory.\163\
---------------------------------------------------------------------------
\162\ Id. at 11-14.
\163\ Id. at 23-25.
---------------------------------------------------------------------------
109. Some commenters object to the use of competitive markets
prices on the grounds that these competitive prices represent only
short-term, or spot prices that do not reflect the long-term marginal
costs and other costs avoided by purchasing utilities.\164\ Similarly,
some commenters assert that competitive prices cannot support the
financing of QFs.\165\
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\164\ IdaHydro Comments at 11; Southeast Public Interest
Organizations Comments at 19; NIPPC, CREA, REC, and OSEIA Comments
at 52, 55 (citing Exelon Wind I, LLC, 140 FERC ] 61,152, at P 52
(2012)); Union of Concerned Scientists Comments at 6.
\165\ BluEarth Renewables Comments at 2; Biological Diversity at
8; Covanta Comments at 9; Public Interest Organization Comments at
43-44.
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110. Public Interest Organizations argue that using competitive
prices to set as-available energy avoided cost rates is discriminatory
because non-QF generators are not limited to competitive prices and
utilities can, and regularly do, pay effective prices for energy that
exceed the price determined by competitive prices.\166\ Several other
commenters express concern about setting QF prices by referencing
short-term liquid hub prices while allowing utilities to rate base and
recover their long-term investments.\167\ Industrial Energy Consumers
argue that, if the Commission implements the liquid market hub
proposal, there must be assurances that utilities' self-builds face the
same market risk exposure as QFs. For example, they argue, if states
expose QFs to variable rates for their energy output, utility-owned
generation should also be exposed to variable rates for their energy
output.\168\
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\166\ Public Interest Organizations Comments at 64.
\167\ IdaHydro Comments at 11; Industrial Energy Consumers
Comments at 12-13.
\168\ Industrial Energy Consumers Comments at 12-13.
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111. Several commenters assert that QF rates should reflect
benefits other than the avoided cost of energy.\169\ For example,
Biogas and Biomass Power state that non-energy benefits, like waste
reduction and economic development must be incorporated into avoided
cost determinations.\170\ Biogas and Resources for the Future state
that locational values should be incorporated into avoided cost
calculations.\171\ American Dams states that utilities' avoided
[[Page 54655]]
transmission charges should be included in avoided cost
determinations.\172\ Xcel states that hidden integration and utility
planning costs should also be incorporated into avoided cost
calculations.\173\ American Dams argues that for high capital projects
like hydro, the Commission should consider longer-term public benefits
and not just short-term market pricing.\174\
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\169\ Biogas Comments at 1-2; Biomass Power Comments at 1; EPSA
Comments at 14-16; Resources for the Future Comments at 4; Xcel
Comments at 3-5.
\170\ Biogas Comments at 2; Biomass Power Comments at 1.
\171\ Biogas Comments at 1; Resources for the Future Comments at
4.
\172\ American Dams Comments at 4.
\173\ Xcel Comments at 3-5.
\174\ American Dams Comments at 2.
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112. Solar Energy Industries asserts that payments based on the LMP
should not relieve the purchasing utility of the requirement to
compensate the QF for any values in addition to electricity (e.g.,
renewable energy credits, frequency response capabilities, pro-rated
capacity value, etc.).\175\
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\175\ Solar Energy Industry Comments at 27-28.
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113. California Utilities request that the Commission clarify that
states may but are not required to consider state policies when
establishing avoided costs.\176\ Harvard Electricity Law requests that
the Commission clarify its rule allowing states to set tiered
rates.\177\
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\176\ California Utilities Comments at 18-19.
\177\ Harvard Electricity Law Comments at 32-33.
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c. Commission Determination
114. As an initial matter, we observe that some of the concerns
raised by commenters about the use of competitive market prices to set
as-available energy rates for QFs are based on the incorrect assumption
that the NOPR proposal would permit states to use competitive market
prices to set as-available energy rates for QFs even when competitive
market prices are below the purchasing utility's avoided costs. In
fact, however, the use of competitive market prices to set QF rates is
explicitly subject to the requirement that such prices are equal to the
purchasing utility's avoided energy costs.\178\ As the Supreme Court
noted in API, the full avoided cost rate requirement represents the
maximum rate permitted under PURPA, and thereby provides important
encouragement to QFs.\179\ And as the Supreme Court also noted in the
same decision, ``the full-avoided-cost rule plainly satisfies the
nondiscrimination requirement.'' \180\ Further, in requiring full
avoided cost rates, ``[t]he Commission did not ignore the interest of
electric utility consumers `in receiving electric energy at equitable
rates.' '' \181\
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\178\ Arguments that the various competitive market prices
identified in this final rule do not represent avoided energy costs
are addressed below with respect to each such specific market price.
\179\ API, 461 U.S. at 413.
\180\ Id.
\181\ Id. at 415 (quoting Conf. Rep. at 97).
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115. For this reason, Allco is incorrect when it claims that the
competitive price proposal represents a menu of prices that a state can
select to choose the lowest rate. In the event that more than one
competitive price option potentially could apply, the state would be
required to select the option that reasonably reflects the purchasing
utility's avoided costs, which is what PURPA requires.\182\
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\182\ In a competitive market, the transportation costs between
any such two hubs and a QF would be such that they would make the QF
rate the same, no matter which hub was selected. See FERC, Energy
Primer, A Handbook of Market Basics, at 64 (June 2020), https://www.ferc.gov/market-assessments/guide/energy-primer-2020.pdf (Energy
Primer) (``If there are no transmission constraints, or congestion,
LMPs will not vary significantly across the RTO footprint. However,
when transmission congestion occurs, LMPs will vary across the
footprint because operators are not able to dispatch the least-cost
generators across the entire region and some more expensive
generation must be dispatched to meet demand in the constrained
area.'').
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116. Further, the record supports the conclusion that the use of
transparent, competitive market prices provides encouragement to QFs,
represents the avoided cost, and can ensure that the rate does not
exceed the incremental cost to the purchasing electric utility. In
addition to the testimony to this effect presented at the technical
conference and cited in the NOPR,\183\ the conclusion is further
supported by comments submitted in response to the NOPR. For example,
NIPPC, CREA, REC, and OSEIA cite to a report by Fitch, which explains
how Fitch evaluates the financial strength of renewable energy
projects. In this report, Fitch states that it gives a ``stronger''
evaluation to projects with power sales contract prices that are
``indexed using simple, broad-based publicly available indexation
formulas.'' \184\ In addition, Solar Energy Industries notes the
difficulties QFs face in expending large sums to develop their projects
``[f]or states that do not publish the avoided costs, or for utilities
that treat their avoided cost methodologies as confidential trade
secrets.'' \185\
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\183\ See American Forest & Paper Association Comments, Docket
No. AD16-16-000, at 8 (filed June 8, 2016) (``To the extent
possible, these determinations [of avoided costs] should not be made
in a `black box', but rather, as part of an open and transparent
method and process.''); EEI Comments, Docket No. AD16-16-000, at 3
(filed June 30, 2016) (``Where transparent competitive markets with
day ahead prices exist, there is no reason to adhere to second-best
avoided cost pricing mechanisms.'').
\184\ NIPPC, CREA, REC, and OSEIA Comments at 37-38 (citing
FitchRatings, Global Infrastructure & Project Finance, Renewable
Energy Project Rating Criteria, at 3 (Feb. 26, 2019), https://www.fitchratings.com/site/re/10061770).
\185\ Solar Energy Industries Comments at 41.
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117. We agree with commenters who assert that competitive market
prices represent only short-run spot prices that do not reflect
electric utilities' long-run costs that QFs can displace. However, we
are authorizing states to use competitive market prices only to
establish as-available energy rates for QFs. The comments misunderstand
the fundamental difference between the value to a purchasing utility of
such as-available energy and the value to a purchasing utility of
capacity.
118. A QF has no obligation under the as-available avoided cost
rate provisions to deliver any set amount of electric energy at any
point in the future, but merely is paid for the amount of electric
energy actually delivered. Therefore, the delivery of as-available
energy does not displace any long-term energy the purchasing electric
utility would generate itself or purchase from another source but
rather allows the purchasing utility to reduce the amount of energy it
otherwise would generate itself or purchase from another entity at the
time the QF delivers the energy. Because the QF has no obligation to
deliver any energy in the future, the utility is unable to avoid
constructing or contracting for capacity to meet its future needs as a
consequence of the delivery of energy by the QF. As-available energy
rates therefore appropriately reflect only the short-run value of
energy delivered at the particular moment in time when and if the QF
has energy available to be delivered to the utility.
119. A QF can displace an electric utility's own generation or
purchases from alternative sources over the long-run when a QF sells
capacity to a utility in addition to as-available energy. In contrast
to as-available energy, a sale of capacity would typically compensate
the QF for maintaining the capability to deliver a set amount of energy
in the future (i.e., capital costs),\186\ and thus allows the
purchasing utility to avoid the cost of making alternative
arrangements, either through a self-build or an alternative purchase,
to obtain that amount of energy. Consequently, the price of capacity
purchased from a QF would reflect this long-run avoided cost. And this
final rule does not alter a purchasing utility's
[[Page 54656]]
existing obligation to pay QFs for any avoided capacity benefit that
allows the utility to avoid acquiring capacity.\187\
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\186\ See Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,885
(``Energy costs are the variable costs associated with the
production of electric energy (kilowatt-hours). They represent the
cost of fuel, and some operating and maintenance expenses. Capacity
costs are the costs associated with providing the capability to
deliver energy; they consist primarily of the capital costs of
facilities.'').
\187\ See Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,881-
86 (describing how states must calculate avoided capacity costs).
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120. For these reasons, we decline to grant the California
Commission's request to allow using competitive prices for not just as-
available energy pricing, but also for capacity pricing.\188\ We also
reject the California Commission's request to permit all electric
utilities, both those located in organized markets and those located in
non-organized market areas, to use any competitive price (whether a
Market Hub Price or Combined Cycle Price, or alternatively a
Competitive Solicitation Price) to set avoided cost rates. The Market
Hub Price and Combined Cycle Price, as well as the Competitive
Solicitation Price are options that should generally reflect a
purchasing electric utility's avoided as-available energy costs in non-
RTO/ISO areas, while the LMP should generally reflect a purchasing
electric utility's avoided as-available energy costs in RTO/ISO market
areas.
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\188\ See infra sections IV.B.3-5. We note that states may use
competitive solicitations to set both energy and capacity avoided
cost rates. See infra section IV.B.8.
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121. With respect to the discrimination claims, our decision to
give states the flexibility to use competitive prices is driven by the
fact that the competitive market price represents the purchasing
utility's avoided costs. And, as explained in Section IV.A.2 above, a
rate set at full avoided costs by definition cannot be discriminatory
and, in any event, the Commission is without authority under PURPA
section 210(b) to require a rate above avoided costs.
122. Further, Industrial Energy Consumers are incorrect when they
suggest that public utility energy rates do not vary with costs in the
same way that the competitive market prices potentially applicable to
QFs under the final rule vary. To the contrary, the Commission and most
states provide for fuel adjustment clauses applicable to rates, which
allow utility rates to adjust automatically with changes in utility
fuel and purchased power costs.\189\ And even utilities whose rates do
not include fuel and purchased power adjustment clauses nevertheless
typically must charge their retail customers cost-based rates, which
means that their energy charges will vary from one rate case to the
next as their fuel and purchased power costs vary from year to year.
These mechanisms for ensuring that utility rates vary with the cost of
energy result in variances in utility energy rates that are similar to
the variance in QF energy rates for those states that elect a
Competitive Price option (either a Market Hub Price or a Combined Cycle
Price) for as-available avoided cost rates.
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\189\ See 18 CFR 35.14 (Fuel Cost and Purchased Economic Power
Adjustment Clauses); ELCON, Fuel Adjustment Clauses & Other Cost
Trackers, https://elcon.org/fuel-adjustment-clauses-cost-trackers
(``Fuel adjustment clauses are in effect in almost all states.'');
NARUC, Staff Subcommittee on Accounting and Finance, Fuel and
Purchased Power Survey Results (Sept. 23, 2015), https://pubs.naruc.org/pub/4AA28D50-2354-D714-5149-B773EFC3EFEF (stating
that only one state surveyed said that it did not employ a fuel
adjustment clause).
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123. Finally, although we are sympathetic to the claims of certain
QFs that they provide non-energy benefits (such as environmental
benefits, waste reduction benefits, and economic development benefits)
that are not reflected in avoided cost rates, PURPA section 210(b)
prohibits the Commission from requiring QF rates to be set above full
avoided costs. Because the Commission already requires states to set QF
rates at full avoided costs, it is barred from requiring QF rates set
higher than that based on the non-energy benefits that QFs may also
provide. However, nothing in PURPA, the PURPA Regulations as they
currently exist, or this final rule would prevent states from rewarding
QFs for such non-energy benefits so long as that is done outside of
PURPA, such as is now done for renewable energy credits (RECs) to
compensate QFs for providing unique environmental or other non-PURPA
benefits.\190\ We address in the sections below each type of
competitive price that could be used as an acceptable energy avoided
cost.
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\190\ See, e.g., American Ref-Fuel Co., 105 FERC ] 61,004, at PP
22-24 (2003), denying reh'g, 107 FERC ] 61,016 at PP 12, 15-16
(2004), dismissing pet. for review sub nom. Xcel Energy Servs. Inc.
v. FERC, 407 F.3d 1242 (D.C. Cir. 2005).
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3. LMP as a Permissible Rate for Certain As-Available Avoided Cost
Rates
a. NOPR Proposal
124. The Commission proposed to revise 18 CFR 292.304 to add
subsections (b)(6) and (e)(1). In combination, these subsections would
permit a state the flexibility to set the as-available energy rate paid
to a QF by an electric utility located in an RTO/ISO at LMPs calculated
at the time of delivery.
125. The Commission explained that RTO/ISO markets calculate a LMP
at each location on the RTO/ISO-controlled grid, and that all sellers
receive the LMP for their location and all buyers pay the market
clearing price for their location. The Commission further recognized
that LMPs reflect the true marginal cost of production, taking into
account all physical system constraints, and these prices would fully
compensate all resources for the variable cost of providing
service,\191\ and explained that prices in such an LMP-based rate
structure are designed to reflect the least-cost of meeting an
incremental megawatt-hour of demand at each location on the grid in
each period, and thus such prices can vary based on location and
time.\192\
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\191\ Offer Caps in Mkts Operated by Reg'l Transmission Orgs.
and Independent Sys. Operators, Order No. 831, 157 FERC ] 61,115, at
P 7 (2016), order on reh'g and clarification, Order No. 831-A, 161
FERC ] 61,156 (2017).
\192\ Sacramento Mun. Util. Dist. v. FERC, 616 F.3d 520, 524
(D.C. Cir. 2010) (SMUD); see also FERC v. Elec. Power Supply Ass'n,
136 S. Ct. 760, 768-69 (2016) (describing how LMP is typically
calculated).
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126. The Commission therefore preliminarily found that LMP is an
accurate measure of avoided costs. Unlike, for example, average system-
wide cost measures of avoided cost used by many states, LMP could
provide an accurate measure of the varying actual avoided costs for
each receipt point on an electric utility's system where the utility
receives power from QFs; LMP is the per MWh cost of obtaining
incremental supplies at each point. Further, the Commission explained
that these prices are not rigid, long-lasting prices as tends to be the
case currently for administratively-determined avoided costs, but
prices that are calculated daily (for the day-ahead markets) and/or
every five minutes (for real-time markets) and they vary to reflect
changing system conditions (e.g., they tend to rise as demand increases
and the system operator dispatches increasingly expensive supplies to
meet that higher demand). In addition, the Commission observed that
LMPs, in contrast to the administrative pricing methodologies used to
set as-available QF rates by many states, could promote the more
efficient use of the transmission grid, promote the use of the lowest-
cost generation, and provide for transparent price signals.\193\
Finally, the Commission also noted that Congress, through enactment of
PURPA section 210(m), appears to have recognized that RTO/ISO LMP
pricing provides sufficient encouragement for QFs.
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\193\ See, e.g., Cal. Indep. Sys. Operator Corp., 105 FERC ]
61,140, at PP 48-50 (2003); cf. Price Formation in Energy and
Ancillary Servs. Mkts Operated by Reg'l Transmission Orgs. and
Indep. Sys. Operators, 153 FERC ] 61,221, at P 2.
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127. The Commission requested comment on whether the real-time
prices established in the CAISO-administered Energy Imbalance Market
[[Page 54657]]
(EIM) \194\ are similar for these purposes to the LMP in RTOs/ISOs. In
this regard, the Commission requested comment on whether ``prices
developed in the EIM similarly `reflect the least-cost of meeting an
incremental megawatt-hour of demand at each location on the grid,' as
the Commission has found to be the case with LMP rates.'' \195\
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\194\ The Commission noted that, by seeking comment regarding
the Western EIM prices, the Commission did not mean to imply that
real-time energy prices established by CAISO within its balancing
authority area do not already satisfy the requirement for setting
as-available QF rates.
\195\ NOPR, 168 FERC 61,184 at P 47 (quoting SMUD, 616 F.3d at
524). Use of real time prices in the Western EIM was addressed at
the Technical Conference, but only in the context of whether that
market could satisfy the requirements for termination of the
mandatory purchase obligation under PURPA section 210(m)(1)(C). See
Supplemental Notice of Technical Conference, Implementation Issues
Under the Public Utility Regulatory Policies Act of 1978, Docket No.
AD16-16-000 (May 9, 2016). The Commission here requested comments on
whether it would be appropriate to use the Western EIM price to
develop an as-available energy rate.
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128. The Commission understood that some states already use LMP to
establish avoided cost energy rates under the existing PURPA
Regulations.\196\ The Commission thus proposed also to clarify that,
while a state in the past may have been able to conclude that LMP was
an appropriate measure of the energy component of avoided costs,\197\ a
state would, under the proposal in the NOPR, be able to adopt LMP as a
per se appropriate measure of the as-available energy component of
avoided costs.\198\
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\196\ See Exelon Wind 1, LLC, 140 FERC ] 61,152, at P 11,
reconsideration denied, 155 FERC ] 61,066 (2016) (recognizing that
the Texas Public Utility Commission has permitted Southwestern
Public Service Company to set avoided costs at LMP); Xcel Energy
Services Inc., Request for Reconsideration, Docket No. EL12-80-001,
at 13 & n.23 (filed Sept. 27, 2012) (stating that Maryland, New
Jersey, North Carolina, Virginia, Connecticut, New Hampshire,
Kentucky, and Michigan have set avoided costs at LMP).
\197\ See 18 CFR 292.304(e).
\198\ The Commission recognized in the NOPR that this proposal
could be seen as a departure from the Commission's statement in
Exelon Wind 1, LLC, 140 FERC ] 61,152 at P 52, reconsideration
denied, 155 FERC ] 61,066 (``The problem with the methodology
proposed by [Southwestern Public Service Company] and adopted by the
Texas Commission is that it is based on the price that a QF would
have been paid had it sold its energy directly in the [Energy
Imbalance Service] Market, instead of using a methodology of
calculating what the costs to the utility would have been for self-
supplied, or purchased, energy `but for' the presence of the QF or
QFs in the markets, as required by the Commission's regulations.'').
The Commission has since found that this statement was overtaken by
events, namely SPP's evolution from an energy imbalance service
market into an Integrated Marketplace, with day-ahead and real-time
energy and operating reserve markets and the Texas Commission's
approving a separate request from Southwestern Public Service
Company to substitute LMP for Locational Imbalance Prices in
calculating avoided costs. Exelon Wind 1, LLC, 155 FERC ] 61,066 at
P 11. The Commission also has acknowledged that, if adopted in a
final rule, the reasoning in the NOPR supported a departure from
precedent. See Cal. Pub. Utils. Comm'n v. FERC, 879 F.3d 966, 977
(9th Cir. 2018) (``When an agency changes policy, the requirement
that it provide a reasoned explanation for its action demands, at a
minimum, that the agency `display awareness that it is changing
position.''') (citing FCC v. Fox Television Stations, Inc., 556 U.S.
502, 515 (2009)).
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b. Comments
i. Comments in Opposition
129. Several commenters oppose the NOPR's LMP proposal.\199\
American Biogas asserts that, by definition, LMP rates assume that
generating facilities are receiving other compensation to fund their
operations and that the marginal rate reflects only the value of the
energy. American Biogas asserts that LMP ignores biogas facilities'
unique municipal infrastructure role and multiple benefits to the
community.\200\ Covanta argues that avoided costs paid to small
baseload QFs should incorporate all long-run avoided costs for capacity
and energy and include other externalities such as the value of
renewable baseload energy, greenhouse gas mitigation, landfill
diversion, reliable and resilient power and other benefits of small
baseload QFs.\201\ Biological Diversity argues that LMP pricing ignores
variability across the country and is inappropriate in regions like the
Southeast which lack RTOs and ISOs and are instead still dominated by
vertically-integrated monopolies.\202\
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\199\ Biogas Comments at 2; Covanta Comments at 8-9; Biological
Diversity Comments at 8-9; CA Cogeneration Comments at 8-9; ELCON
Comments at 23-25; ENGIE Comments at 4; New England Small Hydro
Comments at 8-11; NIPPC, CREA, REC, and OSEIA Comments at 53-60;
Public Interest Organizations Comments at 52-64; Union of Concerned
Scientists Comments at 4-9; Southeast Public Interest Organizations
Comments at 21-25.
\200\ Biogas Comments at 2.
\201\ Covanta Comments at 8.
\202\ Biological Diversity Comments at 8-9.
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130. CA Cogeneration argues that LMP may not represent a truly
competitive price for electricity because, in California, the majority
of supply is through bilateral contracts, not through competitive
bidding in the market. CA Cogeneration states that rooftop solar
distorts LMP by reducing load and not bidding in its full long-term
marginal cost.\203\ CA Cogeneration states that LMPs can be well below
the operating cost of conventional generation and combined heat and
power, and even negative, especially when there is an abundance of
procured resources such as hydro, solar, and wind.\204\ CA Cogeneration
asserts that combined heat and power can survive only if: (1) Fixed
capacity prices are sufficiently high to cover the energy price risk;
(2) the market price reflects the full cost of contracted power and
includes all sources of supply; or (3) 18 CFR 292.304(f)(1) is modified
to provide QF operations first priority, except in special
circumstances related to reliability.\205\
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\203\ CA Cogeneration Comments at 8-9.
\204\ Id.
\205\ Id.
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131. ELCON argues that allowing utilities to use LMP and other
competitive market prices would allow states to ignore long-standing
factors established by Commission regulation in determining the avoided
cost rates, including: (1) Availability of capacity or energy from a QF
during the system daily and seasonal peak periods; (2) dispatchability
and reliability; (3) the relationship of the availability of energy or
capacity from the QF to the ability of the utility to avoid costs; (4)
costs or savings from variations in line losses; and (5) application of
technology-specific avoided cost rates.\206\ ENGIE argues that allowing
states to set energy rates at LMP, while also allowing them to set
capacity rates at zero if it is determined that a utility has no need
for capacity, could allow traditional utilities to corner the market on
capacity, leaving smaller independent QFs to fill energy-only contracts
at LMP.\207\
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\206\ ELCON Comments at 23-24.
\207\ ENGIE Comments at 4.
---------------------------------------------------------------------------
132. New England Small Hydro states that the Commission has not
supported the NOPR's assertion that LMP is an accurate measure of
avoided costs because the NOPR: (1) Inappropriately relies on the
Energy Policy Act of 2005's changes in PURPA section 210(m) to support
its proposed changes to calculation of the avoided cost rate; (2)
ignores the costs that the utility pays to procure power (i.e., RFPs,
other power contracts, planned retirements); and (3) ignores the fact
that LMP and the default service rates that exist in ISO-NE-based
states are quite different.\208\ In addition, New England Hydro states
that, for the avoided cost calculation, the appropriate LMP is the day-
ahead LMP, not the real-time LMP, because utilities primarily purchase
energy in the day-ahead market pursuant to bilateral contracts or RFPs,
not in the real-time market.\209\ New England Hydro also believes that
utilities or state regulatory bodies should be required to establish
and maintain long-term avoided energy forecasts upon which
[[Page 54658]]
QF PURPA power purchase rates would be based.\210\
---------------------------------------------------------------------------
\208\ New England Small Hydro Comments at 8-10.
\209\ Id. at 10.
\210\ Id. at 11.
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133. NIPPC, CREA, REC, and OSEIA claim that LMPs only promote more
efficient use of the transmission grid in the short-term because
factors such as temporary outages, equipment failures, weather
extremes, and the like can cause LMPs to spike, but these have no
impact on long-term transmission availability.\211\ NIPPC, CREA, REC,
and OSEIA believe that, while LMPs are a useful tool for developers to
identify points on the grid where transmission is relatively more or
less congested, developers have strong incentives to avoid congestion,
and they will generally be guided to areas of low congestion during the
transmission interconnection process, whether or not they face LMP-
based contract prices. NIPPC, CREA, REC, and OSEIA claim that if
transmission constraints prevent a generator from delivering power to a
specific node, the LMP at that node cannot be an appropriate measure of
costs avoided by purchase of power from that generator. NIPPC, CREA,
REC, and OSEIA argue that LMP or Western EIM prices at the time of
delivery are not a true measure of the long-term avoided costs of
incumbent utilities unless those utilities are relying on those markets
as a means to obtain long-term resources.\212\
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\211\ NIPPC, CREA, REC, and OSEIA Comments at 57-59.
\212\ Id. at 55 (citing Exelon Wind I, 140 FERC ] 61,152 at P
52).
---------------------------------------------------------------------------
134. NIPPC, CREA, REC, and OSEIA assert that the NOPR proposal
fails to recognize: (1) the Commission's struggle to develop effective
capacity markets in the RTO/ISO regions; (2) the fact that the merchant
generation model is now in serious question; and (3) that the
Commission's claim that Congress endorsed the use of LMP to set avoided
cost rates by adoption of section 210(m) cannot be squared with the
plain language of the statute.\213\ NIPPC, CREA, REC, and OSEIA argue
that there is substantial evidence that LMP prices are distorted by
certain practices, such as zero-cost bids, so that plants operate
uneconomically.\214\ NIPPC, CREA, REC, and OSEIA further maintain that
the 2000-01 California market demonstrated that these volatile short-
term markets can reach extreme and unpredictable highs under stress
conditions.\215\
---------------------------------------------------------------------------
\213\ Id. at 57-59.
\214\ Id. at 55.
\215\ Id. at 57.
---------------------------------------------------------------------------
135. Similarly, Public Interest Organizations cite to studies by
the Sierra Club \216\ and Bloomberg New Energy Finance,\217\ for the
proposition that the use of LMP as the QF price discriminates against
QFs where utility-owned generation and non-QF generators are not
limited to the LMP for recovery of their costs, and where utilities
depress LMP through uneconomic dispatch of their own generation
facilities.\218\ Union of Concerned Scientists states that LMPs are not
an accurate measure of avoided costs and should not be used to set QF
rates because the practice of providing utility-owned generation with
out-of-market cost-recovery in areas like MISO, PJM, SPP, the SERC
Reliability Corporation, and the Western Electricity Coordinating
Council suppresses the clearing prices in the markets where this is
allowed.\219\
---------------------------------------------------------------------------
\216\ Public Interest Organizations Comments at 53-56 (citing
Jeremy Fisher, Sierra Club, Playing with Other People's Money, How
Non-Economic Coal Operations Distort Energy Markets, Sierra Club,
Oct. 2019, at 4).
\217\ Id. at 57 (citing William Nelson & Sophia Liu, Half of
U.S. Coal Fleet on Shaky Economic Footing; Coal Plant Operating
Margins Nationwide, Bloomberg New Energy Finance, March 26, 2018).
\218\ Id. at 52-64.
\219\ Union of Concerned Scientists Comments at 3-8.
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136. Southeast Public Interest Organizations argue that the NOPR's
proposed avoided cost methodology does not take into account: (1) Long-
term or seasonal purchases made from third parties or affiliates; (2)
adjustments for transmission and distribution losses; (3) capacity
deferrals; (4) avoided environmental compliance costs; or (5) a QF's
dispatchability.\220\ Southeast Public Interest Organizations state
that LMP-based rates for QFs in Virginia have enticed little-to-no QF
development in Virginia.\221\ Southeast Public Interest Organizations
urge the Commission either to rescind the NOPR's LMP provisions or at
least to implement this provision on a case-by-case basis.\222\
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\220\ Southeast Public Interest Organizations Comments at 22.
\221\ Id. at 23.
\222\ Id. at 24.
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(a) Utilizing Western EIM To Establish Avoided Costs
137. Solar Energy Industries argues that, because as-available QF
resources are not eligible to participate in the Western EIM (also
known as the CAISO EIM), either directly or through the purchasing
utility, it would be inappropriate to use the Western EIM price as a
proxy because that market does not factor in the participation of the
QF resource.\223\ ELCON asserts that the Western EIM is not a complete
measure of avoided energy costs because the Western EIM merely covers
imbalance conditions, and therefore does not capture the vast majority
of unit commitment and dispatch scheduling cost parameters.\224\ Union
of Concerned Scientists asserts that allowing a state to adopt real-
time prices established in the Western EIM as an accurate measure of
avoided costs will be discriminatory.\225\
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\223\ Solar Energy Industries Comments at 27.
\224\ ELCON Comments at 24.
\225\ Union of Concerned Scientists Comments at 9.
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ii. Comments in Support
138. Several commenters support the Commission's proposal to permit
a state the flexibility to use LMPs to set the as-available energy rate
paid to a QF by an electric utility located in an RTO/ISO.\226\
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\226\ APPA Comments at 11; Arizona Public Service Comments at 5;
CA Utilities Comments at 17; Conn. Authority Comments at 13; DTE
Electric Comments at 4; EEI Comments at 22-24; Comments at 4-5;
Idaho Commission Comments at 3-4; Indiana Municipal Comments at 5;
Kentucky Commission Comments at 4-5; NorthWestern Comments at 4-7;
NRECA Comments at 6-7; Ohio Commission Energy Advocate Comments at
4-5; Pennsylvania Commission Comments at 7-9; South Dakota
Commission Comments at 2; US Chamber of Commerce Comments at 4; We
Stand Comments at 1; Xcel Comments at 5.
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139. CA Utilities state that the NOPR's LMP proposal is a return to
the Commission's policy as expressed in Winding Creek,\227\ and will
facilitate payments to QFs that more accurately represent a utility's
actual avoided costs. CA Utilities assert that the NOPR's LMP proposal
affirms that a formula energy price contract complies with PURPA if
coupled with a fixed capacity price. CA Utilities state that a formula
energy price contract will have the additional benefit of avoiding the
need to develop and administer a new PURPA contract.\228\
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\227\ CA Utilities Comments at 15-17 (citing Winding Creek Solar
LLC, 151 FERC ] 61,103, at P 6 (2015)).
\228\ Id. at 17.
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140. NRECA supports the Commission's proposal because many
utilities that participate in the RTO/ISO markets offer the entirety of
their generation into the market, and purchase all of their
requirements to serve load from that market, at LMP prices.\229\
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\229\ NRECA Comments at 6.
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141. The Pennsylvania Commission supports the NOPR proposal because
LMP prices vary through the day based on changing system conditions,
such as changes in electricity demand, supply, congestion, and line
losses. The Pennsylvania Commission asserts that, because some
utilities in Pennsylvania
[[Page 54659]]
(and other states) have already incorporated LMP elements in their as-
available energy rates, a corresponding revision to the Commission's
regulations that incorporates such practices and harmonizes state and
federal regulations would bring greater predictability to suppliers,
electric utilities and customers.\230\
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\230\ Pennsylvania Commission Comments at 7-8.
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142. The Ohio Commission Energy Advocate believes that, in the
parts of the country with organized nodal wholesale electricity
markets, LMP is an appropriate and fair means by which to calculate
avoided costs because electricity supply and demand must be balanced in
real time. The Ohio Commission Energy Advocate notes that Ohio has
nodal LMPs that reflect the true value of energy at the place and the
time it is produced or delivered, and this value can change
dramatically, even within a day or an hour. The Ohio Commission Energy
Advocate concludes that reflecting the dynamic nature of electricity
pricing in avoided cost calculations will send the most accurate price
signals to QFs and will appropriately and fairly value the energy they
produce.\231\
---------------------------------------------------------------------------
\231\ Ohio Commission Energy Advocate Comments at 4-5.
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143. The South Dakota Commission supports using LMP for certain as-
available QF energy sales because using LMP will increase states'
flexibility. The South Dakota Commission regulates six vertically
integrated electric utilities, five of which are RTO members, and five
of which are multi-jurisdictional.\232\
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\232\ South Dakota Commission Comments at 2.
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144. Xcel submits that compensating QFs based on LMPs at the time
of delivery will not impair QFs' ability to obtain financing because
other factors can drive the ability to obtain financing, including
other project options, location, size, interconnection costs,
experience of the developer, current economic conditions,
creditworthiness of the developer, economies of scale, and other
factors. Xcel states that some resource specific information generally
suggests that the right project in the right location can obtain
financing if the project receives hourly payment based on LMPs.\233\
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\233\ Xcel Comments at 5-7.
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(a) Utilizing Western EIM To Establish Avoided Costs
145. NorthWestern and EIM Entities agree that the Western EIM real-
time prices are similar to LMPs and reflect the least cost of meeting
an incremental megawatt-hour of demand at each location on the
grid.\234\ Xcel asserts that prices in the Western EIM are calculated
using the same methodology as LMPs because, in both cases, units are
dispatched on a least-cost basis that respects applicable transmission
constraints. Xcel requests that the Commission allow avoided costs to
be based on Western EIM prices at the time of delivery absent a showing
that prices would be suppressed in comparison to an LMP-style-
market.\235\ Arizona Public Service states that it is a participant in
the Western EIM, and requests that states be given flexibility to set
the as-available energy rate to be paid to a QF by an electric utility
that participates in the Western EIM at the LMP.\236\
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\234\ EIM Entities Comments at 2-3, 7-13; NorthWestern Comments
at 4-5.
\235\ Xcel Comments at 7-8.
\236\ Arizona Public Service Comments at 5-6.
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iii. Comments in Support With Requested Modifications/Clarifications
146. APPA urges the Commission to clarify that nothing in the
proposed rule is intended to call into question state regulatory
authorities' existing implementation of PURPA's avoided cost
requirements, such as their existing use of LMP.\237\
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\237\ APPA Comments at 9.
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147. Industrial Energy Consumers do not object to the use of LMP as
the avoided cost rate for electric utilities' purchases of QF energy in
RTO/ISO regions,\238\ but they maintain that in non-RTO/ISO regions,
there must be assurance that utilities' self-builds face the same
market risk exposure as QFs.\239\
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\238\ Industrial Energy Consumers Comments at 11.
\239\ Id. at 12.
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148. The Kentucky Commission supports the NOPR's LMP proposal but
prefers that the Commission in the final rule allow states to determine
whether the LMP calculation should use the generator LMP or the load
LMP on a case-by-case basis.\240\
---------------------------------------------------------------------------
\240\ Kentucky Commission Comments at 4-5.
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149. Solar Energy Industries assert that, where the purchasing
utility has demonstrated that it procures its marginal energy from an
LMP market, the utility may use the LMP price as a proxy for avoided
energy costs calculated at the time the obligation is incurred, so long
as there are published prices at the location.\241\ Solar Energy
Industries request that the Commission make clear that: (1) The
flexibility to set QF payment rates for as-available energy at the
applicable LMP requires an on-the record determination that the
purchasing utility procures incremental energy from the identified LMP
market at those prices; (2) payments based on an LMP do not relieve the
purchasing utility of the requirement to compensate the QF for any
values in addition to electricity (e.g., renewable energy credits,
frequency response capabilities, pro-rated capacity value, etc.); and
(3) the state's flexibility to allow utilities to set QF payment rates
for as-available energy at the applicable LMP does not in any way limit
QFs' rights to establish a LEO or contract for a longer-term sale at
fixed, full avoided costs.\242\
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\241\ Solar Energy Industries Comments at 25-26.
\242\ Id. at 27-28.
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150. NorthWestern believes that as-available rates based on LMPs
should accurately capture current events impacting prices, including
times when there is a high saturation of energy available causing
prices to be negative. However, NorthWestern believes that it is
appropriate to deduct from the avoided cost rate the cost for ancillary
services to balance and integrate energy resources.\243\
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\243\ NorthWestern Comments at 4-5.
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c. Commission Determination
151. We affirm with one modification the NOPR proposal to allow LMP
to be used as a measure of as-available energy avoided costs for
electric utilities located in RTO/ISO markets for the reasons set forth
in the NOPR \244\ and those provided by various commenters.
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\244\ NOPR, 168 FERC ] 61,184 at PP 44-45.
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152. We recognize that an LMP selected by a state to set a
purchasing utility's avoided energy cost component might not always
reflect a purchasing utility's actual avoided energy costs.
Accordingly, we find that it is appropriate to modify the option for a
state to set avoided energy costs using LMP from a per se appropriate
measure of avoided cost to a rebuttable presumption that LMP is an
appropriate means to determine avoided cost. While a state could rely
on the presumption, an aggrieved entity (such as a QF) may attempt to
rebut the presumption that LMP reflects the purchasing electric
utility's avoided costs. The aggrieved entity would be able to
challenge the state's decision to rely on LMP in the appropriate forum,
which could include any one or more of the following: (1) Initiating or
participating in proceedings before the relevant state commission or
governing body; (2) filing for judicial review of any state regulatory
proceeding in state court (under PURPA section 210(g)); or,
alternatively (3)) filing a petition for enforcement against the state
at the Commission and, if the Commission declines to act, later filing
a petition against the state in U.S.
[[Page 54660]]
district court (under PURPA section 210(h)(2)(B)).\245\
---------------------------------------------------------------------------
\245\ See Policy Statement Regarding the Commission's
Enforcement Role Under Section 210 of the Public Utility Regulatory
Policies Act of 1978, 23 FERC ] 61,304.
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153. Commenters have not persuaded us that LMP may not
presumptively reflect a purchasing electric utility's avoided energy
costs. LMP sets day-ahead and real-time energy prices through
competitive auctions in RTOs/ISOs that optimally dispatch resources to
balance supply and demand, while taking into account actual system
conditions including congestion on the transmission system. We continue
to find that: (1) LMPs reflect the true marginal cost of production of
energy, taking into account all physical system constraints; (2) these
prices would fully compensate all resources for their variable cost of
providing service; (3) LMP prices are designed to reflect the least-
cost of meeting an incremental megawatt-hour of demand at each location
on the grid, and thus prices vary based on location and time; and (4)
unlike average system-wide cost measures of the avoided energy cost
used by many states, LMP should provide a more accurate measure of the
varying actual avoided energy costs, hour by hour, for each receipt
point on an electric utility's system where the utility receives power
from QFs.\246\
---------------------------------------------------------------------------
\246\ See NOPR, 168 FERC ] 61,184 at PP 44-45 (citing SMUD, 616
F.3d at 524; FERC v. Elec. Power Supply Ass'n, 136 S. Ct. at 768-69
(describing how LMP is typically calculated); Order No. 831, 157
FERC ] 61,115, at P 7, order on reh'g and clarification, Order No.
831-A, 161 FERC ] 61,156).
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154. Various commenters have provided additional reasons for
supporting the NOPR proposal concerning LMP. NRECA explains that LMP
rates for energy are appropriate because many utilities that
participate in the RTO/ISO markets offer the entirety of their
generation into the market at LMP prices and buy all of their load
requirements from the market at LMP prices.\247\ This scenario
described by NRECA is a common one, and it demonstrates that the market
itself, with its LMP pricing, can be the electric utility resource that
would be displaced by a QF purchase. Furthermore, as argued by
Pennsylvania Commission, because some utilities in Pennsylvania and
other states have already incorporated LMP in their as-available energy
rates, a corresponding revision to the Commission's regulations that
incorporates such practices and harmonizes state and federal
regulations would bring greater predictability to suppliers, electric
utilities and customers.\248\
---------------------------------------------------------------------------
\247\ NRECA Comments at 6.
\248\ Pennsylvania Commission Comments at 7-8.
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i. Arguments Against the NOPR Proposal
155. Commenters have not offered persuasive arguments for rejecting
the use of LMP for avoided cost energy rate determination. We disagree
with the argument made by Union of Concerned Scientists,\249\ NIPPC,
CREA, REC, and OSEIA,\250\ and Public Interest Organizations \251\ that
LMP should not be used as a measure of avoided energy costs because LMP
prices are depressed in many markets where self-scheduling rights and
state cost-recovery mechanisms for fuel and operating costs create the
opportunity for market participation at a loss. We recognize that, all
other things being equal, self-scheduling of resources may impact
market clearing prices. This potential price effect, however, does not
mean that the LMP is not an accurate measure of avoided energy costs.
The Commission's regulations, using language from PURPA section 210(d),
define avoided costs as ``the incremental costs to an electric utility
of electric energy or capacity or both which, but for the purchase from
the qualifying facility or qualifying facilities, such electric utility
would generate for itself or purchase from another source.'' \252\
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\249\ Union of Concerned Scientists Comments at 3-8.
\250\ NIPPC, CREA, REC, and OSEIA Comments at 52.
\251\ Public Interest Organizations Comments 52-64.
\252\ 18 CFR 292.101(b)(6) (emphasis added).
---------------------------------------------------------------------------
156. In organized wholesale electric market areas, the electric
utility purchases that would be displaced by QF purchases would, as
NRECA explains, in all likelihood be priced at the relevant LMP. These
LMPs are impacted by many factors, such as self-scheduling, generator
outages, and transmission outages, that may result in LMPs that are
lower or higher than they might otherwise have been. Thus, while self-
scheduling or other factors may impact LMPs, in any case, an electric
utility's purchases during periods when these price impacts are
occurring would be made at the resulting LMPs, whatever those LMPs may
be. Therefore, LMPs meet the Commission's long-standing definition of
avoided costs for a purchasing electric utility, even if they happen to
reflect price impacts from self-scheduling or other factors.
157. Furthermore, while commenters discuss the possibility that
utility-owned coal-fired resources are self-scheduling only because
retail ratepayers are subsidizing such activities, even if such claims
were true they would not alter the above analysis. The LMPs that result
from a market that includes self-scheduled resources still represent
the price of purchases in the market that would be displaced by the QF
purchase.
158. In addition, we reject the related request for clarification
made by Solar Energy Industries,\253\ i.e., that the flexibility to set
QF payments for as-available energy at the applicable LMP should
require an on-the-record determination that the purchasing utility
procures incremental energy from the identified LMP market at those
prices. Unless an aggrieved entity seeks to rebut this presumption in a
state avoided cost adjudication, rulemaking, legislative determination,
or other proceeding, that state would not need to make such an on-the-
record determination before it decides to use LMP.
---------------------------------------------------------------------------
\253\ Solar Energy Industry Comments at 27-28.
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159. Entities may seek to rebut the presumption in particular
cases, as described earlier, and whether the utility actually procures
energy from the identified LMP market or from resources with prices
tied to the identified LMP may be a relevant factor in such rebuttal
arguments. Consistent with the reasons described above for why there
should be such a rebuttable presumption in favor of LMP, this
delineation of rights appropriately places the initial burden on
entities seeking to rebut the presumption, rather than on the states
who wish to rely on LMP for setting avoided cost rates for as-available
energy. The Commission could consider such issues if and when they may
arise in individual cases appropriately brought to the Commission,
including whether the state has adequately justified its use of that
rebuttable presumption.
160. We reject the arguments made by NIPPC, CREA, REC, and OSEIA
that, more generally, prices for long-term QF contracts should be set
by reference to long-term price indices or other indicators that
genuinely reflect the long-term costs of generation avoided by the
purchasing utility.\254\ This final rule only addresses as-available
energy, and as-available energy prices by definition are short term, as
explained below in Section IV.B.7.c.
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\254\ NIPPC, CREA, REC, and OSEIA Comments at 53.
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161. We also reject the arguments made by NIPPC, CREA, REC, and
OSEIA that, while the NOPR is correct that LMPs are intended to promote
more efficient use of the transmission grid,
[[Page 54661]]
that is true only in the short term since factors such as temporary
outages, equipment failures, weather extremes, and the like can cause
LMPs to spike, but these have no impact on long-term transmission
availability. LMPs promote efficient use of the transmission grid in
the long term as well as the short term. Persistence of significant
price separation between different LMP nodes provides an indication of
the value of various possible transmission system upgrades and can show
transparently how system efficiencies may be improved by such
transmission system upgrades. Developers may have some incentive to
avoid congestion without LMPs, but LMPs provide an important price
signal as to how economic or uneconomic a particular production site
may be. In any event, the potential for more efficient use of the
transmission grid is merely an additional benefit of using LMP for
avoided energy cost determinations. Our adoption of LMP as a measure of
avoided energy costs in the RTO/ISO markets is based principally on the
fact that, in RTO/ISO markets, LMP accurately represents the purchasing
electric utility's avoided energy cost at the time the energy is
delivered, for the reasons described earlier.
162. We also are not persuaded by arguments that, if transmission
constraints prevent a generator from delivering power to a specific
node, the LMP at that node cannot be an appropriate measure of costs
avoided by purchase of power from that generator. As discussed above,
an avoided cost rate should reflect not only the cost of energy that
was avoided by the purchasing electric utility, but also the cost to
deliver the QF energy to the purchasing electric utility's load, such
that the total cost avoided is reflected in the rate. In an RTO/ISO
market, a state appropriately is entitled to consider whether the cost
of delivery from the QF node to the load node (including any redispatch
costs necessary to facilitate such delivery over a system that is
otherwise constrained between those nodes) should be reflected in the
LMP at the QF supply node. In instances commenters refer to where
transmission constraints prevent a generator from delivering power to a
specific node, we disagree that such delivery is actually
``prevented.'' Rather, redispatch of system resources would be
necessary to facilitate the delivery, and the respective LMPs reflect
those redispatch costs.
163. We also reject the argument made by NIPPC, CREA, REC, and
OSEIA that the 2000-01 California market demonstrated that volatile
short-term markets can reach extreme and unpredictable highs under
stress conditions.\255\ First we note that, in the wake of the 2000-
2001 California energy crisis, all RTO/ISO markets developed more
comprehensive ex ante market power mitigation measures than existed in
CAISO at that time, including offer caps and reference level
replacement offers, meant in part to moderate such extremes.\256\ In
any event, any price volatility that may currently exist in LMP
markets, regardless of the reason for the price volatility, and
regardless of whether the volatility causes LMPs to be lower or higher,
nevertheless accurately represents the avoided cost of the purchasing
electric utilities in those markets in those hours, as explained
elsewhere in this final rule.
---------------------------------------------------------------------------
\255\ NIPPC, CREA, REC, and OSEIA Comments at 57. Curiously,
these commenters here essentially take the position that higher LMPs
and resulting higher avoided cost energy rates, which would normally
seem to be beneficial to QFs, are instead now anathema.
\256\ See generally Wholesale Competition in Regions with
Organized Elec. Mkts., Order No. 719, 125 FERC ] 61,071 (2008),
order on reh'g, Order No. 719-A, 128 FERC ] 61,059, order on reh'g,
Order No. 719-B, 129 FERC ] 61,252 (2009).
---------------------------------------------------------------------------
164. Finally, we remain convinced that Congress recognized that
RTO/ISO LMP pricing provides sufficient encouragement for QFs through
the enactment of PURPA section 210(m) with its directive that,
essentially, the mandatory purchase obligation can be lifted upon QFs
having non-discriminatory access to RTO/ISO markets. As noted earlier,
however, our decision to grant states the flexibility to rely on a
rebuttable presumption that RTO/ISO LMP pricing is an appropriate
measure of avoided energy costs (and thus set as-available energy rates
in reliance on LMPs) reflects our view that, in RTO/ISO markets, as a
general matter LMP indeed accurately represents the purchasing electric
utility's avoided energy costs.
165. We also disagree with ELCON's \257\ argument that LMP should
not be used to measure avoided costs because that would allow states to
ignore long-standing factors established by the Commission that should
be used to determine avoided costs. The factors referenced by ELCON are
relevant to the traditional administrative determination of avoided
cost, and our revisions to the regulations preserve these factors for
that purpose and for avoided capacity costs. If a state chooses instead
to rely on LMP to set avoided energy cost rates, then it will
necessarily not be using those administrative means of determining
avoided costs, and these factors thus will not be relevant.
---------------------------------------------------------------------------
\257\ ELCON Comments at 23-24.
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166. We are not persuaded by the arguments of various commenters
that LMP cannot be used for avoided cost rates because it ignores the
unique municipal infrastructure role and the multiple benefits of the
community of biogas facilities,\258\ including the value of renewable
baseload energy, greenhouse gas mitigation, landfill diversion,
reliable and resilient power and other benefits of small baseload
QFs.\259\ PURPA frames the determination of QF rates in terms of
avoided cost and does not authorize the Commission in determining QF
rates, particularly as-available energy rates, to consider non-energy-
related factors such as a generator's unique municipal infrastructure
role, greenhouse gas mitigation, and landfill diversion.
---------------------------------------------------------------------------
\258\ Biogas Comments at 2.
\259\ Covanta Comments at 8.
---------------------------------------------------------------------------
167. We also are not persuaded by the argument of CA Cogeneration
that LMP may not represent a truly competitive price for electricity in
California since the majority of California supply is through bilateral
contracts, not through competitive bidding in the market, and that
other factors also distort LMP such as roof top solar. CA Cogeneration,
in essence, objects to the state of California's decision to award
preferred resource status to some resources, such as solar and wind,
and not others, such as cogeneration. These are procurement decisions
made at the state level in connection with resource planning and retail
ratemaking. Even if those decisions impact the resulting LMPs, as CA
Cogeneration claims, that impact would not invalidate the arguments
made above for why LMP is presumptively an appropriate measure of as-
available energy avoided costs in RTO/ISO markets. The aggrieved entity
would be able to challenge the state's decision to rely on LMP in the
appropriate forum, which could include any one or more of the
following: (1) Initiating or participating in proceedings before the
relevant state commission or governing body; (2) filing for judicial
review of any state regulatory proceeding in state court (under PURPA
section 210(g)); or, alternatively (3) filing a petition for
enforcement against the state at the Commission and, if the Commission
declines to act, later filing a petition against the state in U.S.
district court (under PURPA section 210(h)(2)(B)).\260\
---------------------------------------------------------------------------
\260\ See Policy Statement Regarding the Commission's
Enforcement Role Under Section 210 of the Public Utility Regulatory
Policies Act of 1978, 23 FERC ] 61,304.
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[[Page 54662]]
168. We reject the argument made by New England Small Hydro that
the Commission has not supported its view that LMP is an accurate
measure of avoided costs since LMP ignores the costs that the utility
pays to procure power, including through competitive solicitations,
other power contracts, planned retirements and other factors that are
considered in a utility's long-term plans; and ignores the fact that
LMP and the default service rates that exist in ISO-NE-based states are
quite different.\261\ The costs that a purchasing utility pays to
procure power, including through competitive solicitations, other power
contracts, planned retirements and other factors that are considered in
a utility's long-term plans may be relevant to the utility's purchase
of capacity using long-term contracts, but not to the determination of
the proper as-available energy avoided cost rate to be paid to QFs,
which rates will necessarily vary as system conditions vary over time,
as reflected by variances in LMP over time. The fact that LMP and the
default service rates that exist in ISO-NE-based states may diverge is
to be expected because the latter, unlike the as-available energy rates
charged by QFs in RTO/ISO markets that LMP is being used to price,
normally include transmission and distribution costs (and possibly firm
supplier capacity costs) necessary to ensure that firm supply is
continually available to residential customers.\262\ While utilities or
state regulatory authorities continue to have the authority to
establish and maintain long-term avoided energy forecasts upon which QF
PURPA power purchase rates may be based, and to recognize the actual
future energy costs incorporated in new power contracts that are being
signed by New England utilities, elsewhere in this final rule the
Commission explains why the use of variable prices can be appropriate
for long-term energy contracts.
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\261\ New England Small Hydro Comments at 8-10.
\262\ Compare ISO-NE, Transmission, Markets, and Services
Tariff, LMPs and Real-Time Reserve Clearing Prices Calculation,
Sec. III.2.5 (describing how nodal real-time prices are calculated
in ISO-NE at each node using energy offers and bids, transmission
constraints, and other factors) with National Grid, Investigation as
to the Propriety of Proposed Tariff Changes, Docket No. DPU 18-150,
Exh. NG-HSG-1, Gorman Test. 3:18-4:6 (Nov. 15, 2018), https://fileservice.eea.comacloud.net/FileService.Api/file/FileRoom/10043215
(``The Company's filing is based on its investments and costs
incurred to provide distribution service to its customers. An
[Allocated Cost of Service Study] directly assigns or allocates each
element of the revenue requirement, including plant and other
investments, operating expenses, depreciation and taxes, among the
rate classes, in order to determine the costs of providing service
to each rate class. Each element of the total revenue requirement is
analyzed and assigned to or allocated among the rate classes, so the
utility can establish rates that, subject to assumptions such as
kilowatt-hour (`kWh') delivery volumes and the number of customers,
provide it with a fair opportunity to recover its costs and to earn
an appropriate return.'').
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169. We are not persuaded by the argument of Southeast Public
Interest Organizations that the NOPR does not establish a framework for
just and reasonable and nondiscriminatory rates because the proposed
avoided cost methodology does not take into account any long-term or
seasonal purchases made from third parties or affiliates, adjustments
for transmission and distribution losses, capacity deferrals, avoided
environmental compliance costs, or dispatchability of the QF.\263\ LMP
pricing, in fact, does reflect transmission and distribution losses.
The other factors that the Southeast Public Interest Organizations
mention here, such as environmental compliance costs, dispatchability,
long-term or seasonal purchases and capacity deferrals, are factors
that are more applicable to the pricing of capacity and long-term
contracts, not the pricing of as-available energy, which is what the
Commission's NOPR proposal as adopted in this final rule addresses.
---------------------------------------------------------------------------
\263\ Southeast Public Interest Organizations Comments at 22.
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170. The Commission rejects the argument made by Biological
Diversity \264\ that LMP pricing ignores the variability of conditions
across the country. LMP prices by definition vary as supply, demand,
and system conditions change across the country. In any event, the
Commission agrees that LMP pricing would not currently be applicable in
regions like the Southeast that lack RTOs and ISOs and thus that do not
use LMP.
---------------------------------------------------------------------------
\264\ Biological Diversity Comments at 8-9.
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171. We further reject the argument made by ENGIE that allowing
states to set energy rates using LMPs combined with the ability to set
capacity rates at zero if it is determined that a utility has no need
for capacity has the potential to allow traditional utilities to corner
the market on capacity, leaving smaller independent QFs to provide only
energy-only service.\265\ PURPA does not direct the Commission to
guarantee that QF sales make up some specified share of utilities'
capacity needs nor does it require that each QF receive compensation
for providing capacity. PURPA instead focuses on the purchasing
electric utility's avoided costs and provides that the Commission
cannot require that prices charged by a QF exceed the purchasing
electric utility's avoided cost, if a purchasing electric utility has
no need for additional capacity (and thus the purchasing utility's
avoided cost for capacity would be zero),\266\ the only service that
QFs (and other suppliers) would need to provide that utility is energy.
However, a utility's ability to ``corner the market'' on capacity
depends not uniquely on the pricing of QF sales to the utility, but on
a host of factors including the utility's analysis of its need for
capacity and, without a specific inquiry into the circumstances of each
utility, it cannot be concluded that any utility's decision will always
be deficient or that it has been adversely and inappropriately affected
by the Commission's action here.
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\265\ ENGIE Comments at 4.
\266\ See, e.g., NOPR, 168 FERC ] 61,184 at P 33 n.58; see also
City of Ketchikan, Alaska, 94 FERC ] 61,293 at 62,061 (2001)
(``[A]voided cost rates need not include the cost for capacity in
the event that the utility's demand (or need) for capacity is zero.
That is, when the demand for capacity is zero, the cost for capacity
may also be zero.'').
---------------------------------------------------------------------------
172. Several commenters maintain that reliance on LMP will make it
difficult for QFs to obtain financing.\267\ This argument is addressed
below in section IV.B.7 of this final rule.
---------------------------------------------------------------------------
\267\ Biogas Comments at 2; BluEarth Renewables Comments at 2;
Biological Diversity at 8; Covanta Comments at 9; Distributed Sun
Comments at 1-2; New England Small Hydro Comments at 10; NIPPC,
CREA, REC, and OSEIA Comments at 53.
---------------------------------------------------------------------------
ii. Requests for Modification or Clarification of the NOPR
173. We will not provide the clarifications requested by New
England Small Hydro that the Commission require the use of the day-
ahead LMP for QF rates set at LMP, or Southeast Public Interest
Organizations' request to require the use of real-time LMP rather than
average LMP. States that choose to use LMP will determine the LMP most
representative of the avoided cost of the relevant purchasing utility.
174. While the Kentucky Commission requests that the Commission
allow the use of the LMP at a delivery (load) node rather than a
receipt (generator or QF) node, we find that this decision should be
made by the state as it determines which particular LMP best reflects
the avoided cost of the purchasing electric utility.
175. We grant APPA's request for clarification that, while the NOPR
provides greater clarity as to states' entitlement to rely on
competitively-set prices as a measure of avoided cost rates, nothing in
the final rule is intended to call into question any particular state's
existing implementation of PURPA's avoided cost requirements, such as
their existing use of LMP.\268\ While in the past a state
[[Page 54663]]
may have been able to conclude that LMP was an appropriate measure of
the avoided cost for energy, a state can now also rely on a rebuttable
presumption that LMP is an appropriate measure of the as-available
avoided cost for energy to be used in determining a QF's as-available
avoided cost energy rate.
---------------------------------------------------------------------------
\268\ APPA Comments at 9.
---------------------------------------------------------------------------
176. We provide the following clarification in response to the
Solar Energy Industries' request that the Commission make clear that
payments based on LMP do not relieve the purchasing utility of the
requirement to compensate the QF for any values in addition to
electricity (e.g., RECs, etc.), and that the state's flexibility to
allow utilities to set QF payment rates for as-available energy at the
applicable LMP does not in any way limit QFs' rights to establish a LEO
or contract for a longer-term sale at fixed, full avoided costs.\269\
In Windham Solar LLC,\270\ the Commission summarized its precedent
concerning RECs. The Commission stated that the states have the
authority to determine who owns RECs in the initial instance and how
they are transferred, and that the automatic transfer of RECs within a
sale of power at wholesale must find its authority in state law, not
PURPA. But the Commission also held that a state may not assign
ownership of RECs to utilities based on a logic that the avoided cost
rates in PURPA contracts already compensate QFs for RECs in addition to
compensating QFs for energy and capacity, because under PURPA the
avoided cost rates are, in fact, compensation just for energy and
capacity.\271\ We see no reason to disturb that precedent in this final
rule. With regard to the right of QFs to establish a LEO, that right is
neither limited nor expanded by a state's choice of LMP as the measure
of avoided costs for energy.
---------------------------------------------------------------------------
\269\ Solar Energy Industry Comments at 27-28.
\270\ 156 FERC ] 61,042 (2016).
\271\ Id. P 4.
---------------------------------------------------------------------------
iii. Western EIM
177. We hereby find that the Western EIM prices, like other LMP
prices, may presumptively be used as a measure of as-available energy
avoided costs for utilities able to participate in the Western EIM
market. As Xcel points out, ``prices in the EIM are calculated using
the same methodology as LMPs'' since, ``in both cases, units are
dispatched on a least-cost basis that respects applicable transmission
constraints (i.e., congestion),'' and ``[t]he formula for price
calculation involves determination of the system marginal energy cost,
which is the cost of providing the next increment of energy to the
system, minus congestion costs, minus losses, and, in some cases, minus
the cost of carbon.'' \272\ As with LMP, these Western EIM price
components presumptively reflect the avoided cost of as-available
energy incurred by purchasing electric utilities that are able to
participate in the Western EIM region.
---------------------------------------------------------------------------
\272\ Xcel Comments at 7-8.
---------------------------------------------------------------------------
178. We reject arguments that Western EIM prices should not be used
to establish as-available avoided cost energy rates for sales by QFs.
With respect to the unit commitment and dispatch scheduling cost
parameters ELCON refers to, it is true that the Western EIM is a real-
time imbalance market built on a decentralized unit commitment that may
not result in exactly the same real-time dispatch and LMP as would
result from an RTO market with centralized day-ahead unit commitment
and co-optimized energy and reserves. Nonetheless, Western EIM prices
represent quite precisely the avoided cost of as-available energy for
utilities operating in that market structure since those prices show
the cost of obtaining an additional unit of energy at any particular
place and time. With regard to the argument of Union of Concerned
Scientists concerning the cost recovery mechanisms available to
utility-owned and -affiliated generation,\273\ as discussed above with
respect to the rebuttable presumption that LMP may be used for avoided
cost rate determination, we do not find these unproven allegations of
use of retail cost recovery mechanisms to subsidize wholesale RTO/ISO
market participation at a loss sufficient to make a blanket finding
prohibiting the use of Western EIM prices to set as-available avoided
cost energy rates for sales by QFs.
---------------------------------------------------------------------------
\273\ Union of Concerned Scientists Comments at 9.
---------------------------------------------------------------------------
179. With regard to the argument concerning the ability to
participate in the Western EIM raised by Solar Energy Industries,\274\
for PURPA rate purposes, it is not relevant whether QFs are able to
participate in the Western EIM. The rates at issue here are intended,
per the statute, to reflect the costs of alternative electric energy
that the purchasing utility is avoiding. In this context, all that
matters is whether the Western EIM's prices accurately reflect a
purchasing electric utility's avoided costs for energy. Thus, as long
as the purchasing electric utility is able to participate in the
Western EIM, a rebuttable presumption should apply that Western EIM
prices reflect the purchasing electric utility's avoided costs for
energy.
---------------------------------------------------------------------------
\274\ Solar Energy Industry Comments at 27.
---------------------------------------------------------------------------
4. Use of Market Hub Prices as a Permissible Rate for Certain As-
Available QF Energy Sales
a. NOPR Proposal
180. In the NOPR, the Commission recognized that competitive
bilateral energy markets have arisen outside of the RTO/ISO energy
markets. Particularly in the Western United States, price hubs such as
the Mid-Columbia (Mid-C) and Palo Verde hubs are liquid markets with
prices the Commission has recognized as representing competitive market
prices at those hubs.\275\ For the same reasons that LMPs could
represent an appropriate avoided cost energy rate for QFs selling to
electric utilities located in RTO/ISO markets, the Commission proposed
to find that liquid market hubs can represent appropriate rates for QFs
selling to electric utilities located outside of RTO/ISO markets. Like
LMP, liquid market hubs would rely on competition to derive an avoided
cost. From a price determination perspective, liquid market hub prices
differ from LMP mainly in that they measure price at only one or a few
points, whereas RTOs/ISOs derive unique LMPs for all receipt and
delivery points on a specific area of the system.\276\
---------------------------------------------------------------------------
\275\ NOPR, 168 FERC ] 61,184 at P 52 (citing Price Discovery in
Nat. Gas and Elec. Mkts., 109 FERC ] 61,184, at P 66 (2004)
(approving the use of published prices at market hubs with
sufficient liquidity to set prices charged in tariffs); El Paso
Elec. Co., 148 FERC ] 61,051, at P 7 (2014) (approving the use of
the Palo Verde price to set imbalance charges); Idaho Power Co., 121
FERC ] 61,181 at P 27 (2007) (approving use of Mid-Columbia prices
to set energy imbalance charge); PacifiCorp, 95 FERC ] 61,467, at
62,676 (2001) (approving setting energy imbalance rate at average of
four market hub prices); Pinnacle West Energy Corp., 92 FERC ]
61,248, at 61,791 (2000) (accepting the use of the Palo Verde price
to set prices for affiliate transactions because the Palo Verde
Index is a recognized market hub with competitive prices)).
\276\ NOPR, 168 FERC ] 61,184 at P 53.
---------------------------------------------------------------------------
181. Consequently, the Commission proposed in the NOPR to revise
the PURPA Regulations in 18 CFR 292.304 to add a subsection (b)(7)
which, in combination with new subsection (e)(1), would permit a state
to set the as-available energy rate paid to a QF by electric utilities
located outside of RTO/ISO markets at energy rates established at
liquid market hubs. The Commission proposed to define Market Hub Prices
as prices determined at a liquid market hub to which the purchasing
electric utility has reasonable access. States electing to set QF
energy rates using a Market Hub Price also would identify the
particular market hub used to set the
[[Page 54664]]
price. Such determination would require the state to find that the
prices at such hub are competitive prices that reflect the costs an
electric utility would avoid but for the purchase from the QF.\277\
---------------------------------------------------------------------------
\277\ Id. P 56.
---------------------------------------------------------------------------
b. Comments
i. Comments in Support
182. Arizona Public Service and El Paso Electric state that the
Palo Verde/Hassayampa hub represents a regional liquid market hub that
could be used to set as-available energy avoided costs.\278\ Portland
General likewise asserts that the Mid-C price hub should be approved as
appropriate for use in establishing as-available energy avoided
costs.\279\
---------------------------------------------------------------------------
\278\ Arizona Public Service Comments at 6-8; El Paso Electric
Comments at 2-3.
\279\ Portland General Comments at 6-7.
---------------------------------------------------------------------------
183. Xcel provides two additional factors to support the liquid
market hub proposal. First, Xcel cites to the 2018 State of the Market
report issued by the Commission's Office of Enforcement's Division of
Energy Market Oversight, which states that trading hub prices generally
align with energy prices associated with competitive, market-based
sales. Second, Xcel cites to wholesale power sales contracts providing
for the purchase of excess energy based on a combination of day-ahead
prices at Palo Verde and at Four Corners, which Xcel asserts
demonstrates that prices at Palo Verde and Four Corners are reasonably
representative of the value of energy.\280\
---------------------------------------------------------------------------
\280\ Xcel Comments at 8.
---------------------------------------------------------------------------
ii. Comments in Opposition
184. Several commenters argue that liquid market hubs are short-
term spot markets and do not represent long-term energy rates or the
other costs associated with that energy including, but not limited to,
congestion, transmission, and capacity costs.\281\ Other commenters
express concern with setting QF prices at short-term liquid hub prices
while allowing utilities to rate base and recover their long-term
investments.\282\
---------------------------------------------------------------------------
\281\ IdaHydro Comments at 11; Southeast Public Interest
Organizations Comments at 19.
\282\ IdaHydro Comments at 11; Industrial Energy Consumers
Comments at 12-13.
---------------------------------------------------------------------------
185. Public Interest Organizations assert that the liquid market
hub proposal is discriminatory because non-QF generators are not
limited to the liquid market hub price and utilities can, and regularly
do, pay effective prices for energy that exceed the price determined by
regional trading.\283\ Union of Concerned Scientists similarly asserts
that liquid market hub prices are distorted by the participation of
integrated utilities that submit bids below their total costs.\284\
---------------------------------------------------------------------------
\283\ Public Interest Organizations Comments at 64.
\284\ Union of Concerned Scientists Comments at 8.
---------------------------------------------------------------------------
186. Industrial Energy Consumers oppose the liquid market hub
pricing proposal because such markets are not sufficiently competitive,
nondiscriminatory, and transparent to be used as the basis for
calculating a utility's avoided cost payment.\285\ Industrial Energy
Consumers urge the Commission not to assume that non-competitive
markets are, in fact, competitive.\286\ Southeast Public Interest
Organizations state that no southeast state could credibly identify a
particular market hub that is reasonably accessible and has competitive
prices that actually relate to the costs an electric utility would
avoid but for the purchase from the QF.\287\ Southeast Public Interest
Organizations also assert that the liquid market hub proposal does not
require states to determine whether liquid market hub prices represent
a utility's avoided costs, and therefore the proposal would allow
liquid market hubs to set avoided energy prices even when they do not
represent avoided energy costs.\288\
---------------------------------------------------------------------------
\285\ Industrial Energy Consumers Comments at 12.
\286\ Id.
\287\ Southeast Public Interest Organizations Comments at 18.
\288\ Id. at 19.
---------------------------------------------------------------------------
187. ELCON asserts that a liquid regional hub does not necessarily
imply liquidity at a more granular level.\289\ According to ELCON, the
basis spread resulting from transmission congestion outside of RTO/ISOs
is often opaque in real time and poorly documented in hindsight, and
this is a clear indication that discriminatory treatment and barriers
to the bulk transmission system persist under current conditions
outside of RTO/ISOs.\290\ ELCON states that for these and other
reasons, bilateral markets alone are insufficient to serve as complete
avoided cost measures.\291\
---------------------------------------------------------------------------
\289\ ELCON Comments at 25.
\290\ Id.
\291\ Id.
---------------------------------------------------------------------------
188. Allco states that prices at liquid market hubs would suffer
from shortcomings with respect to small QFs connected to the
distribution system, because purchases from such QFs also allow the
purchasing utility to avoid transmission costs, including line
losses.\292\
---------------------------------------------------------------------------
\292\ Allco Comments at 7-8.
---------------------------------------------------------------------------
iii. Commission Determination
189. We adopt the proposal in the NOPR to give the states
flexibility to set as-available avoided cost energy rates using prices
from a liquid market hub to which the purchasing electric utility has
reasonable access. For the reasons explained in the NOPR, we find that
liquid market hubs can represent appropriate as-available avoided cost
energy rates for QFs selling to electric utilities located outside of
RTO/ISO markets. However, as the Commission also found in the NOPR,
before relying on prices from liquid market hubs, a state must find
that the liquid market hub price in question represents the purchasing
utility's avoided cost for as-available energy.\293\
---------------------------------------------------------------------------
\293\ See NOPR, 168 FERC ] 61,184 at PP 53, 56.
---------------------------------------------------------------------------
190. Examples of factors a state reasonably could consider in
making this determination (in addition to the core finding that the
liquid market hub represents the purchasing utility's avoided cost for
as-available energy) are: (1) Whether the hub is sufficiently liquid
that prices at the hub represent a competitive price; \294\ (2) whether
the prices developed at the hub are sufficiently transparent; (3)
whether the electric utility has the ability to deliver power from such
hub to its load, even if its load is not directly connected to the hub;
and (4) whether the hub represents an appropriate market to derive an
energy price for the electric utility's purchases from the relevant QFs
given the electric utility's physical proximity to the hub. These
factors are not intended to be exhaustive, and states reasonably could
consider other factors in identifying a relevant liquid market hub for
setting as-available QF energy rates.
---------------------------------------------------------------------------
\294\ In considering whether a hub is sufficiently liquid,
states could, for example, consider such factors as those identified
by the Commission in Price Discovery in Nat. Gas and Elec. Mkts.,
109 FERC ] 61,184, at P 66.
---------------------------------------------------------------------------
191. In order for prices at market hubs to represent a purchasing
electric utility's avoided costs, the market hub price may need to be
subject to adjustments to account for transmission costs the electric
utility would incur before such prices could serve as a factor in
determining appropriate QF rates.\295\ In addition, market prices in a
region may be determined based on a formula that includes adjustments
to the market hub price or that incorporates prices at more than one
market hub located in the region, when such prices represent standard
pricing practice in the region where the purchasing electric utility is
located.\296\ Such adjustments may be necessary to ensure that the
[[Page 54665]]
competitive market price reflects a purchasing utility's actual avoided
costs for as-available energy.
---------------------------------------------------------------------------
\295\ Other adjustments also may be necessary in other
situations in order for the adjusted hub price to reasonably reflect
the purchasing electric utility's avoided cost.
\296\ NOPR, 168 FERC ] 61,184 at P 58.
---------------------------------------------------------------------------
192. Arguments regarding the short-term nature of liquid market
hubs and claims that use of such prices is discriminatory are addressed
in Section IV.B.2 above.
193. We will not address in this final rule arguments about whether
particular market hubs should be found to represent avoided costs or,
to the contrary, that particular market hubs may be too illiquid or
insufficiently granular, or that prices at particular market hubs may
not reflect avoided costs. We are not making any determination in this
final rule that the prices at any specific market hub do or do not
represent the avoided costs of any specific utility. Rather, we are
allowing the states the flexibility to rely on prices at liquid market
hubs to set as-available avoided cost energy rates for QF sales in
regions outside RTO/ISO markets upon a state finding that it is
appropriate to do so given the specific circumstances governing a
particular market hub and the purchasing utility involved. The
aggrieved entity would be able to challenge the state's decision to use
a liquid market hub price in the appropriate forum, which could include
any one or more of the following: (1) Initiating or participating in
proceedings before the relevant state commission or governing body; (2)
filing for judicial review of any state regulatory proceeding in state
court (under PURPA section 210(g)); or, alternatively (3) filing a
petition for enforcement against the state at the Commission and, if
the Commission declines to act, later filing a petition against the
state in U.S. district court (under PURPA section 210(h)(2)(B)).\297\
---------------------------------------------------------------------------
\297\ See Policy Statement Regarding the Commission's
Enforcement Role Under Section 210 of the Public Utility Regulatory
Policies Act of 1978, 23 FERC ] 61,304.
---------------------------------------------------------------------------
194. With respect to Southeast Public Interest Organizations'
assertion that the liquid market hub proposal in the NOPR does not
require states to determine whether liquid market hub prices represent
a utility's avoided costs, the Commission intended to impose such a
requirement as a prerequisite before a liquid market hub may be relied
on as a measure of a purchasing utility's avoided cost of as-available
energy. However, we acknowledge that the regulatory text in the NOPR
was ambiguous in that regard. Therefore, the regulatory text of 18 CFR
292.304(b)(7)(i) in the final rule has been revised to make this more
clear.
c. Proposed Modifications
i. Comments
195. APPA requests that the Commission clarify that, in addition to
liquid market hubs, as-available energy avoided costs could be
determined based on prices of comparable competitive quality.\298\ APPA
states that amending the proposed regulation in this fashion would also
enable utilities proximate to (or embedded within) RTO/ISO markets to
reference prices in those markets as viable alternatives in
establishing avoided costs.\299\
---------------------------------------------------------------------------
\298\ APPA Comments at 13.
\299\ Id. at 13.
---------------------------------------------------------------------------
196. The California Commission requests that the Commission clarify
that states previously were permitted to use liquid market hub prices
under the current PURPA Regulations and that the proposed revisions
simply codify and confirm the validity of this past practice.\300\ The
California Commission and Massachusetts DPU further request that the
proposed rules be modified to permit states to use competitive prices
to set both energy and capacity costs, and to not be limited to using
such mechanisms only for as-available energy prices.\301\
---------------------------------------------------------------------------
\300\ California Commission Comments at 24.
\301\ California Comments at 25; Massachusetts DPU Comments at
8-10.
---------------------------------------------------------------------------
197. EEI notes that some states may be located in regions with
access to more than one market hub and those states should have the
flexibility to use an average of market hub prices or develop a formula
correlated to the appropriate market hubs to develop the electric
utility's avoided cost.\302\ EEI notes that this proposal is not new,
but its inclusion in the Commission's regulations will provide
certainty to states.\303\
---------------------------------------------------------------------------
\302\ EEI Comments at 26.
\303\ Id. at 27.
---------------------------------------------------------------------------
198. NIPPC, CREA, REC, and OSEIA assert that the liquid market hub
proposal should not be adopted without making significant changes.\304\
For example, they argue, only long-term contract prices reported at
market hubs should be used.\305\ Even with respect to market-hub prices
for long-term contracts, they assert that the Commission should include
safeguards to ensure that prices are set based on liquid trading with a
sufficient number of competitors to assure effective price discovery,
that prices are not subject to manipulation, and that reported price
indices are accurate and not subject to mis-reporting or other forms of
manipulation.\306\ Finally, they argue that the Commission should
require avoided costs to include the costs of transmission to and from
such hubs except in cases where the utility's system directly
interconnects with that hub.\307\ Resources for the Future makes
similar arguments.\308\
---------------------------------------------------------------------------
\304\ NIPPC, CREA, REC, and OSEIA Comments at 60.
\305\ Id.
\306\ Id.
\307\ Id.
\308\ Resources for the Future Comments at 8.
---------------------------------------------------------------------------
199. In contrast, NorthWestern asserts that liquid market hub
prices should be adjusted downward by a transmission differential to
reflect the cost of getting energy from the market to load.\309\
NorthWestern states that reliance on the market hub to establish
avoided costs only remains a valid option if the prices are less than
what it would cost a utility to build a resource to supply its
customers' needs.\310\
---------------------------------------------------------------------------
\309\ NorthWestern Comments at 5.
\310\ Id.
---------------------------------------------------------------------------
ii. Commission Determination
200. We clarify that, in adopting a rule allowing states to use
liquid market hubs to determine as-available avoided energy costs, we
are not finding that the use of liquid market hubs for this purpose
prior to the issuance of this final rule was not permitted. Depending
on the specific circumstances, a state may appropriately have
determined, prior to the final rule, that a liquid market hub price
represented a purchasing utility's as-available avoided energy cost.
After the effective date of this final rule, an aggrieved entity may
seek review of a state's determination to use liquid market hubs in the
appropriate forum.\311\
---------------------------------------------------------------------------
\311\ See Policy Statement Regarding the Commission's
Enforcement Role Under Section 210 of the Public Utility Regulatory
Policies Act of 1978, 23 FERC ] 61,304.
---------------------------------------------------------------------------
201. We confirm that: (1) States located in regions with access to
more than one market hub have the flexibility to use an appropriate
average of market hub prices or to develop an appropriate formula that
relies on data from relevant market hubs to develop an electric
utility's as-available avoided energy cost, so long as doing so yields
a price that accurately reflects the purchasing electric utility's as-
available avoided energy cost; \312\ (2) states must determine that a
liquid market hub is sufficiently liquid that its prices represent a
competitive price; \313\ and (3) the market hub price may need to be
subject to adjustments to account for transmission costs the electric
utility would incur.\314\
---------------------------------------------------------------------------
\312\ NOPR, 168 FERC ] 61,184 at P 58.
\313\ Id. P 57.
\314\ Id. P 58.
---------------------------------------------------------------------------
[[Page 54666]]
202. Finally, we find that the general ruling requested by APPA
regarding the use of ``prices of comparable competitive quality'' to
set as-available avoided cost rates is beyond the scope of this
rulemaking in that here we were proposing only particular discrete
changes to our regulations for setting as-available avoided cost energy
rates charged by QFs.
5. Use of Formulas Based on Natural Gas Prices To Establish a
Permissible Rate for Certain As-Available QF Energy Sales
a. NOPR Proposal
203. The Commission observed in the NOPR that, in regions where
there are no RTOs/ISO or liquid market hubs, the price of electricity
generated by efficient combined-cycle natural gas generation facilities
would appear to represent a reasonable measure of a competitive energy
price.\315\
---------------------------------------------------------------------------
\315\ Id. P 59.
---------------------------------------------------------------------------
204. The Commission therefore proposed to revise the PURPA
Regulations in 18 CFR 292.304 to add a subsection (b)(7) which, in
combination with new subsection (e)(1), would permit a state to set the
as-available energy rate paid to a QF by electric utilities located
outside of RTO/ISO markets at Combined Cycle Prices, defined as a
formula rate established by the state using published natural gas price
indices and a proxy heat rate for an efficient natural gas combined-
cycle generating facility. The state would need to determine that the
resulting Combined Cycle Price represents an appropriate approximation
of the purchasing electric utility's avoided costs. This determination
would involve consideration of such factors as, for example: (1)
Whether the cost of energy from an efficient natural gas combined-cycle
generating facility represents a reasonable approximation of a
competitive price in the purchasing electric utility's region; (2)
whether natural gas priced in accordance with a particular proposed
natural gas price index would be available in the relevant market; (3)
whether there should be an adjustment to the natural gas price to
appropriately reflect the cost of transporting natural gas to the
relevant market; and (4) whether the proxy heat rate used in the
formula should be updated regularly to reflect improvements in
generation technology. The Commission described the above factors as
not exhaustive and proposed providing states the flexibility to apply
other factors that also might be appropriate for consideration.\316\
---------------------------------------------------------------------------
\316\ Id.
---------------------------------------------------------------------------
205. The Commission stated that natural gas price indices coupled
with the heat rate of an efficient natural gas combined-cycle
generating facility may be a reasonably accurate measure of avoided
cost, at least in those markets where natural gas-fired resources are
commonly the marginal units. In such markets, the Commission stated
that it would expect that new supplies of energy would need to be
offered at a price equal to or less than the incremental cost of using
these efficient gas units in order to displace them economically. Thus,
the Commission found preliminarily that using natural gas price indices
and the heat rate of an efficient combined-cycle natural gas generating
facility to establish an avoided cost energy rate relies on competitive
market forces, in this case competitive forces in natural gas markets
for the fuel used by natural gas combined-cycle generating facilities
that the purchasing electric utility, but for the purchase from the QF,
would generate itself or purchase from another source.\317\
---------------------------------------------------------------------------
\317\ Id. P 54.
---------------------------------------------------------------------------
b. Comments
206. Several entities oppose the NOPR's Combined Cycle Prices
proposal.\318\ Allco asserts that this is exactly the type of
administrative avoided cost determination about which NARUC and
utilities have complained.\319\ Allco also argues that the only reason
for including the Combined Cycle Prices proposal in the Commission's
regulations is to create a menu of prices from which a state commission
or unregulated utility can choose the lowest price, which Allco claims
would not encourage QF generation, and would be inconsistent with the
rules of economic dispatch and the language of PURPA.\320\ Public
Interest Organizations argue that the Combined Cycle Price proposal is
discriminatory to QFs for all the same reasons that restricting QF
rates to LMP is discriminatory (i.e., because utilities can, and
allegedly do, pay effective prices for energy that exceed the
calculation from natural gas prices and assumed combined cycle heat
rates).\321\ Southeast Public Interest Organizations argue that the
Combined Cycle Prices proposal does not require states to include
variable O&M costs in the proxy combined cycle plant or an adjustment
for natural gas transportation, even though a utility-owned combined
cycle gas plant would be allowed to recover both types of costs.\322\
---------------------------------------------------------------------------
\318\ Allco Comments at 8; BluEarth Comments at 1-2; ELCON
Comments at 25-26; Industrial Energy Consumers Comments at 10-11;
Public Interest Organizations Comments at 64; R Street Comments at
5; Southeast Public Interest Organizations Comments at 19-20.
\319\ Allco Comments at 8.
\320\ Id.
\321\ Public Interest Organizations Comments at 64.
\322\ Southeast Public Interest Organizations Comments at 19-20.
---------------------------------------------------------------------------
207. In contrast, R Street opposes the proposal because using
natural gas combined cycle plants as the basis for QF rates in non-RTO/
ISO regions could lead to the overpayment of a QF. R Street argues that
regions without organized wholesale markets should instead price QF
rates at the lowest cost resource based on an administratively
determined avoidable cost.\323\
---------------------------------------------------------------------------
\323\ R Street Comments at 5.
---------------------------------------------------------------------------
208. Similarly, ELCON argues that the proposal is complicated by
the fact that natural gas units are not always marginal, especially in
export-constrained subregions when renewables output is high. ELCON
believes this proposal would be subject to extensive forecasting error,
and therefore argues that careful assessment should precede its
adoption.\324\
---------------------------------------------------------------------------
\324\ ELCON Comments at 26.
---------------------------------------------------------------------------
209. Other entities support the NOPR's Combined Cycle Price
proposal.\325\ The California Commission and EEI argue that states
already had this flexibility under the current regulations, and request
that the Commission acknowledge this fact in a final rule.\326\
Similarly, other supporters of the Combined Cycle Price proposal argue
that states should have the ability to develop as-available energy
price formulas based on technologies other than combine cycle gas
plants, if doing so would more accurately reflect the relevant
purchasing utility's avoided cost.\327\
---------------------------------------------------------------------------
\325\ APPA Comments at 12-13; Arizona Public Service Comments at
6; California Commission Comments at 23; Chamber of Commerce
Comments at 4; Duke Energy Comments at 9-10; EEI Comments at 27; El
Paso Electric Comments at 3; Idaho Commission Comments at 3;
Southern Comments at 9.
\326\ California Commission Comments at 23; EEI Comments at 27-
28.
\327\ APPA Comments at 13; Duke Energy Comments at 10; EEI
Comments at 27; Idaho Commission Comments at 3; Southern Comments at
9-11.
---------------------------------------------------------------------------
210. El Paso Electric argues that: (1) The gas index price should
be adjusted to account for the basis differential between the price at
the natural gas hub and the price of natural gas in or near the
utility's service area; and (2) states should be allowed to update the
formula periodically to reflect improved
[[Page 54667]]
efficiencies in combined cycle generating facilities.\328\
---------------------------------------------------------------------------
\328\ El Paso Electric Comments at 3-4.
---------------------------------------------------------------------------
c. Commission Determination
211. We adopt the NOPR proposal to revise 18 CFR 292.304 to add a
subsection (b)(7) which, in combination with new subsection (e)(1),
would permit a state to set the as-available energy rate paid to a QF
by electric utilities located outside of RTO/ISO markets at Combined
Cycle Prices, defined as a formula rate established by the state using
published natural gas price indices and a proxy heat rate for an
efficient natural gas combined-cycle generating facility. We also
clarify that the formulas used to set as-available energy rates based
on natural gas prices should include recovery of variable O&M costs.
212. While some commenters oppose allowing states to use Combined
Cycle Prices (or other competitive prices) to set avoided energy cost
rates, states already had the flexibility to determine avoided costs in
this manner under the current regulations, as the California Commission
and EEI observe.\329\ If Combined Cycle Prices accurately represent a
particular purchasing utility's avoided energy costs, their use would
be consistent with the Commission's existing definition of avoided
costs as ``the incremental costs to an electric utility of electric
energy or capacity or both which, but for the purchase from the
qualifying facility or qualifying facilities, such utility would
generate itself or purchase from another source.'' \330\ Furthermore,
as noted above in section IV.B.2, the use of competitive market prices,
including Combined Cycle Prices, to set QF rates is explicitly subject
to the requirement that such prices are equal to the purchasing
utility's avoided energy costs. Therefore, this proposal merely
codifies more explicitly an option for determining avoided cost rates
that already existed, i.e., where a state determines that a Combined
Cycle Price is a measure of the purchasing electric utility's avoided
cost for as-available energy.
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\329\ States could have used any of the competitive prices
adopted in this final rule to set avoided cost energy rates as long
as such prices met, to the extent practicable, the factors described
18 CFR 292.304(e).
\330\ See 18 CFR 292.101(b)(6).
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213. The concerns of R Street, ELCON, and others that Combined
Cycle Prices may not reflect a particular purchasing electric utility's
avoided cost are addressed by the requirement that the state would need
to determine that the Combined Cycle Price indeed represents the
purchasing electric utility's avoided cost for as-available energy.
214. While some commenters requested that we expand the proposed
regulation explicitly to include technologies other than combined cycle
natural gas generating facilities, we decline to do so for two reasons.
First, as already mentioned, the current regulations are already
flexible enough to accommodate states calculating avoided costs based
on the cost of the generating units or technology that accurately
reflects the relevant purchasing utility's avoided cost.\331\ Second,
this proposal focused specifically on combined cycle technology, as
opposed to other generating technologies, because combined cycle
generation makes up such a large portion of the nation's generation
fleet.\332\ This relative ubiquity, coupled with the fact that combined
cycle natural gas generation facilities are often the marginal units in
many regions, justifies an elevated profile in the PURPA Regulations
for combined cycle technology compared to other technologies. This
final rule does not foreclose other technologies from being used for
avoided cost determination, upon an appropriate finding by the state
that they accurately measure a purchasing electric utility's avoided
cost for as-available energy.
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\331\ See 18 CFR 292.101(b)(6).
\332\ According to EIA data, the nameplate capacity of natural
gas-fired combined cycle generation technology, exceeds the
nameplate capacity of generation from any other fuel source. See
EIA, Electric Power Annual Table 4.7.A Net Summer Capacity of
Utility Scale Units by Technology and by State, 2018 and 2017
(Megawatts), https://www.eia.gov/electricity/annual/html/epa_04_07_a.html, and 4.7.C Net Summer Capacity of Utility Scale
Units Using Primarily Fossil Fuels and by State, 2018 and 2017
(Megawatts), https://www.eia.gov/electricity/annual/html/epa_04_07_c.html.
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215. Southeast Public Interest Organizations support their
opposition to Combined Cycle Prices in part by claiming that the
Commission did not specifically require states to include variable O&M
in the formula. We agree that variable O&M expenses are an appropriate
cost component of formula rates and should be included in any Combined
Cycle Price formulae in order to accurately reflect the relevant
purchasing electric utility's avoided costs.
216. With respect to the arguments of Southeast Public Interest
Organizations regarding natural gas transportation costs, the
regulation we adopt in this final rule, 18 CFR 292.304(b)(7)(ii)(C),
specifically requires that states consider whether there should be an
adjustment to the natural gas price to appropriately reflect the cost
of transporting natural gas to the relevant market. As to El Paso
Electric's arguments regarding index price adjustments using basis
differentials, and periodic formula updates to reflect efficiency
improvements, we note that the revisions to the PURPA Regulations,
which we adopt in this final rule, provide that states which choose to
rely on Combined Cycle Prices must consider, when designing their
formulae, whether and to what extent to include these costs, based on
their assessment of how best to identify a relevant purchasing electric
utility's avoided cost for as-available energy.\333\
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\333\ See new 18 CFR 292.304(b)(7)(ii).
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6. 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
217. The NOPR noted that, 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. Accordingly, the NOPR suggested
that 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 proposed to add a new option in 18 CFR
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.\334\ In other words, states could rely on estimates of
forecasted energy prices at the time of delivery over the anticipated
life of the contract--such estimates are commonly referred to as
forward price curves--to develop a fixed energy rate component for that
contract when such estimates reflect the purchasing electric utility's
avoided costs.
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\334\ NOPR, 168 FERC ] 61,184 at P 61.
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218. The NOPR stated that 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).\335\ 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; however, the energy rate in the contract
could be different from year-to-
[[Page 54668]]
year (or some other period) and nevertheless comply with the current
requirement in 18 CFR 292.304(d)(2)(ii) that the energy rate be fixed
for the term of the contract.\336\
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\335\ Id. P 62 (noting that 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 (citing 18 CFR 292.304(e)(2)).
\336\ Id. (noting that this is permissible under the
Commission's existing PURPA Regulations (citing 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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a. Comments
219. Two commenters oppose the NOPR proposal to add a new option in
18 CFR 292.304(d)(1)(iii) permitting fixed energy rates to be based on
forecasted estimates of the stream of revenue flows during the life of
the contract.\337\ Southeast Public Interest Organizations and Mr.
Mattson state that the NOPR proposal is a departure from past
precedent.\338\ Southeast Public Interest Organizations state that this
proposal suffers the same deficiencies as the LMP and liquid market hub
price proposals. Furthermore, according to Southeast Public Interest
Organizations, the NOPR provides no analysis as to how or whether the
forward price curves result in just and reasonable and non-
discriminatory rates as required by PURPA.\339\
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\337\ Southeast Public Interest Organizations Comments at 25;
Mr. Mattson Comments at 26.
\338\ Southeast Public Interest Organizations Comments at 25;
Mr. Mattson Comments at 26.
\339\ Southeast Public Interest Organizations Comments at 25.
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220. Other commenters support the NOPR proposal to add a new option
in 18 CFR 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.\340\ The South Dakota Commission and Pennsylvania
Commission state that they support the NOPR proposal on forecasted
values of the estimated stream of revenues because it forecasts a
steady stream of revenue and provides built-in flexibility.\341\
According to these commenters, the proposal also balances the QF's need
for a steady stream of revenue with the purchasing electric utility's
responsibility to have a prudent mix of supply contracts for its
provider of last resort obligations.\342\ The Chamber of Commerce
states that, while future rates are not guaranteed to materialize, the
projected rates will more accurately reflect those realized than a
single avoided cost rate set at the inception of a QF contract.\343\
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\340\ Allco Comments at 8; APPA Comments at 14; Arizona Public
Service Comments at 2-3; Chamber of Commerce Comments at 4-5;
Connecticut Authority at 13; Distributed Sun Comments at 2; EEI
Comments at 28-30; Idaho Commission Comments at 4; NorthWestern
Comments at 6; NRECA Comments at 8; Pennsylvania Commission Comments
at 8; Resources for the Future Comments at 8; South Dakota
Commission Comments at 3.
\341\ Pennsylvania Commission Comments at 8-9; South Dakota
Commission Comments at 3.
\342\ Pennsylvania Commission Comments at 8-9.
\343\ Chamber of Commerce Comments at 4-5.
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221. Arizona Public Service states that it supports the proposal
because it grants states additional flexibility, which helps protect
utilities' customers from over-paying for generation due to QFs need
for sales guarantees and financing.\344\ NRECA agrees that states must
have flexibility in determining forecasted market prices including
appropriate discounting to ensure that utilities and consumers are not
locked into contracts with fixed prices that are higher than prevailing
market prices.\345\
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\344\ Arizona Public Service Comments at 2-3.
\345\ NRECA Comments at 8.
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222. NRECA requests that the Commission clarify proposed revisions
to 18 CFR 292.304(d)(1)(i), (ii), and (iii) to state that an electric
utility is exempt from offering a stream of market revenue as payment,
even if there is a market hub price that could be relevant.\346\ The
Connecticut Authority also suggests that the Commission modify 18 CFR
292.304(d)(1)(ii) to specify that a state may set a series of energy
rates. For this option, Connecticut Authority argues, the regulatory
text should provide greater regulatory and commercial certainty to QF
developers, avoiding disputes with distribution utilities and
states.\347\
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\346\ Id. at 9.
\347\ Connecticut Authority Comments at 14.
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223. Connecticut Authority supports revisions to 18 CFR
292.304(d)(2) because the rule would permit a state to limit a QF's
option to select a preferred energy rate methodology.\348\ Connecticut
Authority also supports the proposed 18 CFR 202.304(d)(iii) that
permits states to set a stated or fixed rate for energy that is
calculated using the present value of the expected stream of revenue
from as-available energy rates during the life of the contract or LEO.
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\348\ Id. at 13.
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224. EEI states that this proposal is not novel, and as an example
notes that the Commission and a federal district court have already
found that the Connecticut Authority could set avoided cost rates based
on a forecast of future avoided costs.\349\ According to EEI, the
Commission has not ruled either that any form of forecasting is
mandated or that any is unacceptable.\350\
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\349\ EEI Comments at 28 (citing Allco Renewable Energy Ltd. v.
Mass. Elec. Co., 208 F. Supp. 3d. 390, 395 (D. Mass. 2016); Windham
Solar, 157 FERC ] 61,134 at P 5.
\350\ EEI Comments at 28-30.
---------------------------------------------------------------------------
225. Allco states that the proposed new option in 18 CFR
292.304(d)(1)(iii) permitting fixed energy rates to be based on
forecasted estimates of the stream of revenue flows during the life of
the contract is consistent with PURPA section 210 and is already
permitted. Allco also states that forecasts need to be non-
discriminatory. According to Allco, utilities and states frequently use
one forecast when dealing with QFs and another when obtaining approval
for their favored projects; Allco asserts that this practice is
discriminatory.\351\
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\351\ Allco Comments at 8.
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226. APPA states that the proposed change is a logical extension of
the conclusion that market options are a legitimate alternative means
of specifying avoided costs.\352\ Distributed Sun states that it
supports permitting states to set fixed energy rates with forward
curves or through competitive solicitations.\353\ NorthWestern supports
the proposal to permit fixed energy rates to be on a forward price
curve developed from prices in either the organized markets or liquid
market hubs.\354\
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\352\ APPA Comments at 14.
\353\ Distributed Sun Comments at 2.
\354\ NorthWestern Comments at 6.
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b. Commission Determination
227. We adopt the proposal to add a new option in 18 CFR
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. The Commission has previously permitted the use of this
method to establish energy and capacity rates over the term of a
contract or LEO.\355\ Nevertheless, given the flexibilities we adopt in
this final rule with respect to competitive market prices and variable
energy rates, we clarify here that a state may use competitive market
prices and/or variable energy rates in the context of a more fixed
estimated avoided cost energy rate (together with a fixed avoided
capacity rate) that is determined at the time an LEO or contract is
incurred. The fixed energy rate component of the contract could be
[[Page 54669]]
a single rate, based on the amortized present value of forecast energy
prices, or it could be a series of specified rates that change from
year-to-year (or other periods) in future years. We also will allow the
state to establish the applicable energy rate(s) for the QF for the
entire term or the rate may change from year-to-year (or some other
period) of the contract at the time the LEO is incurred.
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\355\ Windham Solar, 157 FERC ] 61,134 at P 4 (citing 18 CFR
292.304(d)(2)).
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228. Southeast Public Interest Organizations and Mr. Mattson state
that the NOPR proposal is a departure from past precedent. The very
purpose of a proceeding like this is to consider changes to our
regulations and our doing so is not impermissible.
229. Southeast Public Interest Organizations also state that the
proposal suffers the same deficiencies as the LMP and liquid market hub
pricing proposals and that the NOPR provides no evidence as to how or
if the forward price curves present just and reasonable and non-
discriminatory rates as required by PURPA. Given that we find above
that LMPs and liquid market hub prices may reflect avoided as-available
energy costs and that estimates of such prices over the term of a
contract can therefore reflect a purchasing electric utility's avoided
as-available costs over time, we do not believe Southeast Public
Interest Organizations and Mr. Mattson's concerns are justified.
230. Although, as described below, we allow states to require
variable avoided cost energy rates, allowing forward price curves
determined at the time an LEO is incurred provides an additional option
for states to calculate avoided energy costs in advance while also
using transparent metrics for those calculations. Use of the forward
price curve does not deter the adoption of just and reasonable and non-
discriminatory rates required by PURPA, moreover, and insofar as we
require that states determine that the estimated stream of revenues
reflects the purchasing electric utility's avoided energy, such pricing
is fully consistent with the statute's requirements. With regard to
forecasts, we acknowledge that the forecast used to set the avoided
cost rate must meaningfully and reasonably reflect the utility's
avoided costs over time.\356\
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\356\ See 18 CFR 292.304(b)(5). 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.
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231. We decline to modify this proposal expressly either to permit
or prohibit a state from setting a series of estimated avoided energy
costs over time. Each state will be required to determine whether a
particular estimated stream of revenues represents a purchasing
electric utility's avoided costs over a specified term. Similarly, in
order to provide states flexibility to use LMPs and other competitive
market prices to establish as-available avoided energy costs, we will
not require a state to use this option to guarantee a stream of
revenues.
7. Providing for Variable Energy Rates in QF Contracts
a. Background
232. As explained above, if a QF chooses to sell energy and/or
capacity pursuant to a contract, the PURPA Regulations currently
provide the QF the option of receiving the purchasing electric
utility's avoided cost calculated and fixed at the time the LEO is
incurred.\357\ The Commission's justification in Order No. 69 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.\358\ 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.'' \359\ Further, the Commission agreed with the ``need
for certainty with regard to return on investment in new
technologies.'' \360\ The Commission stated its belief that any
overestimations or underestimations ``will balance out.'' \361\
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\357\ 18 CFR 292.304(d)(2)(ii).
\358\ 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'').
\359\ Id.
\360\ Id.
\361\ Id.
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233. 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 have declined in recent 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.\362\ Based on this
concern, some commenters recommended that the Commission allow states
to ``price generation [energy] from QFs at market prices, and to update
those prices regularly so that the prices for [QFs] 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.\363\ 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.\364\
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\362\ 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 [percent] 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 [percent] 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 [percent] 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 (filed June 30, 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 [percent] from 2011
through 2015 (from approximately $60 per megawatt-hour to less than
$30 per megawatt-hour).'').
\363\ EEI Supplemental Comments, attach. A at 4; see also
Southern Company Comments, Docket No. AD16-16-000, at 7 (filed June
30, 2016) (``[T]he avoided energy cost payment to the QF should be
based on actual avoided energy cost at the time the QF delivers
energy.'').
\364\ See Technical Conference, Docket No. AD16-16-000, Tr.
26:22-25, 27:1-3 (June 29, 2016) (filed July 8, 2016) (Technical
Conference Tr.) (Solar Energy Industries) (``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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b. NOPR Proposal
234. In the NOPR, the Commission proposed to revise 18 CFR
292.304(d) 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 or LEO, and instead allow the state the flexibility to require
QF energy
[[Page 54670]]
rates to vary during the term of the contract. However, under the
proposed revisions to 18 CFR 292.304(d), a QF would continue to be
entitled to a contract with avoided capacity costs calculated and fixed
at the time the contract or LEO is incurred. Only the energy rate in
the contract or LEO could be required by a state to vary. Further, the
NOPR did not propose to obligate states to require variable avoided
cost energy rates--they would retain the ability to allow the QF's
energy rate be fixed at the time the LEO is incurred.\365\
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\365\ NOPR, 168 FERC ] 61,184 at P 67.
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235. The Commission preliminarily found compelling the record
evidence that overestimations have not been adequately balanced by
underestimations in past years. Further, it appeared to the Commission
that this trend may persist into the future with the continuing general
decline in the cost of both wind and solar generation.\366\
Consequently, the Commission found 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 to 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.'' \367\
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\366\ Id. P 68 (citing EIA, Today in Energy, Average U.S.
construction costs for solar and wind continued to fall in 2016
(Aug. 8, 2018), 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 . . . .'')).
\367\ Id. P 68 (internal quotations omitted) (citing 16 U.S.C.
824a-3(b)(1)).
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236. The Commission acknowledged that the current PURPA Regulations
allowing a QF to fix its rates for the life of a contract or LEO were
based on the recognition that fixed rates are beneficial for obtaining
financing for QF projects. The Commission also recognized that QF
developers have continued to assert that they require fixed rates to
finance new projects. However, the Commission stated that it did not
view the proposed modification to the PURPA Regulations as materially
affecting the ability of QFs to obtain financing for several
reasons.\368\
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\368\ Id. P 69.
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237. First, the Commission expressed its understanding 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. The Commission stated that these fixed
capacity and variable energy payments have been sufficient to permit
the financing of significant amounts of new capacity in the RTOs and
ISOs.\369\ 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.\370\ Other comments at the Technical Conference suggested that
a fixed capacity charge likewise would be adequate for financing a QF
project.\371\
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\369\ Id. P 70 (citing Monitoring Analytics, LLC., Third
Quarter, 2018 State of the Market Report for PJM, January through
September, at 249, Table 5-6 (Nov. 8, 2018), http://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2018/2018q3-som-pjm.pdf (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)).
\370\ Id. (citing 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.''); 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.'')).
\371\ Id. P 70 (citing Solar Energy Industries Comments, Docket
No. AD16-16-000, at 3 (filed June 30, 2016) (``Developers need rates
for such sales of energy and/or capacity to be fixed.'') (emphasis
added)).
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238. The Commission further noted that there are financial products
available, such as contracts for differences, which allow generation
owners to hedge their exposure to fluctuating energy prices.\372\ The
Commission stated that 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.\373\
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\372\ Id. P 72 (citing Elec. Storage Participation in Mrkts.
Operated by Reg'l Transmission Org. and Independent Sys. 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'')).
\373\ Id. P 72.
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239. The Commission also explained that, 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. The Commission stated that the
fact that owners of such facilities, which do not have recourse to the
avoided cost rate provisions of PURPA, have been able to obtain
financing for new projects is 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.\374\
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\374\ Id. P 73.
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240. For example, EIA data showed that, since 2005, QFs have made
up only 10% to 20% 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.\375\ EIA data also showed that net generation of energy
by non-utility owned renewable resources in the United States escalated
from 51.7 terawatt hours (TWh) in 2005 when EPAct 2005 was passed, to
340 TWh in 2018. The Commission further observed that, 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 \376\ increased from
3.6 TWh in 2005 to 19.5 TWh in 2012, and to 42.5 TWh in 2018. 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.\377\
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\375\ Id. P 74 (citing EIA, Today in Energy, North Carolina has
More PURPA-Qualifying Solar Facilities than any other State, figure
titled PURPA qualifying facilities (1980-2015) percent of total
renewable capacity (Aug. 23, 2016), https://eia.gov/todayinenergy/detail.php?id=27632).
\376\ Arizona, Colorado, Idaho, Montana, Nevada, New Mexico,
Utah, and Wyoming.
\377\ NOPR, 168 FERC ] 61,184 at P 74.
---------------------------------------------------------------------------
241. The Commission found that EIA data on independently-owned
natural gas-fired generation capacity told 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 would not be within the scope of the PURPA
avoided cost rate provisions. The Commission cited to EIA data showing
that, in 2018,
[[Page 54671]]
approximately 44% of all energy produced by natural gas-fired
generation in the United States was generated by independently-owned
capacity.\378\ The total amount of energy produced in 2018 by
independently-owned natural gas-fired generation was 651 TWh, an
increase of 13.7% from 2017.\379\ 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
State region, 21.4% of the energy produced by natural gas-fired
generation in 2018 was produced by independently-owned capacity, and in
Oregon and Washington 45.4% of natural gas-fired energy was produced by
independently-owned capacity.\380\ From this, the Commission concluded
that independent owners of non-QF generation have been, and continue to
be, able to obtain financing for their facilities.\381\
---------------------------------------------------------------------------
\378\ NOPR, 168 FERC ] 61,184 at P 75 (citing EIA, Electric
Power Monthly with Data for December 2018, at tbl. 1.7.B, https://www.eia.gov/electricity/monthly/current_month/epm.pdf.).
\379\ Id.
\380\ Id.
\381\ Id.
---------------------------------------------------------------------------
242. The Commission did 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 Commission concluded that the evidence demonstrated 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. The Commission reasoned that QFs, which have the
ability to take advantage of PURPA's mandatory purchase requirements,
should be better positioned than non-QFs to negotiate the necessary
contractual arrangements for financing. Moreover, the Commission noted
that QFs are equally as well positioned as non-QF independent
generators to take advantage of federal and state incentives designed
to encourage the construction of renewable resources. \382\
---------------------------------------------------------------------------
\382\ Id. P 76.
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243. Further, the Commission pointed to evidence that the desire to
limit the effect of fixed QF contract rates had directly led to PURPA
implementation issues that affected QF financing in other respects,
particularly with respect to the length of QF contracts.\383\ For
example, a commissioner of the 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.\384\ Similarly, Southern Company
testified that the fixed rate requirement is ``resulting in . . .
typically shorter contract term lengths.'' \385\ Golden Spread Electric
Cooperative recommended that, if the fixed rate requirement is not
eliminated, the Commission permit shorter contract terms, ``as short as
one-year or three years at most.'' \386\
---------------------------------------------------------------------------
\383\ Id. P 65 (citing Natural Resources Defense Council
Comments, Docket No. AD16-16-000, at 4 (filed June 30, 2016)).
\384\ Id. P 65 (citing 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.'')).
\385\ Id. P 65 (citing Technical Conference Tr. at 202 (Southern
Company)).
\386\ Id. P 65 (citing Golden Spread Electric Cooperative
Comments, Docket No. AD16-16-000, at 10 (filed June 30, 2016)).
---------------------------------------------------------------------------
244. Finally, the Commission addressed one particular standard form
of QF contract rate currently employed by a number of utilities, which
is a one-part rate, applicable to each MWh of energy delivered by the
QF. This one-part rate is calculated to reflect both avoided capacity
costs and avoided energy costs. Contracts employing such rates also
typically impose a must purchase obligation on the purchasing utility.
The Commission stated that its proposed rule was not intended to
prevent states from implementing such an approach to setting QF
contract rates in the future. The Commission proposed that, to the
extent 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 18 CFR 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.\387\
---------------------------------------------------------------------------
\387\ Id. P 81.
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c. General Comments on the NOPR Proposal
i. Comments in Support of NOPR Proposal
245. Several commenters support the NOPR proposal to allow energy
rates to vary in QF contracts and other LEOs, arguing it will reduce
overpayments and protect customers.\388\ In that regard, Duke Energy
asserts that the primary factor behind overpayment has been the
requirement to offer fixed avoided cost energy rates during a period of
rapidly declining energy prices.\389\ Several other commenters
similarly cite to the general decline of energy prices coupled with the
fact that QFs have been able to lock in rates over the life of a
contract or other LEO as reasons for their support of the NOPR
proposal.\390\
---------------------------------------------------------------------------
\388\ Conservative Action Comments at 1; Consumer Energy
Alliance Comments at 2; EEI Comments at 30-31; Idaho Power Comments
at 7-8; Idaho Commission Comments at 4; LG&E/KU Comments at 3;
NextEra Comments at 5; see also Alaska Power Comments at 1; Arizona
Public Service Comments at 3-4; Basin Comments at 6-8; Chamber of
Commerce Comments at 4; Freedom Center Comments at 1-2; R Street
Comments at 5; Tax Reform Comments at 1-2.
\389\ Duke Energy Comments at 5-7.
\390\ Consumer Energy Alliance Comments at 2; Idaho Power
Comments at 7-8; Idaho Commission Comments at 4; LG&E/KU Comments at
3; Ohio Commission Energy Advocate Comments at 4.
---------------------------------------------------------------------------
246. Several commenters also support the NOPR's variable rate
proposal because it will allow states greater flexibility to determine
avoided cost rates accurately and to meet PURPA's consumer protection
goals.\391\ LG&E/KU states that such flexibility is appropriate and
necessary to meet the statutory requirement that ratepayers not pay a
rate that exceeds the electric utility's incremental cost of
alternative energy.\392\ NorthWestern argues that providing such
flexibility will assist in guaranteeing that customers are held
harmless by purchases of QF power.\393\
---------------------------------------------------------------------------
\391\ Alliant Energy Comments at 9; Duke Energy Comments at 8-9;
LG&E/KU Comments at 4; MA DPU Comments at 1, 7; NorthWestern
Comments at 6-7.
\392\ LG&E/KU Comments at 4.
\393\ NorthWestern Comments at 6-7.
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247. Supporters of the NOPR variable rate proposal also commented
on specific aspects of the proposal. These comments are discussed in
more detail in the following sections.
ii. Comments in Opposition to NOPR Proposal
248. Several commenters oppose the NOPR variable energy rate
proposal.\394\
[[Page 54672]]
In addition to objections as to specific aspects of that proposal,
which are discussed in the following sections, some commenters raise
threshold issues regarding this proposal.
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\394\ Allco Comments at 9-11; AllEarth Comments at 2; Biogas
Comments at 2; BluEarth Comments at 2; CARE Comments at 3-5;
Biological Diversity Comments at 8; ELCON Comments at 18, 21-23;
EPSA Comments at 6-13; Massachusetts AG Comments at 8-9; North
Carolina DOJ Comments at 2-6; North Carolina Commission Staff
Comments at 2-4; New England Hydro Comments at 8; NIPPC, CREA, REC,
and OSEIA Comments at 29-48; North American-Central Comments at 4-6;
Public Interest Organizations Comments at 6-7, 27-51; Resources for
the Future Comments at 4-7; Solar Energy Industries Comments at 28-
38; SC Solar Alliance Comments at 4-10; Southeast Public Interest
Organizations Comments at 9-18; sPower Comments at 10-13; State
Entities Comments at 2-3; Mr. Mattson Comments at 26-27; Two Dot
Wind Comments at 11-13; Western Resource Councils Comments at 2.
---------------------------------------------------------------------------
249. NIPPC, CREA, REC, and OSEIA cite to the PURPA Conference
Report as expressing Congress's intent that QFs be entitled to long-
term fixed energy rates. Specifically, they cite to the statement in
the Conference Report that ``the Commission and States should look to
the reliability of that power to the utility and the cost savings to
the utility which may result at some later date by reason of supply to
the utility at that time of power from the cogenerator or small power
producer.'' \395\ According to NIPPC, CREA, REC, and OSEIA, this
statement shows that ``Congress also recognized that attempts to set
the rates based on the avoided costs at the time of delivery would
likely be insufficient to encourage such facilities.'' \396\
---------------------------------------------------------------------------
\395\ NIPPC, CREA, REC, and OSEIA Comments at 27 (quoting Conf.
Rep. at 98-99).
\396\ Id.
---------------------------------------------------------------------------
250. Harvard Electricity Law asserts that the Commission may not
authorize state regulators to change rates in existing contracts.\397\
Harvard Electricity Law then asserts that the Commission: (1) Attempts
to portray its agenda as consistent with Congressional intent by
providing a skewed summary of the legislative history; (2) presents an
unsupported statement that its rules will ``continue to encourage'' QF
development, which ignores the administrative record and fails to
account for regulatory changes since PURPA's enactment; (3) misreads
its own rules in claiming that repeal is necessary to protect
consumers; and (4) relies on a finding that fixed price energy
contracts are not necessary to encourage QFs that is based on
irrelevant data and questionable assumptions that are not grounded in
reasoned decision making.
---------------------------------------------------------------------------
\397\ Harvard Electricity Law Comments at 23 (citing API, 461
U.S. at 414).
---------------------------------------------------------------------------
251. Harvard Electricity Law also asserts that allowing long-term
contracts to include variable rates is contrary to PURPA.\398\ In
support of this assertion, Harvard Electricity Law cites to two
decisions which it claims stand for the proposition that the
Commission's proposed rule would impose forbidden utility-type
regulation on QFs.\399\
---------------------------------------------------------------------------
\398\ Id. at 28.
\399\ Id. at 29 (citing Freehold Cogeneration Assoc. v. Bd. of
Regulatory Comm'rs. of N.J., 44 F.3d 1178, 1193 (3d Cir. 1995)
(Freehold Cogeneration); Smith Cogeneration Mgt. v. Corp. Comm'n.,
863 P.2d 1227 (Okla. 1993) (Smith Cogeneration)).
---------------------------------------------------------------------------
252. NIPPC, CREA, REC, and OSEIA and Public Interest Organizations
assert that it is unclear whether independent power producers that have
obtained financing did so with short-term variable rate
conditions.\400\ North American-Central argues that, if a variable rate
will preclude a QF from receiving financing in the first place, it is
irrelevant that a state might be more willing to offer a longer-term
contract.\401\
---------------------------------------------------------------------------
\400\ NIPPC, CREA, REC, and OSEIA Comments at 46.
\401\ North American-Central Comments at 5-6.
---------------------------------------------------------------------------
iii. Commission Determination
253. In this final rule, we adopt without modification the NOPR
variable rate proposal. We find that setting QF energy avoided cost
contract and other LEO rates at the level of the purchasing utility's
avoided energy costs at the time the energy is delivered is consistent
with PURPA, which limits QF rates to the purchasing utility's avoided
costs. Indeed, a variable energy avoided cost approach is a more
accurate way to ensure that payments to QFs equal, but do not exceed,
avoided costs.\402\ It is inevitable that, in contrast, over the life
of a QF contract or other LEO a fixed energy avoided cost rate, such as
that used in past years, will deviate from actual avoided costs.
---------------------------------------------------------------------------
\402\ 16 U.S.C. 824a-3(b)(1).
---------------------------------------------------------------------------
254. As described in more detail in the following sections, the
record overwhelmingly supports our conclusions that long-term forecasts
of avoided energy costs are inherently less accurate, and that states
should be given the flexibility to rely on a more accurate variable
avoided cost energy rate approach. Further, there are numerous
instances where overestimates and underestimates have not balanced
out.\403\ When that has occurred, consumers have borne the brunt of the
overpayments, which subsidized QFs, in contravention of Congressional
intent and the Commission's expectations.
---------------------------------------------------------------------------
\403\ See Duke Comments at 6 (Duke's QF contracts cost $4.66
billion but its ``actual current avoided costs'' are $2.4 billion);
Idaho Power Comments at 10-11 (``The cost of PURPA generation
contained in Idaho Power's base rates, on a dollars per MWh basis,
is not just greater than Mid-C market prices, it is greater than all
the net power supply cost components currently recovered in base
rates. Idaho Power's average cost of PURPA generation included in
base rates is $62.49/MWh. At $62.49/MWh, the average cost of PURPA
purchases is greater than the average cost of FERC Account 501, Coal
at $22.79/MWh; greater than FERC Account 547, Natural Gas at $33.57/
MWh; greater than FERC Account 555, Non-PURPA Purchases at $50.64/
MWh; and significantly greater than what is being sold back to the
market as FERC Account 447, Surplus Sales at $22.41/MWh.'');
Portland General Comments at 5 (``for a typical 3 MW Solar QF
project that incurred a LEO in 2016 and reaches commercial
operations three years later, [Portland General's] customers would
pay 67% more for the project's energy than if the 2019 avoided cost
rate had been used. As a result of this lag, [Portland General's]
customers would pay an additional $1.6 million more for the energy
from the QF facility over the 15-year contract term.''); see also
NOPR, 168 FERC 61,184 at P 64 n.101 (citing Alliant Energy,
Comments, Docket No. AD16-16-000, at 5 (filed 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,
attach. A at 3-4 (``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 (filed
June 30, 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).'').
---------------------------------------------------------------------------
255. Given that PURPA section 210(b) prohibits the Commission from
requiring QF rates in excess of avoided costs,\404\ this record
evidence supports our decision to give the states the flexibility to
require variable avoided cost energy rates in QF contracts and other
LEOs to prevent QF rates from exceeding avoided costs. We discuss
specific aspects of the variable energy rate provisions below, but at
the outset address certain threshold issues raised in the comments.
---------------------------------------------------------------------------
\404\ This prohibition is described in Section IV.A.
---------------------------------------------------------------------------
256. We reiterate the points made in detail above in Section II.
The variable energy avoided cost rate provision is not based on any
determination that the Commission's rules no longer should encourage QF
development. The question of whether QFs should continue to be
encouraged is a question for Congress. Rather, we are revising the
PURPA Regulations by giving states the flexibility to require variable
avoided cost energy rates in QF contracts and other LEOs in order to
better comply
[[Page 54673]]
with Congress's clear instruction in PURPA that the Commission may not
require QF rates in excess of a purchasing utility's avoided costs.
257. By its very nature, the question of fixed versus variable
energy rates is a question of how risk from increases in avoided energy
costs over the life of a QF contract or other LEO should be allocated.
Answering this question requires the Commission to allocate this risk
either to (i) customers of electric utilities, or (ii) QFs and their
investors and lenders. But the Commission does not have unlimited
discretion in how it resolves the question. Congress in PURPA section
210(b) provided guidance to the Commission in how it should perform
that allocation--by mandating that the Commission cannot adopt a rule
that provides for a rate that exceeds the incremental cost of
alternative electric energy.\405\
---------------------------------------------------------------------------
\405\ 16 U.S.C. 824a-3(b); see also 16 U.S.C. 824a-3(d); 18 CFR
292.101(b)(6), 292.304(b)(2).
---------------------------------------------------------------------------
258. Opponents of variable avoided cost energy rates urge the
Commission to continue placing this risk on the customers of electric
utilities, as it did in the past, by retaining the option for QFs to
fix their avoided cost energy rates in their contracts or LEOs
notwithstanding record evidence, discussed elsewhere in this final
rule, that fixed energy rates compared to actual avoided costs have not
balanced out over time. But, after consideration of the record, the
Commission has decided instead to allow states to reduce the risk to
customers by giving states the flexibility to require variable avoided
cost energy rates in QF contracts and LEOs. The Commission's
determination ensures that the PURPA Regulations continue to be
consistent with the statutory avoided cost rate cap in PURPA section
210(b), coupled with the directive in the Conference Report that
customers of utilities not be required to subsidize QFs.\406\
---------------------------------------------------------------------------
\406\ Conf. Rep. at 98 (``The provisions of this section are not
intended to require the rate payers of a utility to subsidize
cogenerators or small power produc[er]s.'') (emphasis added).
---------------------------------------------------------------------------
259. Third, there is no merit to the contention that the PURPA
Conference Report expresses Congressional intent that QFs are entitled
to long-term fixed energy rates. The statement in the Conference Report
cited by NIPPC, CREA, REC, and OSEIA does not support this
contention.\407\ The example provided in the PURPA Conference Report
was of a utility owning a hydroelectric generating facility. Congress
hypothesized that this utility might be able to avoid drawing down its
reservoir as a result of a purchase from a QF, and thereby be able to
generate electricity from the hydroelectric facility at a later date
rather than running a more expensive fossil fuel unit at that later
date. Congress stated that the avoided cost in its example should be
based on the cost of the more expensive fossil unit whose operation was
avoided at a later date rather than the avoided cost at the time the QF
delivered its energy.\408\
---------------------------------------------------------------------------
\407\ See NIPPC, CREA, REC, and OSEIA Comments at 27 (quoting
Conf. Rep. at 98-99).
\408\ Id. at 98-99 (``In interpreting the term `incremental cost
of alternative energy,' the conferees expect that the Commission and
the states may look beyond the cost of alternative sources which are
instantaneously available to the utility. Rather, the Commission and
states should look to the reliability of that power to the utility
and the cost savings to the utility which may result at some later
date by reason of supply to the utility at that time of power from
the cogenerator or small power producer; for example an electric
utility which owns a source of hydroelectric power and which is
offered the sale of electric energy from a cogenerator or small
power producer might, if measured over the short term, have a low
incremental cost of alternative power because of its access to
hydropower; however, it may be the case that by purchasing from the
cogenerator or small power producer and saving hydropower for later
use, the utility can avoided the use of expensive electric energy
generated by fossil fired units during later months of its seasonal
generation cycle. Thus, viewed over the longer period of time, the
incremental cost of alternative electric energy might be
substantially higher than that measured by the instantaneously
available hydropower.'').
---------------------------------------------------------------------------
260. While Congress recognized that the better measure of avoided
cost in that scenario might be the cost of the alternative fossil fuel
unit that would not be run at that later date,\409\ nothing in the
quoted section of the PURPA Conference Report suggests that Congress
intended the Commission to require that all avoided cost energy rates
be fixed at the outset for the life of a QF contract or other LEO. And
nothing in the revision being implemented in this final rule would
prohibit a state from calculating a QF's avoided cost energy rate for a
QF contract or LEO in the manner suggested in the PURPA Conference
Report or, indeed, in the manner the Commission has long allowed, if a
state determined that such an approach best reflects the purchasing
electric utility's avoided costs.
---------------------------------------------------------------------------
\409\ Under the approach adopted in this final rule, with the
flexibility granted to states to adopt--but not a mandate directing
states to adopt--variable avoided cost energy rates for QF contracts
and other LEOs, states can adopt a pricing approach that best fits
their circumstances, including adopting the pricing approach
described by the Conference Report to address the circumstances
described by the Conference Report.
---------------------------------------------------------------------------
261. Fourth, the variable avoided cost energy rate provision
adopted herein does not run afoul of the Freehold Cogeneration and
Smith Cogeneration cases cited by Harvard Electricity Law.\410\ Those
decisions, which overturned state avoided cost determinations allowing
for changes in QF rates, were based on the provision in the original
PURPA Regulations giving QFs the option to select contracts with long-
term fixed avoided cost rates.\411\ Indeed, the Smith Cogeneration
decision quotes at length from the explanation in Order No. 69 of the
Commission's justification for its requiring in its regulations fixed
avoided cost rates in QF contracts and LEOs.\412\ Neither decision
suggests that PURPA would prevent the Commission from revising its
regulations to allow states the flexibility to require variable avoided
cost energy rates, as the Commission is doing here.
---------------------------------------------------------------------------
\410\ Harvard Electricity Law Comments at 29 (citing Freehold
Cogeneration, 44 F.3d at 1193; Smith Cogeneration, 863 P.2d at
1227).
\411\ See Smith Cogeneration, 863 P.2d at 1241 (holding that
allowing reconsideration of established avoided costs ``makes it
impossible to comply with PURPA and FERC regulations requiring
established rate certainty for the duration of long term contracts
for qualifying facilities that have incurred an obligation to
deliver power'') (emphasis added); Freehold Cogeneration, 44 F.3d at
1193 (relying on Smith Cogeneration analysis that ``that PURPA and
FERC regulations preempted the State Commission rule'') (emphasis
added).
\412\ Smith Cogeneration, 863 P.2d at 1240.
---------------------------------------------------------------------------
262. Harvard Electricity Law also relies on Freehold Cogeneration
and Smith Cogeneration to assert that the Commission is imposing
``utility-type'' regulation in violation of Congressional intent as
expressed in the PURPA Conference Report.\413\ However, those holdings
do not address the changes the Commission is implementing here. By
adopting a provision that allows states the option to require variable
avoided cost energy rates, we are not mandating ``utility-type''
regulation. The PURPA Conference Report states that: ``It is not the
intention of the conferees that [QFs] become subject . . . to the type
of examination that is traditionally given to electric utility rate
applications to determine what is the just and reasonable rate that
they should receive for their electric power.'' \414\ Our action today
is consistent with that statement; we are not subjecting QFs to the
same type of examination that is traditionally given to electric
utility rate applications (e.g., cost-of-service rate regulation).
---------------------------------------------------------------------------
\413\ Harvard Electricity Law Comments at 30.
\414\ Conf. Rep. at 97.
---------------------------------------------------------------------------
263. Indeed, the regulation adopted today does not subject QF rates
to any examination whatsoever of the costs incurred by QFs in producing
and selling power. Rather, the variable avoided cost energy rate
provision applicable to QF contracts and other LEOs that is adopted in
this final rule sets QF rates based on the avoided costs
[[Page 54674]]
of the purchasing utility. In no sense can this variable avoided cost
energy rate provision be characterized as imposing utility-style
regulation on the QFs themselves.
264. Finally, we agree with Harvard Electricity Law that state
regulators may not change rates in existing QF contracts or other
existing LEOs.\415\ By its terms, the variable energy avoided cost
provision adopted in this final rule applies only prospectively to new
contracts and new LEOs entered into after the effective date of this
final rule. Nothing in the final rule, including in this preamble,
should be read as sanctioning the modification of existing fixed-rate
QF contracts and LEOs.
---------------------------------------------------------------------------
\415\ Harvard Electricity Law Comments at 23 (citing API, 461
U.S. at 414).
---------------------------------------------------------------------------
d. Whether the Current Approach Has Resulted in Payments to QFs in
Excess of Avoided Costs
i. Comments in Support of NOPR Proposal
265. Duke Energy states that its experience shows the Commission's
original assumption that overestimations and underestimations will
balance out over time was incorrect. From 2012 to 2017, Duke Energy
states that it experienced explosive growth in solar QF contracts, and
entered into at a time of rapidly declining natural gas prices--which
drove down Duke Energy's avoided costs. Duke Energy states that, as of
July 1, 2019, it has almost 4,000 MW of QF power under contract and in
commercial operation. Duke Energy claims the total estimated financial
obligation on Duke Energy's retail and wholesale customers to pay for
this QF power is approximately $4.66 billion over the next
approximately 15 years. If the contracts had been permitted to contain
rates that mirrored the utilities' declining incremental costs either
to generate that electric energy itself or to purchase alternative
electric energy, i.e., Duke Energy's ``actual current avoided costs,''
Duke Energy asserts that the contracts would be valued at $2.4 billion.
Duke Energy claims that, among the factors contributing to this
overpayment of $2.26 billion for the remainder of these QF contracts,
the primary factor has been the requirement to offer fixed avoided cost
energy rates during a period of rapidly declining energy prices.\416\
---------------------------------------------------------------------------
\416\ Duke Energy Comments at 6.
---------------------------------------------------------------------------
266. EEI argues that relying on certain avoided cost methods, such
as the costs of a proxy unit at a fixed point in time, may result, and
has resulted, in the over estimation of future energy prices, leaving
customers saddled with uneconomic PURPA contracts. According to EEI,
the Commission's variable rate proposal will help ensure that the
variable energy rate more accurately reflects the electric utility's
actual avoided cost of energy so that rates for customers are just and
reasonable. EEI describes this change as important for states,
especially those in RTO/ISO markets, that elect to have the avoided
cost rate set at LMP.
267. EEI also submitted with its comments a study performed by
Concentric Energy Advisors showing that the avoided cost rates in the
sample of solar and wind QF contracts they reviewed generally exceeded
rates that are realized in competitive markets for solar and wind
energy. According to that report, the total overpayment ranged between
$2.7 billion and $3.9 billion. Several other commenters also cited the
Concentric Energy Advisors report for the proposition that consumers
nationwide have overpaid for QF contracts between 2009-2018.\417\
Berkshire Hathaway represents that PURPA contracts held by PacifiCorp
will cost customers more than $1.2 billion above projected market costs
over the next 10 years.\418\
---------------------------------------------------------------------------
\417\ Alliant Energy Comments at 7-8; Conservative Action
Comments at 1; Duke Energy Comments at 5-7; Mr. Moore Comments at 2;
Mr. Transeth Comments at 2.
\418\ Berkshire Hathaway Comments at 5.
---------------------------------------------------------------------------
268. Massachusetts DPU argues that a 10-year, fixed energy rate
based on current New England wholesale energy market prices is highly
likely to diverge from actual energy market prices over the ten-year
contract term and could significantly harm ratepayers.\419\ Mr.
Transeth represents that Consumers Energy's QF contracts are priced
between 30 to 50% higher than their current market value.\420\
---------------------------------------------------------------------------
\419\ Massachusetts DPU Comments at 7 (citing NOPR, 168 FERC ]
61,184 at 40).
\420\ Mr. Transeth Comments at 2.
---------------------------------------------------------------------------
269. APPA supports the variable energy rate proposal because the
discrepancy between administratively set, locked-in, long-run avoided
costs and actual market prices for the purchase of equivalent energy
can be enormous, as demonstrated by the evidence submitted in the
Technical Conference. According to APPA, were continued development of
the IPP and renewable industries in jeopardy, the Commission might have
grounds to conclude that enabling QFs to lock in energy payments over
the course of their agreement is needed in order to bolster these
resources, but the growth in the IPP and renewables industries in RTOs/
ISOs indicate otherwise.\421\
---------------------------------------------------------------------------
\421\ APPA Comments at 16.
---------------------------------------------------------------------------
270. Commissioner O'Donnell asserts that the Montana Public Service
Commission has addressed concerns about overpayments by shortening QF
contract length from 25 years to 15, which has resulted in litigation
currently pending before the Montana Supreme Court. Commissioner
O'Donnell asserts that, because the energy component of an avoided cost
rate reflects the price at which the purchasing electric utility could
purchase power on the open market, there is no need to fix that fluid
energy component for as long as 25 years.\422\
---------------------------------------------------------------------------
\422\ Commissioner O'Donnell Comments at 2.
---------------------------------------------------------------------------
271. Competitive Enterprise asserts that long-term fixed price
rates ``serve only to reward certain financial investors at the expense
of consumers, who are forced to pay inflated rates for electricity''
and insists that utilities should only be required to purchase from
resources that are needed and competitively priced.\423\
---------------------------------------------------------------------------
\423\ Competitive Enterprise Comments at 2.
---------------------------------------------------------------------------
ii. Comments in Opposition to NOPR Proposal
272. Harvard Electricity Law observes that the Commission's
examples of contract rates that exceed avoided costs calculated years
prior illustrate the general proposition that ``energy forecasts have a
manifest record of failure.'' \424\ Harvard Electricity Law notes,
however, that in issuing Order No. 69, the Commission recognized that
industry changes are difficult to forecast, but the Commission
nonetheless concluded in Order No. 69 that the possibility that
consumers would be harmed by high rates was outweighed by the
Commission's duty to encourage QFs.\425\ Harvard Electricity Law
further claims that the repeal of the fixed-price rule is not necessary
to protect consumers from rates in future contracts.\426\ Harvard
Electricity Law argues that the Commission's rules do not require an
annual matching between avoided costs and rates, nor prevent states
from setting declining avoided costs (which Order No. 69 explicitly
condones).\427\
---------------------------------------------------------------------------
\424\ Harvard Electricity Law Comments at 24 (citing Vaclav
Smil, Energy at the Crossroads: Global Perspectives and
Uncertainties, Mass. Inst. Tech., 2003, at 121, 145-149).
\425\ Harvard Electricity Law Comments at 24.
\426\ Id. at 23.
\427\ Id. at 23-24 (citing Order No. 69, FERC Stats. & Regs. ]
30,128 at 30,881).
---------------------------------------------------------------------------
273. Several commenters argue that the NOPR's assertion of
artificially high avoided cost rates is unsupported or
[[Page 54675]]
relies on flawed data and analysis.\428\ For example, NIPPC, CREA, REC,
and OSEIA argue that the Commission relied on flawed data and analysis
by using actual market prices that resulted after substantial QF
penetration (which they assert has reduced power prices).\429\
---------------------------------------------------------------------------
\428\ NIPPC, CREA, REC, and OSEIA Comments at 30; Public
Interest Organizations Comments at 39-40; Public Interest
Organizations Comments at 43; Solar Energy Industries Comments at
34-36.
\429\ NIPPC, CREA, REC, and OSEIA Comments at 30-31.
---------------------------------------------------------------------------
274. Public Interest Organizations claim that the NOPR's evidence
of overestimations is based on a selective choice of years reflecting
general wholesale price declines, in which QF contracts were executed
just before unforeseen natural gas price declines.\430\ Public Interest
Organizations argue that these recent electricity price overestimations
are not unique to QFs and can be explained by general declines in
natural gas prices since the adoption of hydraulic fracturing and the
2007-2009 recession.\431\
---------------------------------------------------------------------------
\430\ Public Interest Organizations Comments at 39-40.
\431\ Id. at 47-50.
---------------------------------------------------------------------------
275. Public Interest Organizations dispute Alliant's asserted
overestimation by claiming that Alliant likely would have procured non-
QF energy at the same price and further point out that Alliant does not
disclose the data upon which it relies.\432\ Public Interest
Organizations assert that the Commission similarly erred in relying on
EEI's description of overestimations of avoided costs in PacifiCorp's
QF contracts because PacifiCorp only compares those prices to the Mid-C
hub and does ``not contain an analysis of the long-term balancing of
its forecasted avoided energy rates with actual avoided energy costs.''
\433\ Public Interest Organizations contend that this comparison
implies that PacifiCorp would have relied entirely on the Mid-C hub for
all of its needs but for the QF contracts.\434\
---------------------------------------------------------------------------
\432\ Id. at 40-41.
\433\ Id. at 41 (citing NOPR, 168 FERC ] 61,184 at P 64 n.101
(citing EEI Supplemental Comments, Docket No. AD16-16-000, attach. A
at 3-4 (June 25, 2018))).
\434\ Id.
---------------------------------------------------------------------------
276. SC Solar Alliance contests Duke Energy's estimate of $2.26
billion in overpayments for QF power. According to SC Solar Alliance,
``an expert witness for South Carolina's Office of Regulatory Staff,
which represents the interests of the using and consuming public in
proceedings before the South Carolina Commission, recently testified
that Duke's estimation of `overpayments' to QFs was not reliable and
that he `wouldn't put a whole lot of weight in [Duke's estimate].' ''
\435\
---------------------------------------------------------------------------
\435\ SC Solar Alliance Comments at 7 (quoting Public Service
Commission of South Carolina, Docket No. 2019-185 & 186-E, Hearing
Transcript Vol. 2 at 596, lines 6-21 (Horii Test.)) (attached as
Appendix 1 to SC Solar Alliance Comments).
---------------------------------------------------------------------------
277. GridLab attacks the conclusions of the Concentric Report,
raising two principal arguments. First, according to GridLab, QF
contracts are executed in non-competitive markets where utilities do
not perform competitive solicitations. If QF avoided cost pricing is
higher than prices set through competitive bidding, GridLab asserts
that is because the utility's production costs are higher than
competitive prices.\436\ Second, GridLab asserts that Concentric has
compared two datasets that are different in several ways, most notably
project size--with larger projects enjoying economies of scale that
result in lower costs. According to GridLab, the difference in project
size and its impact on cost is a significant factor that could account
for the whole of the reported increase on price.\437\
---------------------------------------------------------------------------
\436\ GridLab Comments at 1-2.
\437\ Id. at 4.
---------------------------------------------------------------------------
278. NIPPC, CREA, REC, and OSEIA argue that it was unreasonable for
the Commission in the NOPR to assume that electricity price declines
are permanent, given recent integrated resource plans (IRP) in the
Northwest predicting significantly increased electricity demand and
market prices at the Mid-C and Palo Verde hubs.\438\ NIPPC, CREA, REC,
and OSEIA represent that electricity prices will climb significantly in
the Northwest. NIPPC, CREA, REC, and OSEIA also assert that 100%
renewable or non-emitting generation mandates and increased
electrification of transportation could substantially increase
electricity demand. NIPPC, CREA, REC, and OSEIA contend that fixed-
price QF contracts protect consumers from the potential for future
rising prices, market volatility, market risk, and project risk.\439\
---------------------------------------------------------------------------
\438\ NIPPC, CREA, REC, and OSEIA Comments at 33-34.
\439\ Id. at 34-36.
---------------------------------------------------------------------------
279. Resources for the Future reasons that ``while fixed prices
determined [five to ten] years ago would likely exceed current average
market prices, that may not be true for fixed prices determined either
more recently or in the future.'' \440\ Resources for the Future states
that, contrary to the NOPR, there is no consensus that wind and solar
generation costs will continue to decline because any capital cost
declines will be relatively modest and will be offset by declining
federal tax credits.\441\ Furthermore, Resources for the Future
attributes these cost declines to the recent U.S. natural gas boom and
points out that this decline is therefore not likely to continue.\442\
sPower similarly argues that recent energy price declines will not
necessarily continue, especially given expiring tax credits and
additional tariffs.\443\
---------------------------------------------------------------------------
\440\ Resources for the Future Comments at 4.
\441\ Id. at 5.
\442\ Id. at 4.
\443\ sPower Comments at 10-11.
---------------------------------------------------------------------------
280. Several commenters assert that the risk of overpayments to QFs
should be compared to the alternative generation sources used by the
utility.\444\ For example, ELCON claims that critics who assert that
QFs are ``locking-in'' consumers to artificially high rates must
acknowledge that utility procurement does exactly the same via the pre-
approval process, sometimes for even longer durations. ELCON argues
that QFs can only benefit consumers by competing on a level playing
field with comparable terms and conditions.\445\ North Carolina
Commission Staff similarly asserts that the risk of overpayment to QFs
should be considered in the context of a utility's long-term commitment
to build plants where ``generation decisions are based upon uncertain
forecasts that could result in ratepayers bearing the same type of
forecast risk from utility plants as they do from QFs.'' \446\
---------------------------------------------------------------------------
\444\ ELCON Comments at 22; North Carolina Commission Staff
Comments at 2-3; NIPPC, CREA, REC, and OSEIA Comments at 31; Public
Interest Organizations Comments at 40, 43; Solar Energy Industries
Comments at 36-38.
\445\ ELCON Comments at 22.
\446\ North Carolina Commission Staff Comments at 2-3.
---------------------------------------------------------------------------
281. According to Solar Energy Industries, the risk from utility
generation construction is allocated to ratepayers for the life of
these assets regardless of ongoing changes in energy prices, while
PURPA was designed to shift this risk away from ratepayers. Solar
Energy Industries state that there is no evidence that ratepayers are
harmed by long-term QF contracts any more than other long-term
contracts or utility recovery of generation assets in their rate base.
Solar Energy Industries state that, even though solar prices have
declined over time, solar QFs should not be penalized for utility
failures to update their avoided cost calculations to keep pace with
such declines.\447\
---------------------------------------------------------------------------
\447\ Solar Energy Industries Comments at 36-38.
---------------------------------------------------------------------------
282. The DC Commission states that, with respect to the fact that
long-term contracts (e.g., 20 years) using fixed avoided energy costs
could create stranded costs potentially due to
[[Page 54676]]
inaccurate projections, the chance of creating stranded costs is
substantially reduced when the most up-to-date data regarding avoided
energy costs is used. The DC Commission states that, if the contract
length is permitted to be flexible, the possibility of stranded costs
would be significantly reduced for shorter term contracts.\448\ The DC
Commission states that, without the worry of stranded costs, there is
no need to eliminate the fixed price contract option for QFs.\449\
---------------------------------------------------------------------------
\448\ DC Commission Comments at 8.
\449\ Id.
---------------------------------------------------------------------------
iii. Commission Determination
283. As explained above, the NOPR proposal to give states the
flexibility to require variable energy pricing in QF contracts and
other LEOs, instead of providing QFs the right to elect fixed energy
prices, was based on the Commission's concern that, at least in some
circumstances, long-term fixed avoided cost energy rates have been well
above the purchasing utility's avoided costs for energy--a result
prohibited by PURPA section 210(b). And the record evidence
demonstrates just that, i.e., that QF contract and LEO prices for
energy can exceed and have exceeded avoided costs for energy without
any subsequent balancing out. In addition to the examples presented in
the record of the Technical Conference that were cited in the NOPR,
commenters have provided additional examples of such overpayments, as
described above.\450\ Such evidence has persuaded us that it is
necessary to give states the flexibility to address QF contract and LEO
rates for energy that exceed avoided costs for energy, while at the
same time still allowing states the flexibility to continue requiring
long-term fixed avoided cost energy rates in QF contracts and other
LEOs when such treatment is appropriate.
---------------------------------------------------------------------------
\450\ See Duke Comments at 6; Idaho Power Comments at 10-11;
Portland General Comments at 5; NOPR, 168 FERC ] 61,184 at P 64
n.101.
---------------------------------------------------------------------------
284. As Harvard Electricity Law concedes, the examples of QF
contract rates that exceed avoided costs that are in the record
illustrate the general proposition that ``energy forecasts have a
manifest record of failure.'' \451\ It is this ``manifest record of
failure'' including evidence in the record that the failure has been at
the expense of consumers, that drives us to make the change adopted in
the final rule.\452\
---------------------------------------------------------------------------
\451\ Harvard Electricity Law Comments at 24 (citing Vaclav
Smil, Energy at the Crossroads: Global Perspectives and
Uncertainties, Mass. Inst. Tech., 2003, at 121, 145-149).
\452\ See, e.g., supra P 254 & note 403.
---------------------------------------------------------------------------
285. While some commenters challenge the idea that avoided cost
energy rates in QF contracts and other LEOs have exceeded actual
avoided costs, their arguments largely either concede that
overestimations have occurred while arguing that such overestimations
impacted purchasing electric utilities just as much as QFs, or attempt
to argue that such overestimations were temporary or unusual. For these
reasons, they assert that the Commission should not conclude that
historical overestimations of avoided cost require a change to the
current PURPA Regulations requiring states to allow QFs to fix their
avoided costs energy rates for the term of their contracts. These
arguments do not cause us to reconsider our determination, for the
reasons explained below.
286. First, Harvard Electricity Law's citation to the Commission's
original determination in Order No. 69 that it was not necessary to
provide for variable avoided cost energy rates carries little
weight.\453\ The purpose of the NOPR was to reconsider the Commission's
determinations made in Order No. 69 in light of changes in
circumstances and additional evidence that was not available to the
Commission when it issued Order No. 69 in 1980. The record evidence
cited above demonstrates that, contrary to the Commission's finding in
1980, overestimations and underestimations of future avoided costs may
not even out.\454\ Consequently, the Commission's determination in 1980
does not preclude the Commission from changing the rule adopted at that
time.
---------------------------------------------------------------------------
\453\ Id. at 23-24 (citing Order No. 69, FERC Stats. & Regs. ]
30,128, at 30,881).
\454\ See Duke Comments at 6; Idaho Power Comments at 10-11;
Portland General Comments at 5; NOPR, 168 FERC ] 61,184 at 64 n.101.
---------------------------------------------------------------------------
287. We agree with Public Interest Organizations that the recent
electricity price overestimations were not unique to QFs and can be
explained by general declines in natural gas prices since the adoption
of hydraulic fracturing and the 2007-2009 recession.\455\ But that is
precisely why the estimates of avoided costs reflected in the QF
contracts and LEOs were incorrect and why the resulting fixed avoided
cost energy rates reflected in such QF contracts and other LEOs
resulted in QF rates well above utility avoided costs in violation of
PURPA section 210(b); the precipitous decline in natural gas prices
caused a corresponding reduction in utilities' energy costs, and thus
in their energy avoided costs but this decline was not reflected in the
QFs' fixed contract rates that remained at their previous levels.
---------------------------------------------------------------------------
\455\ Public Interest Organizations Comments at 47-50.
---------------------------------------------------------------------------
288. Similarly, arguments from commenters that electric utilities
also based resource acquisitions on incorrect forecasts of natural gas
prices \456\ ignore a key distinction between utility rates and fixed
QF rates. Electric utilities may have relied on incorrect natural gas
price forecasts to justify the timing and type of their resource
acquisitions, as commenters assert. But once an electric utility
resource decision was made, their cost-based rate regimes typically
obligated the electric utility eventually to pass through to customers
any energy cost savings realized as a result of declining natural gas
and other fuel prices, as well as any energy cost savings due to lower
purchased power rates resulting from the decline in natural gas prices.
By contrast, once QF avoided cost energy rates were fixed based on now-
incorrect (and now-high) natural gas price forecasts, those energy
rates remained fixed for the term of the QFs' contracts and LEOs.
Therefore, unlike fixed avoided cost energy rates in QF contracts and
LEOs, cost-based electric utility energy rates declined as the cost of
natural gas and other fuels and purchased power declined.
---------------------------------------------------------------------------
\456\ ELCON Comments at 22; North Carolina Commission Staff
Comments at 2-3; NIPPC, CREA, REC, and OSEIA Comments at 31; Public
Interest Organizations Comments at 40, 43; Solar Energy Industries
Comments at 36-38.
---------------------------------------------------------------------------
289. We also disagree with Public Interest Organizations'
assertions that it was improper to have used competitive market hub
prices to determine whether fixed QF contract and LEO prices resulted
in overpayments as compared to electric utilities' actual avoided
costs.\457\ We recognize that the competitive market hub prices used in
the comparisons may not have precisely reflected the avoided energy
costs of all electric utilities located in the same region as the
competitive market hub. However, as explained above in the discussion
of the use of Market Hub Prices to determine avoided energy costs,
competitive market prices in general should reflect the marginal
avoided energy costs of utilities with access to such markets.
Certainly, those markets generally reflect the marginal cost of energy
in the region.\458\ The
[[Page 54677]]
magnitude of the differences between the market hub prices and the QF
contract and LEO prices provides solid evidence that the QF contract
and LEO prices used in the comparison were well above actual avoided
energy costs at the time the energy was delivered by the QFs, even if
the exact magnitude is unclear.
---------------------------------------------------------------------------
\457\ Public Interest Organizations Comments at 40-41.
\458\ A review of recent Mid-C Hub daily spot prices (from
Intercontinental Exchange (ICE) https://www.eia.gov/electricity/wholesale/, indicates that they reflect the marginal cost of energy
in that area since they are usually the result of a significant
number of trades (averaging 54 per day), counterparties (averaging
16 per day), and trading volume (averaging 26,714 MWh/day), which
usually exceed those of the NP-15 trading hub, an active Western
trading hub in Northern California in the CAISO footprint (averaging
6 trades per day, 4 counterparties per day, and 2,756/MWh per day).
The prices for Mid-C ranged between an average of approximately $16/
MWh high price and $13/MWh low price during the recent spring (Mar
19-Jun 20, 2020). During this period the index was reported for 65
trading days for Mid-C and 9 trading days for NP-15.
---------------------------------------------------------------------------
290. We acknowledge that energy prices may increase in the future,
as several commenters point out.\459\ However, as noted by Harvard
Electricity Law, ``energy forecasts have a manifest record of
failure.'' \460\ Moreover, the fact that energy prices may increase in
the future does not eliminate the risk that fixed avoided cost energy
rates could still be above actual avoided costs. That is, if the actual
increase in energy prices is still lower than the forecasted increase
that would form the basis of the fixed avoided cost energy rate, then
the fixed avoided cost energy rate will be above actual avoided energy
costs. Giving states the flexibility to require variable avoided cost
energy rates in QF contracts and in other LEOs will allow states to
better ensure that avoided cost energy payments made to QFs will more
accurately reflect the purchasing utility's avoided costs regardless of
whether energy prices are increasing or declining. We also note that,
if energy prices do in fact increase, variable avoided cost energy
pricing would protect and even benefit the QF itself, as it would not
be locked into a fixed energy rate contract or LEO that would be below
the purchasing electric utility's avoided energy cost.
---------------------------------------------------------------------------
\459\ NIPPC, CREA, REC, and OSEIA Comments at 33-36; Resources
for the Future Comments at 4; sPower comments at 10-11.
\460\ Harvard Electricity Law Comments at 24 (citing Vaclav
Smil, Energy at the Crossroads: Global Perspectives and
Uncertainties, Mass. Inst. Tech., 2003, at 121, 145-149).
---------------------------------------------------------------------------
291. Although many commenters agreed that fixed QF energy rates
were higher than actual avoided energy costs in at least some
instances, challenges were raised against both Duke Energy's estimate
that its fixed QF contract rates were $2.6 billion above market costs,
and the Concentric Report's comparison of QF fixed rates for wind and
solar facilities with the cost of wind and solar projects with
competitive, non-PURPA contracts.
292. However, the expert testimony cited by the SC Solar Alliance,
that the witness ``wouldn't put a whole lot of weight in [Duke's
estimate],'' \461\ does not address Duke's calculation of past
overpayments. Rather, the witness was answering a question regarding
the potential for overpayments ``[f]or going forward solar,'' i.e.,
future overpayments as a result of the new fixed avoided cost rates
being considered by the South Carolina Commission that were the subject
of the expert witness' testimony.\462\ The same witness acknowledged
the past overpayments made by Duke Energy, which he attributed to
``drops in natural gas prices that no one could've foreseen.'' \463\ It
is these overpayments due to unforeseen declines in natural gas prices
that form an important basis for the Commission's determination in this
final rule to now give states the flexibility to require variable
avoided cost energy rates in QF contracts and LEOs.
---------------------------------------------------------------------------
\461\ SC Solar Alliance Comments at 7 (quoting, Public Service
Commission of South Carolina, Docket No. 2019-185 & 186-E, Hearing
Transcript Vol. 2, Tr. at 596: 6-21 (Horii Test)) (attached as
Appendix 1 to SC Solar Alliance Comments).
\462\ Public Service Commission of South Carolina, Docket No.
2019-185 & 186-E, Hearing Transcript Vol. 2, Tr. 596: 3-4 (Horii
Test)) (attached as Appendix 1 to SC Solar Alliance Comments).
\463\ Id. at 593:21-22.
---------------------------------------------------------------------------
293. With respect to the criticisms of the Concentric Report, we
emphasize that we have not relied on that report to support the
variable energy avoided cost provision adopted in the final rule. It is
not clear that the lower cost of the competitively priced renewable
resources identified in the report represents the avoided costs of the
purchasing utilities that entered into the QF contracts at fixed rates
for renewable resources under PURPA. Therefore, it is not clear that
the difference in costs identified by Concentric can be ascribed to the
fixed rates in the QF contracts or rather to the fact that the avoided
cost rates in the QF contracts were based on more expensive non-
renewable capacity that was avoided by the purchasing utilities.
e. Whether the Proposed Change Would Violate the Statutory Requirement
that the PURPA Regulations Encourage QFs
i. Comments
294. Several commenters argue that the NOPR's variable rate
proposal is inconsistent with PURPA's mandate that the PURPA
Regulations ``encourage'' the development of QFs.\464\ Southeast Public
Interest Organizations state that removing QFs' right to a fixed energy
rate would flout Congressional intent that PURPA encourage QF
development because fixed rates are necessary to attract QF
financing.\465\ Harvard Electricity Law states that Congress's mandate
to encourage QFs is not contingent on industry conditions and does not
expire.\466\
---------------------------------------------------------------------------
\464\ Allco Comments at 9; Con Edison at 3, 4; Harvard
Electricity Law Comments at 1; North American-Central Comments at 4-
6; Southeast Public Interest Organizations at 9-11.
\465\ Southeast Public Interest Organizations Comments at 9-10.
\466\ Harvard Electricity Law Comments at 1.
---------------------------------------------------------------------------
ii. Commission Determination
295. As explained above in Section IV.A.1, the statutory
requirement that the Commission's PURPA Regulations encourage QFs
remains, but it is bounded by the statutory provision in PURPA section
210(b) that QF rates may not exceed a purchasing utility's avoided
costs. Further, as explained above, we have determined, based on the
record evidence, that it is not necessarily the case that
overestimations and underestimations of avoided energy costs will
balance out. Consequently, a fixed energy rate in a QF contract or LEO
potentially could violate the statutory avoided cost cap on QF rates.
296. The Commission's PURPA Regulations continue to encourage the
development of QFs by, among other things, allowing a state to vary the
rate paid to the QF over time but in a way that satisfies the rate cap
established in PURPA section 210(b). In this way, the QF can obtain a
higher rate when the utility's avoided costs increase, and ratepayers
are not paying more than the utility's avoided costs when prices
decrease. Furthermore, as discussed above, allowing the use of variable
energy rates may promote longer contract terms, which would help
encourage and support QFs.\467\ It therefore is consistent with PURPA
section 210(b), as well as the obligation imposed by PURPA section
210(a) to revise the Commission's PURPA Regulations ``from time to
time,'' to provide the states the flexibility to require that QF
contracts and other LEOs implement variable avoided cost energy rates
in order to prevent payments to QFs in excess of the purchasing
electric utility's avoided energy costs. PURPA section 210(b) prohibits
the Commission from requiring QF rates above avoided costs even if,
according to some commenters, a fixed avoided cost energy rate would
provide greater encouragement to QFs than a variable avoided cost
energy rate.
---------------------------------------------------------------------------
\467\ See infra P 349.
---------------------------------------------------------------------------
[[Page 54678]]
f. Discrimination
i. Comments in Support of NOPR Proposal
297. Alliant Energy observes that utility-owned generation and
traditional power purchase agreements (PPAs) are subject to a
demonstration of need and that traditional PPAs are subject to re-
evaluation during their term to determine whether they continue to be
cost-competitive and in the best interests of customers. Alliant Energy
asserts that, by contrast, QFs are not required to demonstrate that
their projects are needed and that, once a contract is executed, it is
not subject to re-evaluation.\468\
---------------------------------------------------------------------------
\468\ Alliant Energy Comments at 6-7.
---------------------------------------------------------------------------
ii. Comments in Opposition to NOPR Proposal
298. Several commenters assert that the NOPR's variable avoided
cost energy rate proposal is discriminatory.\469\ For example, EPSA
argues that PURPA requires the Commission to implement regulations
that, for rates for electric utility purchases from QFs, ``shall not
discriminate against qualifying cogenerators or qualifying small power
producers.'' EPSA describes this standard as more restrictive than the
FPA's prohibition against ``unduly discriminatory'' rates. According to
EPSA, the fact that long-term QF contracts are substantially above
prevailing market prices due to declining wholesale prices over the
long-term does not justify the variable rate proposal because electric
utility-owned generation is similarly based on imperfect long-term
forecasts of energy prices that oftentimes prove to be too high. EPSA
therefore argues that the NOPR variable rate proposal should not be
adopted unless utility-owned assets are also subject to a similar cost
recovery regime.\470\
---------------------------------------------------------------------------
\469\ ELCON Comments at 21-22; SC Solar Alliance Comments at 5-
10; sPower Comments at 13; see also ELCON Comments at 22; North
Carolina Commission Staff Comments at 2-3; NIPPC, CREA, REC, and
OSEIA Comments at 31; Public Interest Organizations Comments at 40,
43; Solar Energy Industries Comments at 36-38.
\470\ EPSA Comments at 8-9.
---------------------------------------------------------------------------
299. sPower describes the NOPR proposal to allow variable rates as
providing a significant advantage to electric utilities over QFs, given
that electric utilities themselves, according to sPower, have not had
to lower rates to consumers as energy prices have declined.\471\ ELCON
asserts that pushing more market risk to QFs while utility assets
remain insulated from markets creates an investment risk asymmetry.
ELCON claims this puts QFs at a competitive disadvantage and shifts the
consumer burden to more utility builds, which have generally been
higher cost than merchant builds.\472\
---------------------------------------------------------------------------
\471\ sPower Comments at 13.
\472\ ELCON Comments at 21-22.
---------------------------------------------------------------------------
300. SC Solar Alliance states that utilities often rely on fuel
price forecasts over time to justify rate base approval for generation
assets that might run beyond price forecasts. SC Solar Alliance argues
that allowing utilities this right, but not QFs, holds QFs to a much
higher standard than utilities and therefore is discriminatory.\473\
---------------------------------------------------------------------------
\473\ SC Solar Alliance Comments at 5-10.
---------------------------------------------------------------------------
301. Commissioner Slaughter argues that, by removing the fixed,
long-term contract option for independent power producers, the NOPR
threatens to hamper the competitiveness of renewable-based energy firms
challenging vertically integrated utilities in many localities across
the country.\474\
---------------------------------------------------------------------------
\474\ Commissioner Slaughter Comments at 4.
---------------------------------------------------------------------------
iii. Commission Determination
302. The discrimination claims are based on the incorrect
assumption that electric utilities have not been required to lower
their energy rates as prices have declined. To the contrary, as
explained above, utilities typically charge their customers cost-based
rates, and as their fuel and purchased power costs have declined, they
typically have been required to provide corresponding reductions in the
energy portion of their rates to their customers.\475\ Requiring QF
avoided cost energy rates to likewise change as purchasing electric
utilities' avoided energy costs change does not create a discriminatory
difference, but rather puts QF rates on par with utility rates.
---------------------------------------------------------------------------
\475\ See supra PP 40, 122, 288.
---------------------------------------------------------------------------
303. Further, we are not changing the requirement that QF avoided
cost energy rates be set at the purchasing utility's full avoided
energy costs. As the Supreme Court held in API, ``the full-avoided-cost
rule plainly satisfies the nondiscrimination requirement.'' \476\
Rather, we are allowing the states the option to now choose to require
QF avoided cost energy rates that vary with the purchasing utility's
avoided costs of energy, rather than QF avoided cost rates that are
fixed for the life of the QF's contract or LEO, to ensure the rates
comply with PURPA.
---------------------------------------------------------------------------
\476\ API, 461 U.S. at 413.
---------------------------------------------------------------------------
g. Effect of Variable Energy Rates on Financing
i. Comments in Support of the NOPR Proposal
304. Several commenters state that fixed energy payments are not
necessary for QFs to obtain financing.\477\ Alliant states that it is
on track to be the third largest utility owner-operator of wind
facilities in the United States, with 1.9 GW on its system and in
addition is increasing the pace of solar resource development in its
Wisconsin territory. Alliant states it therefore does not believe that
the proposed change will slow renewable deployment and adoption.\478\
---------------------------------------------------------------------------
\477\ APPA Comments at 16-17; Indiana Commission Comments at 6.
\478\ Alliant Energy Comments at 6.
---------------------------------------------------------------------------
305. Several commenters assert that PURPA's must-purchase
requirement itself should necessarily afford QF developers a degree of
certainty and enables developers to attract capital at advantageous
terms.\479\ The Idaho Commission states that, even if modified as
proposed, QF contract terms would remain superior to competitively bid
renewable projects where the energy is not ``must take'' and
curtailment and other reliability parameters are imposed.\480\
---------------------------------------------------------------------------
\479\ APPA Comments at 16-17; Finadvice Comments at 2; Idaho
Commission Comments at 4; Commissioner O'Donnell Comments at 3.
\480\ Idaho Commission Comments at 4.
---------------------------------------------------------------------------
306. Finadvice and APPA argue that maintaining a fixed capacity
rate, as proposed by the Commission, will help attract capital and
ameliorate any negative effect that the variable energy rate proposal
may impose.\481\ Ohio Commission Energy Advocate argues, as evidence
that QFs can still flourish under a variable energy rate, that the PJM
market has successfully attracted new supplies and ensured resource
adequacy through fixed capacity and variable energy rates.\482\
---------------------------------------------------------------------------
\481\ APPA Comments at 16-17; Finadvice Comments at 2.
\482\ Ohio Commission Energy Advocate Comments at 3-4.
---------------------------------------------------------------------------
307. The Idaho Commission states that variable energy prices
protect the ratepayer while allowing the QF to ensure a stream of
revenue through a longer-term contract. The Idaho Commission affirms
that the rapid growth of non-QF renewable projects and their ability to
obtain financing should quell any concerns about a QF's ability to
obtain financing as long as PURPA's ``must take'' provision
remains.\483\ Commissioner O'Donnell asserts that QFs should bear some
market risk as energy prices rise and fall in a way that balances risks
to all parties.\484\
---------------------------------------------------------------------------
\483\ Idaho Commission Comments at 4.
\484\ Commissioner O'Donnell Comments at 3.
---------------------------------------------------------------------------
308. EEI argues that PURPA does not require the Commission or the
states to implement regulations that guarantee a
[[Page 54679]]
QF's financeability. EEI represents that Congress intended QFs to be
treated similarly to merchant generation and simply required QFs to
have non-discriminatory access. According to EEI, because QFs are not
subjected to the oversight or regulatory responsibilities applicable to
electric utilities, it was not expected or intended that QFs be treated
the same as electric utilities.\485\ Similarly, Duke argues that the
central design criteria for PURPA rates and terms should be customer
indifference, just and reasonableness, and non-discrimination. Duke
Energy states that a design that requires QF financeability as a
criterion will inevitably lead to a QF boom and customer harm.\486\
Duke Energy further asserts that several factors affect financeability
and that, therefore, claims by QFs that they require fixed energy
payments for financing purposes should be rejected.\487\
---------------------------------------------------------------------------
\485\ EEI Comments at 35.
\486\ Duke Energy Comments at 17-18.
\487\ Id. at 13.
---------------------------------------------------------------------------
309. EEI claims QFs that require third-party financing will still
be able to obtain financing if the Commission adopts the proposals in
the NOPR, because they are additional options, in addition to those
currently being used by states, that will be available to determine
avoided costs. EEI maintains that a QF developer will be able to obtain
financing under any of the options, provided it can build a cost-
efficient plant that can profit at an avoided cost rate.\488\ EEI
claims that independent power producers lacking the certainty of the
mandatory purchase obligation are building most renewable generation
today because merchant power plants may be developed and financed using
a variety of hedging and risk management tools, such as commodity
hedges, that lock in cash flows and facilitate construction at the
outset.\489\
---------------------------------------------------------------------------
\488\ EEI Comments at 35-36.
\489\ Id. at 36.
---------------------------------------------------------------------------
310. APPA states that much of the renewable development that has
occurred over the past 20 years has taken place within RTO/ISO
footprints and therefore is largely unaided by PURPA obligations.\490\
---------------------------------------------------------------------------
\490\ APPA Comments at 16-17.
---------------------------------------------------------------------------
311. Duke Energy states that concern about the potential for fixed
avoided cost contract rates exceeding actual avoided costs at the time
of delivery have led both North Carolina and South Carolina to enact
laws placing limits on the length of QF contracts.\491\ The Idaho
Commission states that there is no evidence that variable energy prices
would be fatal to QF development.\492\ The Idaho Commission states that
it reduced contract length on large projects to two years because it
did not interpret the Commission's current rules to allow for a
variable energy rate inside a long-term contract. The Idaho Commission
states that, because its experience dictated that the longer the
contract term, the more inflated the avoided cost rate, the Idaho
Commission set parameters to balance QF interests against utility
ratepayer interests. The Idaho Commission states that an energy rate
established at the time of contract formation that provides for
``revisions to the energy rate at regular intervals, consistent with,
for example, a purchasing electric utility's [integrated resource
planning (IRP)] to reflect updated avoided cost calculations'' would
allow states to consider longer term contracts without putting
ratepayers at risk.\493\ NorthWestern represents that the Montana
Commission has lowered the length of QF contracts from 25 to 15 years
in response to the current requirement that QFs are entitled to fixed
avoided cost rates for energy in their contracts and a concern that
rates calculated at the time a contract is signed are likely to change
over the life of that contract.\494\
---------------------------------------------------------------------------
\491\ Duke Energy Comments at 9; LG&E/KU Comments at 4.
\492\ Idaho Commission Comments at 4.
\493\ Id. (citing NOPR, 168 FERC ] 61,184 at P 5 n.5).
\494\ NorthWestern Comments at 6-7.
---------------------------------------------------------------------------
ii. Comments in Opposition to the NOPR Proposal
312. Many commenters assert that the NOPR's variable energy rate
proposal will result in QFs being unable to obtain financing.\495\
Several commenters also assert that it is discriminatory that utilities
and non-QF generators can rate-base long-term investments and recover
actual operating costs, while the NOPR's proposed rules would deprive
QFs of a reasonable ability to forecast their cost recovery with no
guarantees.\496\
---------------------------------------------------------------------------
\495\ Allco Comments at 9; AllEarth Comments at 2; Biogas
Comments at 2; BluEarth Comments at 2; Biological Diversity Comments
at 8; Commissioner Slaughter Comments at 4; Con Edison Comments at
3, 4; Covanta Comments at 7-8; DC Commission Comments at 6-8;
Distributed Sun Comments at 1; EPSA Comments at 2; Energy Recovery
at 4; Harvard Electricity Law Comments at 5; Massachusetts AG
Comments at 8-9; New England Hydro Comments at 8; NIPPC, CREA, REC,
and OSEIA Comments at 37-38; North Carolina DOJ Comments at 3, 6;
North American-Central Comments at 4-6; Public Interest
Organizations Comments at 6-7; Resources for the Future Comments at
6-7. SC Solar Alliance Comments at 5-7; Southeast Public Interest
Organizations Comments at 9-11; State Entities Comments at 2-3; Two
Dot Wind Comments at 11-13.
\496\ Allco Comments at 9; Commissioner Slaughter at 4; Harvard
Electricity Law Comments at 5; NIPPC, CREA, REC, and OSEIA Comments
at 36-37; Public Interest Organizations Comments at 6-7; Solar
Energy Industries at 29-30.
---------------------------------------------------------------------------
313. Several commenters assert that the NOPR lacks evidence on the
record to conclude that the variable rate proposal would not affect the
ability of QFs to obtain financing.\497\ NIPPC, CREA, REC, and OSEIA
argue that the NOPR contained no record evidence demonstrating how this
proposal would continue to encourage QFs in a non-discriminatory
manner,\498\ and lacks evidence on how QF generation can be financed
without a fixed energy rate.\499\ Similarly, Harvard Electricity Law
asserts that repealing the fixed-price PPA requirement is premised on
irrelevant data and ignores the record, and disagrees with the
Commission's demonstration of information on non-QF capacity to show
that QF development no longer relies on contracts with fixed energy
rates.\500\
---------------------------------------------------------------------------
\497\ NIPPC, CREA, REC, and OSEIA Comments at 29, 46; Harvard
Electricity Law Comments at 22, 25-27; Public Interest Organizations
Comments at 6-7, 33-35.
\498\ NIPPC, CREA, REC, and OSEIA Comments at 29.
\499\ Id. at 46-48.
\500\ Harvard Electricity Law Comments at 22, 25 (citing NOPR,
168 FERC ] 61,184 at PP 69-70, 76).
---------------------------------------------------------------------------
314. Public Interest Organizations assert that testimony from
Southern Company, American Forest and Paper Association, and Solar
Energy Industries, upon which the NOPR relies, states that non-QF
renewable PPAs generally entail fixed energy rates rather than variable
energy rates.\501\ In particular, Public Interest Organizations state
that testimony from Solar Energy Industries, refers to reliance on
fixed rates for energy and/or capacity without describing them as
alternatives but rather ``an acknowledgement that a [power purchase
agreement] may provide fixed capacity in addition to fixed energy
revenue, not a suggestion that a QF can be developed without a
predictable energy revenue stream.'' \502\
---------------------------------------------------------------------------
\501\ Public Interest Organizations Comments at 33-35 (citing
NOPR, 168 FERC ] 61,184, at P 70 n.114 (citing Tech. Conference,
Docket No. AD16-16-000, Tr. at 153, 200 (filed June 30, 2016))).
\502\ Id. at 35 (citing NOPR, 168 FERC ] 61,184, at P 70 n.115
(citing Solar Energy Industries Comments, Docket No. AD16-16-000, at
3 (filed June 30, 2016))).
---------------------------------------------------------------------------
315. Allco describes programs in California, Massachusetts,
Connecticut, and Vermont that offer standard QF contract programs with
variable energy rates, none of which, according to Allco, have led to
the construction of solar projects.\503\ Allco claims that these
programs prove that, without the ability to obtain a fixed long-term
forecasted rate, QF solar energy development will
[[Page 54680]]
not exist.\504\ Southeast Public Interest Organizations assert that
Southeastern states with fixed QF energy rates have seen vigorous QF
development, while Southeastern states with variable energy rates have
seen virtually no QF development, undermining the Commission's
assertion that QFs can be financed without fixed energy rates.\505\
---------------------------------------------------------------------------
\503\ Allco Comments at 10.
\504\ Id. at 9-11.
\505\ Southeast Public Interest Organizations Comments at 9-11,
15-16.
---------------------------------------------------------------------------
316. Covanta and Energy Recovery state that the NOPR's variable
rate proposal would have an especially negative effect on Waste to
Energy facilities.\506\ Covanta states that, because Waste to Energy
depends on finite local tax resources, a loss in energy revenue due to
price variability cannot be easily replaced.\507\ Covanta states that,
without adequate QF pricing and multi-year contracts (and consistent,
predictable pricing throughout the life of the contract), local
governments may be forced to close their Waste to Energy facilities
prematurely, to minimize loss and stranding that investment.\508\
Energy Recovery states that the inability to secure suitable rates
through a long-term contract has closed seventeen Waste to Energy
facilities in the last fifteen years.\509\
---------------------------------------------------------------------------
\506\ Covanta Comments at 7-8; Energy Recovery Comments at 1, 4.
\507\ Covanta Comments at 7-8.
\508\ Id. at 8.
\509\ Energy Recovery Comments at 3.
---------------------------------------------------------------------------
317. NIPPC, CREA, REC, and OSEIA state that the NOPR's anecdotal
reliance on tax incentives to encourage QF development is irrelevant
because these incentives are declining or disappearing, thereby
requiring QFs to rely even more on energy rates.\510\ NIPPC, CREA, REC,
and OSEIA predict that the NOPR's proposed rules would make QF
development riskier and would thereby slow the development of new
technologies such as energy storage, hydrogen fuels, and other advanced
renewable energy technologies.\511\
---------------------------------------------------------------------------
\510\ NIPPC, CREA, REC, and OSEIA Comments at 40-41.
\511\ Id. at 41-42.
---------------------------------------------------------------------------
318. Solar Energy Industries states that financing for QFs differs
from financing for fossil fuel generators because ``much of the cost of
installation is incurred up-front, but once installed, the generation
has little, if any, variable cost.'' \512\ Likewise, Harvard
Electricity Law observes that wind and solar QFs, for example, have
higher capital costs, lower operating costs, and provide energy
intermittently, and therefore have characteristics that may present
different financing challenges as compared to non-QF natural gas fired
capacity.\513\ Similarly, Public Interest Organizations argue that,
unlike independent power producer natural gas generators with fixed
capacity payments and variable energy costs, renewable QFs rely on
fixed energy payments to cover their capital costs given their own
nominal variable energy costs.\514\
---------------------------------------------------------------------------
\512\ Solar Energy Industries Comments at 30.
\513\ Harvard Electricity Law Comments at 26.
\514\ Public Interest Organizations Comments at 33-34.
---------------------------------------------------------------------------
319. NIPPC, CREA, REC, and OSEIA state that the financeability of
generation with fixed capacity prices and variable energy prices inside
RTOs/ISOs is irrelevant to regions that lie outside of RTOs/ISOs.\515\
NIPPC, CREA, REC, and OSEIA criticize the NOPR's reliance on an
independent power producer natural gas turbine's financeability outside
the RTO/ISO context as irrelevant to QFs because these natural gas
turbines receive fixed capacity payments and variable energy payments
to account for the fluctuating price of fuel; whereas a QF would need a
sufficient fixed capacity payment to support financing and an energy
rate that removes market risk.\516\
---------------------------------------------------------------------------
\515\ NIPPC, CREA, REC, and OSEIA Comments at 42-43.
\516\ Id.
---------------------------------------------------------------------------
320. NIPPC, CREA, REC, and OSEIA state that the NOPR's reference to
hedging instruments to reduce risks from fluctuating prices is
irrelevant.\517\ NIPPC, CREA, REC, and OSEIA state that hedging makes
projects less financeable because it increases transaction and
compliance costs for small power producer QFs that cannot afford large
legal divisions and trading floors to employ such hedges.\518\
---------------------------------------------------------------------------
\517\ Id. at 44-45 (citing NOPR, 168 FERC ] 61,184 at P 72 &
n.117).
\518\ Id. at 45-46.
---------------------------------------------------------------------------
321. Resources for the Future states that wind projects have used
bank hedges, synthetic PPAs, and proxy revenue swaps.\519\ Resources
for the Future claims, however, that these products would be
inaccessible to most wind QFs if fixed energy payments are eliminated.
Resources for the Future argues that solar QFs would have even less
access to such hedging given their smaller size and high transaction
costs. Resources for the Future states that QFs under 5 MW in RTO/ISOs
and QFs outside of RTO/ISOs thus would be unable to obtain
financing.\520\
---------------------------------------------------------------------------
\519\ Resources for the Future Comments at 6.
\520\ Id. at 6-7.
---------------------------------------------------------------------------
322. Solar Energy Industries states that QFs in RTO/ISO markets
without a fixed energy rate would require a hedging instrument to
finance their projects. Solar Energy Industries further states that QFs
outside RTO/ISO markets without a fixed energy rate would be unable to
finance their projects because they would have no access to such
hedging mechanisms.\521\ Solar Energy Industries states that the NOPR
failed to consider which markets offer financial products, whether
these financial products are available to QFs outside RTOs/ISOs, and
whether these products will be sufficient to provide financing to
QFs.\522\
---------------------------------------------------------------------------
\521\ Solar Energy Industries Comments at 30.
\522\ Id. at 31.
---------------------------------------------------------------------------
323. Solar Energy Industries states that financing for QFs differs
from financing for fossil fuel generators because much of the cost of
installation is incurred up-front, with virtually no variable costs.
Solar Energy Industries states that, because of this difference,
financiers ``examine the QF's projected revenue stream to ensure that
the revenue stream is sufficient to recover the installed costs plus a
competitive return.'' \523\ Solar Energy Industries reasons that QFs
must therefore know in advance their facility's energy and capacity
values and obtain a legally enforceable contract that fits into common
underwriting models.\524\
---------------------------------------------------------------------------
\523\ Id.
\524\ Id.
---------------------------------------------------------------------------
324. North Carolina DOJ asserts that allowing avoided cost energy
prices to fluctuate could eliminate fixed-price power sales contracts,
thereby making compensation to QFs more volatile and discouraging
renewable energy financing.\525\
---------------------------------------------------------------------------
\525\ North Carolina DOJ Comments at 3.
---------------------------------------------------------------------------
325. Distributed Sun agrees with Commissioner Glick's dissent on
the NOPR that revoking the fixed energy price requirement would halt
the construction of most distributed energy resources.\526\ Solar
Energy Industries states that it is not aware of a meaningful number of
QFs that have been constructed using capacity rates alone or capacity
rates with variable energy rates.\527\
---------------------------------------------------------------------------
\526\ Distributed Sun Comments at 3.
\527\ Solar Energy Industries Comments at 28.
---------------------------------------------------------------------------
326. Mr. Mattson argues that a variable rate or a rate based on a
projected stream of revenues during the contract are not long-term
contracts. Mr. Mattson argues that this violates legislative intent and
precedent and is not viable, suggesting that PURPA requires avoided
cost data to be kept by a utility for public inspection.\528\
---------------------------------------------------------------------------
\528\ Mr. Mattson Comments at 26.
---------------------------------------------------------------------------
327. Western Resource Councils represents that PURPA, in the rural
[[Page 54681]]
Northern Plains and Rocky Mountain West, is the only vehicle for small
businesses to obtain project financing and that variable rates
undermine the certainty of QFs obtaining financing.\529\
---------------------------------------------------------------------------
\529\ Western Resource Councils Comments at 2.
---------------------------------------------------------------------------
328. Public Interest Organizations assert that the NOPR has no
basis to speculate that the Idaho Commission shortened contract lengths
to two years because of the fixed rate requirement or that it would
provide longer contracts if it could require variable energy
rates.\530\ According to Public Interest Organizations, the fact that
no solar and wind QFs have been developed since the Idaho Commission
set a two year contract length, even while they are currently entitled
to fixed rates, shows that allowing variable rates will further
discourage wind and solar QF development.\531\
---------------------------------------------------------------------------
\530\ Public Interest Organizations Comments at 36.
\531\ Id. at 35-38.
---------------------------------------------------------------------------
329. sPower argues that, even with long-term contracts, QFs will
not be viable without fixed energy rates and explains that, if the
Commission seeks to encourage states to offer longer contract terms, it
should just require longer terms.\532\
---------------------------------------------------------------------------
\532\ sPower Comments at 11.
---------------------------------------------------------------------------
330. The DC Commission states that, in the jurisdictions where the
contract length has been adjusted to ``short-term,'' such as Idaho's
two-year contract,\533\ further elimination of the QF fixed price
contract option would discourage or eliminate new small renewable
energy facilities entering the markets, which is not consistent with
PURPA's objective of encouraging the construction of renewable
generation.\534\
---------------------------------------------------------------------------
\533\ DC Commission Comments at 8 (citing NOPR, 168 FERC ]
61,184 at P 77).
\534\ Id.
---------------------------------------------------------------------------
331. NIPPC, CREA, REC, OSEIA, and Public Interest Organizations
argue that the fact that states have shortened the length of QF
contracts in response to fixed energy prices means that the Commission
should require a minimum contract length.\535\ Green Power supports the
creation of longer-term standard contract lengths for both cogeneration
and small power production facilities.\536\ Green Power recommends that
cogeneration developers are offered 5, 8, or 10-year contracts and that
small power producers developers are offered 10, 15, or 20-year
contracts.\537\ Mr. Mattson proposes that long-term contracts, defined
as 20 years or longer, be available to QFs at their discretion.\538\
---------------------------------------------------------------------------
\535\ NIPPC, CREA, REC, and OSEIA Comments at 47-48; Public
Interest Organizations Comments at 6-7.
\536\ Green Power Comments at 2, 10.
\537\ Id. at 10.
\538\ Mr. Mattson Comments at 7-9.
---------------------------------------------------------------------------
332. CARE notes that a purchasing utility's fixed capacity value
may be zero if the state determines that the electric utility has no
need for additional capacity resources. In that circumstance, there
would be no fixed element in an avoided cost contract, which CARE
believes would be inconsistent with the Commission's rationale
justifying variable energy rate contracts.\539\ EPSA similarly argues
that, as noted in the NOPR, an electric utility is not required to pay
for QF capacity that the state has determined is not needed. EPSA
claims that the variable rate proposal therefore would create
substantial uncertainty for QF developers and investors in non-ISO/RTO
regions.\540\
---------------------------------------------------------------------------
\539\ CARE Comments at 4 n.7.
\540\ EPSA Comments at 12.
---------------------------------------------------------------------------
333. American Biogas argues that LMP prices are not sufficient to
sustain existing biogas projects or to increase their number.\541\
Several commenters state that LMP cannot sustain QFs in general.\542\
---------------------------------------------------------------------------
\541\ Biogas Comments at 2.
\542\ BluEarth Renewables Comments at 2; Biological Diversity at
8; Covanta Comments at 9; Public Interest Organization Comments at
43-44.
---------------------------------------------------------------------------
334. NIPPC, CREA, REC, and OSEIA argue that the NOPR proposal to
base QF pricing on LMP or Western EIM will limit competition, because
QFs will be stuck with no long-term assurance of investment recovery,
and thus with no means to finance their projects, while regulated
incumbent utilities will be able to rate-base their generation assets,
thus guaranteeing long-term recovery of their investments.\543\ NIPPC,
CREA, REC, and OSEIA maintain that prices for long-term QF contracts
should be set by reference to long-term price indices or other
indicators that, unlike highly-variable LMP and Western EIM prices,
genuinely reflect the long-term costs of generation avoided by the
purchasing utility.\544\
---------------------------------------------------------------------------
\543\ NIPPC, CREA, REC, and OSEIA Comments at 55-56.
\544\ Id. at 53.
---------------------------------------------------------------------------
iii. Commission Determination
335. As an initial matter, the Commission agrees with commenters
that PURPA does not guarantee QFs a rate that guarantees financing.
PURPA only requires the Commission to adopt rules that encourage the
development of QFs; it does not provide a guarantee that any particular
QF will be developed or profitable. This is evident from the structure
of PURPA, which caps QF rates at the purchasing utility's avoided costs
rather than providing for rates that guarantee the recovery of a QF's
costs. The legislative history confirms that Congress did not intend to
guarantee QF financing. As stated in the PURPA Conference Report, ``the
Conferees recognize that [QFs] are different from electric utilities,
not being guaranteed a rate of return on their activities generally or
on the activities vis-a-vis the sale of power to the utility and whose
risk in proceeding forward in the [QF] enterprise is not guaranteed to
be recoverable.'' \545\
---------------------------------------------------------------------------
\545\ Conf. Rep. at 97-98 (emphasis added).
---------------------------------------------------------------------------
336. Notwithstanding that PURPA does not guarantee QF
financeability, the Commission believes that the variable avoided cost
energy rate option implemented by this final rule will still allow QFs
to obtain financing.
337. Before addressing specific comments on this issue, however, we
reiterate that we are not eliminating fixed rate pricing for QFs. Under
this final rule, QFs will continue to be able to require fixed avoided
cost capacity rates in their contracts and LEOs. Capacity costs, as
relevant here, include the cost of constructing the capacity being
avoided by purchasing utilities as a consequence of their purchases
from QFs. As will be discussed below, a combination of fixed avoided
cost capacity rates and variable energy rates can provide important
revenue streams that can support the financing of QFs.
338. Furthermore, merely because QFs have had access to fixed
avoided cost energy rates does not mean that QFs must have access to
such rates to obtain future financing. Up to now, QFs have had the
right under the PURPA Regulations to both fixed capacity and fixed
energy rates, and we understand that most QFs executing long-term
contracts have exercised this right. Commenters insisting that the
Commission cannot allow states the option to impose variable avoided
cost energy rates without evidence that QFs have obtained financing
under such contract structures \546\ are attempting to impose a
standard that could never be satisfied.
---------------------------------------------------------------------------
\546\ See Solar Energy Industries Comments at 28; NIPPC, CREA,
REC, and OSEIA Comments at 29, 46; Harvard Electricity Law Comments
at 22, 25-27; Public Interest Organizations Comments at 6-7, 33-35.
---------------------------------------------------------------------------
339. In any event, there is ample evidence outside of the PURPA
context demonstrating that generation projects with fixed capacity
rate-variable energy contracts are financeable. As the Commission
explained in detail in the NOPR, since the time of the passage of PURPA
a large new independent power production industry has developed in
[[Page 54682]]
the United States. Like QFs, independent power producers sell power at
wholesale, and have no ability to rate-base their facilities or to
otherwise recover their costs through regulated rates to retail
customers, unlike traditional utilities with franchised service
territories and retail customers. Unlike QFs, however, independent
power producers have had no right to require utilities to purchase
their power or to impose fixed energy cost pricing in their power sales
contracts.\547\
---------------------------------------------------------------------------
\547\ See NOPR, 168 FERC ] 61,184 at P 76.
---------------------------------------------------------------------------
340. The record shows that, even without the right to require long-
term fixed energy rates, non-QF independent power producers
nevertheless have been able to obtain financing for large amounts of
generation capacity, including from renewables. EIA data shows that, in
2019, approximately 44% of all energy produced by natural gas-fired
generation in the United States was generated by independently owned
capacity.\548\ Furthermore, EIA data demonstrates that net generation
of energy by non-utility owned renewable resources in the United States
grew by almost 700% between 2005 and 2018, which speaks to the reality
that renewable resources are able to acquire financing even without the
right to require long-term fixed energy rates.\549\ Based on this data,
we find that the right to require counterparties to pay fixed energy
rates is not essential for the financing of independent power
generation capacity.
---------------------------------------------------------------------------
\548\ EIA, Electric Power Monthly with Data for December 2018,
at tbl. 1.7.B (February 2020), https://www.eia.gov/electricity/monthly/archive/february2020.pdf).
\549\ Id. P 74 (explaining that net generation of energy by non-
utility owned renewable resources in the United States escalated
from 51.7 TWh in 2005 when EPAct 2005 was passed, to 340 TWh in
2018) (citing EIA, Electricity Data Browser, www.eia.gov/electricity/data/browser).
---------------------------------------------------------------------------
341. We acknowledge that a number of different financing mechanisms
were used for this independent power generation capacity, not all of
which will be available to QFs. Nevertheless, we understand that a
standard rate structure employed in the electric industry is a fixed
capacity rate-variable energy rate structure, and that many independent
power production facilities have been financed based on this
structure.\550\ Accordingly, record evidence and historical data
regarding the financing and construction of significant amounts of
independent power production facilities supports the Commission's
conclusion that a fixed capacity rate-variable energy rate structure--
which will apply in those states choosing the variable avoided cost
energy rate option--also will support financing of QFs.
---------------------------------------------------------------------------
\550\ American Public Power Association, How New Generation is
Funded (Aug. 29, 2018), https://www.publicpower.org/blog/how-new-generation-funded (``Beginning in 2015, merchant generation [in
RTOs/ISOs markets] began to increase dramatically from prior years,
amounting to 19.3 percent of new capacity in 2015, 7.2 percent in
2016, and 29.1 percent in 2017.''). In RTOs and ISOs with capacity
markets, merchant generators are compensated through variable energy
rates and fixed capacity rates, along with whatever ancillary
service revenues they can earn.
---------------------------------------------------------------------------
342. For the reasons described below, we do not find compelling the
concerns expressed by some commenters that a fixed capacity rate-
variable energy rate construct may not work for solar and wind
resources, which have high fixed capacity costs and minimal variable
energy costs.\551\ Similarly, we are not persuaded by comments that
point out that energy rates in typical independent power production
contracts are designed to recover the cost of a facility's fuel,
whereas variable energy rates would provide no such guarantee.\552\
---------------------------------------------------------------------------
\551\ See Harvard Electricity Law Comments at 26; Public
Interest Organizations Comments at 33-34; Solar Energy Industries
Comments at 30.
\552\ NIPPC, CREA, REC, and OSEIA Comments at 42-43.
---------------------------------------------------------------------------
343. As an initial matter, as we have noted, the record
demonstrates that the amount of renewable resources being developed
outside of PURPA greatly exceeds the amount of renewable resources
developed as QFs.\553\ Renewable resources developed outside of PURPA
may not have a legal right to long-term contracts with fixed energy
rates, yet nevertheless have been able to obtain financing.
---------------------------------------------------------------------------
\553\ See supra P 240.
---------------------------------------------------------------------------
344. The Commission also disagrees with those commenters who assert
that, as a consequence of the above factors, the Commission should
``require[] the variable energy component to be structured in a way
that removes market risk from the QF.'' \554\ This argument runs
directly counter to one of the fundamental premises of PURPA, which is
that QFs must accept the market risk associated with their projects by
being paid no more than the purchasing utility's avoided cost, thereby
preventing utility retail customers from subsidizing QFs.\555\ PURPA
does not allow the Commission to require QFs to be paid rates above
avoided costs in order to make certain types of QF technologies
financeable. If a state determines that it is necessary to require
variable avoided cost energy rates in order to avoid paying QFs an
above-avoided cost rate, which is a bedrock requirement of PURPA, then
the impact this may have on facilities not financeable with a fixed
capacity rate-variable energy rate contract structure is a direct
result of the requirements of PURPA itself.\556\ Concerns regarding the
alleged mismatch between avoided costs and the costs of renewable
technologies therefore are collateral attacks on the requirements of
PURPA itself, not our proposed implementation of it.
---------------------------------------------------------------------------
\554\ NIPPC, CREA, REC, and OSEIA Comments at 43.
\555\ See Conf. Rep. at 97-98 (stating that the ``risk in
proceeding forward in the [QF] enterprise is not guaranteed to be
recoverable''); accord API, 461 U.S. at 416 (holding that QFs
``would retain an incentive to produce energy under the full-
avoided-cost rule so long as their marginal costs did not exceed the
full avoided cost of the purchasing utility'').
\556\ See Connecticut Authority Comments at 14 (``[C]ontracted
QF rates that take into account New England market conditions would
not deter lenders and investors. Many QFs have no fuel costs and low
variable costs of production; therefore, it is reasonable to find
that these QFs would earn substantial inframarginal rents on energy
sales. Further, QFs may be able to sell RECs and/or participate in
other Connecticut programs.'').
---------------------------------------------------------------------------
345. In the NOPR, the Commission noted the availability of various
hedging devices that would allow QFs to fix or limit the variability of
a variable avoided cost energy rate.\557\ We acknowledge those comments
explaining that hedging tools increase project expense and may not be
available to all QFs.\558\ However, the Commission never intended to
suggest that hedging is cost-free or that it would be appropriate for
all QFs. The commenters all agree that hedging is available for at
least some QFs.\559\ For such QFs, hedging can help provide energy rate
certainty if such certainty is required for financing. To the extent
that certainty is required, then the cost of hedging is a part of the
cost of financing the project that PURPA requires QFs to bear.
---------------------------------------------------------------------------
\557\ NOPR, 168 FERC ] 61,184 at P 72.
\558\ NIPPC, CREA, REC, and OSEIA Comments at 45-46; Resources
for the Future Comments at 6-7; Solar Energy Industries Comments at
30.
\559\ Id.
---------------------------------------------------------------------------
346. Public Interest Organizations cite testimony from the
Technical Conference stating that Southern Company has negotiated non-
QF renewable contracts with fixed energy rates rather than variable
energy rates.\560\ However, that testimony does not support the
contention that the Commission must provide for fixed avoided cost
energy rates for QF contracts and other LEOs. As the cited testimony
notes, Southern agreed to contracts with longer terms and with fixed
energy rates only because the
[[Page 54683]]
renewable energy developers agreed to a rate that was 50 to 60 percent
of the projected long-term avoided cost.\561\
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\560\ Public Interest Organizations Comments at 33-34 (citing
NOPR, 168 FERC ] 61,184 at P 70 n.114 (citing Tech. Conference,
Docket No. AD16-16-000, Tr. 200 (filed June 30))).
\561\ Tech. Conference, Docket No. AD16-16-000, Tr. at 200
(filed June 30). The Commission notes that the PURPA Regulations
specifically permit QFs and utilities to agree to rates that differ
from what the PURPA Regulations require. 18 CFR 292.301(b). As the
testimony cited by the Public Interest Organizations suggests, QFs
that believe fixed energy avoided cost rates are required to obtain
financing are free to offer rate and/or other contractual
concessions in exchange for a fixed rate.
---------------------------------------------------------------------------
347. Certain commenters expressed concern that, when a purchasing
electric utility is not avoiding the construction or purchase of
capacity as a consequence of entering into a contract with a QF, under
the NOPR's proposed rules a state could limit the QF's contract rate to
variable energy payments.\562\ 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.\563\ Nothing in PURPA or the legislative history
of PURPA suggests that the Commission should set QF rates so as to
facilitate the financing of new QF capacity in locations where no new
capacity is needed.
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\562\ CARE Comments at 4 n.7; EPSA Comments at 12.
\563\ See, e.g., City of Ketchikan, 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.'').
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348. In the NOPR, the Commission also observed that the variable
avoided cost energy rate proposal might cause states to make other
changes to their administration of PURPA in ways that would improve the
financeability of QF projects. Most notably, states that had limited
the length of contract terms because of concerns about overpayments for
energy might be willing to allow longer term contracts if the contracts
have variable avoided cost energy rates. Longer term contracts with
fixed avoided cost capacity rates, in turn, would provide greater
revenue assurance to QFs.\564\ The comments submitted in response to
the NOPR support our analysis.
---------------------------------------------------------------------------
\564\ NOPR, 168 FERC ] 61,184 at P 65. Contrary to assertions by
some commenters, the Commission's conclusion in the NOPR about the
possible positive effects of the variable avoided cost energy rate
proposal was not based on speculation. See Public Interest
Organizations Comments at 36. Rather, the Commission relied on
testimony presented at the Technical Conference. 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.'').
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349. Further, there is some evidence that variable avoided cost
energy rates in contracts and LEOs could result in longer-term
contracts.\565\ To be clear, we are not finding that the variable
avoided cost energy rate provision in this final rule will necessarily
lead to longer term contracts and LEOs in every state, nor does our
decision to adopt this provision rely on such a finding.\566\ However,
the record supports the conclusion that the variable avoided cost
energy rate provision could lead to longer term contracts in at least
some states, and that likelihood provides support for the conclusion
that QFs will be able to obtain financing for their projects under this
provision if their costs are indeed below the purchasing utility's
avoided costs.
---------------------------------------------------------------------------
\565\ Idaho Commission Comments at 4 (allowing states to set
variable QF energy avoided costs ``would allow states to consider
longer term contracts without putting ratepayers at risk'') (citing
NOPR, 168 FERC ] 61,184 at 5 n.5).
\566\ We are not finding that variable avoided cost energy rates
would be appropriate only if they cause states to require longer
term contracts, and we are not adopting the suggestion made by
certain commenters that the Commission order states to require
longer contract terms. See NIPPC, CREA, REC, and OSEIA Comments at
47-48; Public Interest Organizations Comments at 6-7; sPower
Comments at 11.
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h. Other Claimed Benefits of Fixed Avoided Cost Energy Rates
i. Comments
350. Public Interest Organizations assert that maintaining the
requirement to pay QFs fixed rates serves as a hedge for consumers
because QFs, unlike utilities, bear their own risks and have provided
``billions of dollars'' in benefits to consumers. Public Interest
Organizations assert that eliminating QFs' rights to fixed rate
contracts ignores these benefits to consumers and puts them at
risk.\567\ Likewise, Solar Energy Industries portrays a fixed energy
rate as providing a hedge to a utility that the purchasing electric
utility may use as a revenue stream in connected markets. Solar Energy
Industries nevertheless argues that, in order to encourage QF
development, the Commission must ensure that QFs know the energy price
at the time of contracting and that utilities publish rates stating the
energy, capacity, and environmental attributes of the QF rate.\568\
---------------------------------------------------------------------------
\567\ Public Interest Organizations Comments at 45-46 (citing S.
Rep. No. 95-442, at 9, 22-23, 33 (1977), as reprinted in 1978
U.S.C.C.A.N. 7903, 7906, 7919-21, 7930; Public Interest
Organizations, Comments, Docket No. AD16-16-000, at 5, 19-21 (Oct.
17, 2018)). In earlier comments in Docket No. AD16-16-000, cited by
Public Interest Organizations in response to the NOPR, Public
Interest Organizations asserted that long-term fixed QF contracts
often act as a hedge that lowers QF financing expenses, which
benefits ratepayers, and insulates ratepayers from fuel price
fluctuations. Public Interest Organizations, Comments, Docket No.
AD16-16-000, at 20-21 (Oct. 17, 2018).
\568\ Solar Energy Industries Comments at 31-32.
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ii. Commission Determination
351. Fixed and variable energy rates each can provide benefits to
electric utility customers. These benefits are the converse of each
other: Variable avoided cost energy rates provide protection to
customers when energy costs decline, and fixed avoided cost energy
rates provide protection to customers when energy costs increase. By
giving the states the flexibility to choose either variable or fixed
avoided cost energy rates in QF contracts and LEOs, the Commission is
giving each state the ability to choose the protection that is best
suited for electric customers in their state, based on each state's
view of what the future may hold and the likelihood that variable
energy avoided costs will exceed fixed energy avoided costs during the
life of a QF contract or LEO.
352. We acknowledge that fixed avoided energy cost rates can serve
as a hedge against future fuel price increases in a way that protects
ratepayers, assuming such price increases actually occur. Given that
PURPA both places an avoided cost cap on QF rates, and requires that
such rates must be just and reasonable to the electric consumers of the
electric utility, we find it is appropriate to provide flexibility to
states to decide how to apportion such risks to their ratepayers in a
way that ensures QF avoided energy cost rates are consistent with
PURPA's requirements (i.e., by using either fixed or variable avoided
cost energy rates to best meet those requirements).
353. We caution, though, that having made that choice, a state is
not free to toggle a QF's contractual rate structure back and forth
unilaterally from one to the other as circumstances change; QFs are
entitled to the certainty that once a state has made its choice with
respect to a particular QF's contract or LEO, that QF's contract or LEO
is not subject to change during the term of that contract or LEO except
by mutual consent.
i. Potential Modifications to NOPR Proposal
i. Comments
354. The California Commission, Connecticut Authority, and
Massachusetts DPU support the variable energy rate proposal and suggest
that, in addition, states be given the discretion
[[Page 54684]]
to require the avoided capacity rate to vary.\569\
---------------------------------------------------------------------------
\569\ California Commission Comments at 27-28; Connecticut
Authority Comments at 14-15; Massachusetts DPU Comments at 8-10.
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355. In contrast, NIPPC, CREA, REC, and OSEIA urge the Commission,
if it allows variable energy rates, to adopt strict parameters for
setting capacity rates in order to provide some predictability to QFs
to allow them to obtain financing. NIPPC, CREA, REC, and OSEIA
recommend that the Commission require forecasted capacity rates be
``offered in a long-term contract of at least 20 years after
commencement of sales under the agreement'' for ``[a]ll years during
the term of the QF's long-term contract after which the utility
forecasted to be capacity deficit in its load and resource balance, as
forecasted in its resource plan in effect at the time of the legally
enforceable obligation'' and ``[a]ny time the utility is planning or
undertaking actions to acquire a major generation resource or a major
capital investment at an aging facility at the time of creation of the
legally enforceable obligation.'' \570\
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\570\ NIPPC, CREA, REC, and OSEIA Comments at 51.
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356. Commissioner O'Donnell urges the Commission to provide
additional guidance to states on the minimum required contract duration
that would enable a QF to obtain financing from investors while
providing sufficient ratepayer protections.\571\
---------------------------------------------------------------------------
\571\ Commissioner O'Donnell Comments at 3.
---------------------------------------------------------------------------
ii. Commission Determination
357. We decline to adopt the California Commission's, Connecticut
Authority's, and Massachusetts DPU's requests to permit a state to
require variable avoided cost capacity rates in addition to variable
avoided cost energy rates. There is a fundamental difference between
avoided energy costs and avoided capacity costs. Unlike avoided energy
costs, which fluctuate with changes in the variable cost of the
purchasing utility's marginal energy resource, a purchasing utility's
avoided capacity cost is determined at the time the utility incurs the
obligation to purchase capacity from a QF rather than self-build a
capacity resource or enter into a power purchase agreement with a third
party. Although a purchasing utility's avoided capacity cost may later
change as additional capacity acquisitions are avoided, the cost of the
capacity avoided by the purchasing utility as a consequence of
purchasing capacity from a particular QF at a particular moment in time
does not change.
358. As a simple illustrative example, if a utility is able to
avoid constructing a new generation facility with a capacity cost of
$10/MW-month as a result of purchasing power from a QF, its avoided
capacity cost is the $10/MW-month capacity cost that it would have been
incurred to construct the new facility. Once the utility commences its
purchases from the QF, it may not need additional capacity, and its
avoided capacity cost for the next QF would drop to $0/MW-month. It
would not be appropriate to then reduce the original QF's avoided
capacity charge to $0/MW-month, however, because the only reason that
the utility does not need additional capacity is because it already
purchased capacity from the original QF in order to avoid the $10/MW-
month capacity cost. That is, without the purchase from the original
QF, the utility would have incurred a capacity cost of $10/MW-month,
and that is the utility's avoided capacity cost for the term of its
contract with the original QF. It would be inappropriate, in other
words, for avoided cost capacity rates to change after they are first
set at the time a LEO (such as a contract) is established.
359. We also decline to adopt the suggestion of NIPPC, CREA, REC,
and OSEIA to adopt additional criteria for establishing avoided
capacity costs, including minimum contract lengths. We believe that the
existing rate-setting provisions adequately set out the criteria that
should be considered by a state in determining avoided capacity
costs.\572\ To the extent that any party believes a state has not
appropriately applied these criteria, that party has recourse to the
enforcement provisions of PURPA sections 210(g) and (h).\573\
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\572\ See 18 CFR 292.304(e).
\573\ See also Policy Statement Regarding the Commission's
Enforcement Role Under Section 210 of the Public Utility Regulatory
Policies Act of 1978, 23 FERC ] 61,304.
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360. We decline to specify a minimum required contract length given
that it is up to states to decide appropriate contract lengths in a way
that accurately calculates avoided costs so as to meet all statutory
requirements.
8. Consideration of Competitive Solicitations To Determine Avoided
Costs
a. NOPR Proposal
361. The Commission in the NOPR proposed 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 cost energy and/or capacity rates using
competitive solicitations (i.e., requests for proposals or RFPs),
conducted pursuant to appropriate procedures.
362. The Commission recognized that one way to enable the industry
to move toward more competitive QF pricing is to allow states to
establish QF avoided cost rates through a competitive solicitation
process. 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.\574\ That rulemaking
proceeding, along with several related proceedings, ultimately was
withdrawn as overtaken by events in the industry.\575\
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\574\ 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, Sales of Power to Qualifying Facilities, and
Interconnection Facilities, FERC Stats. & Regs. ] 32,457 (1988)
(cross-referenced at 42 FERC ] 61,324) (ADFAC NOPR).
\575\ 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, Sales
of Power to Qualifying Facilities, and Interconnection Facilities,
84 FERC ] 61,265 (1998) (terminating ADFAC NOPR proceeding).
---------------------------------------------------------------------------
363. Since then, the Commission held in a 2014 order addressing the
specific facts of the particular competitive solicitation 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 competitive solicitation.\576\ In a separate
proceeding involving a different competitive solicitation, the
Commission declined to initiate an enforcement action where the state
competitive solicitation was an alternative to a PURPA program.\577\
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\576\ See, e.g., Hydrodynamics, Inc., 146 FERC ] 61,193, at PP
31-35 (2014) (Hydrodynamics).
Competitive solicitation processes have been used more recently
in a number of states, including Georgia, North Carolina, and
Colorado. Georgia's competitive solicitation process is described at
Ga. Comp. R. & Regs. 515-3-4.04(3) (2018). North Carolina's
competitive solicitation process is described at 4 N.C. Admin. Code
11.R8-71 (2018). Colorado's competitive solicitation process is
described at sPower Development Co., LLC v. Colorado Pub. Utils.
Comm'n, 2018 WL 1014142 (D. Colo. Feb. 22, 2018).
\577\ 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).
---------------------------------------------------------------------------
364. Given this precedent, the Commission proposed to amend its
regulations to clarify that a state could establish QF avoided cost
rates through an appropriate competitive solicitation process.
Consistent with its general approach of giving states flexibility in
the manner in which they determine
[[Page 54685]]
avoided costs, the Commission did not propose in the NOPR to prescribe
detailed criteria governing the use of competitive solicitations as
tools to determine rates to be paid to QFs, as well as to determine
other contract terms. The Commission stated that 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.
365. Nevertheless, in considering what constitutes proper design
and administration of a competitive solicitation, the Commission found
it was appropriate to establish certain minimum criteria governing the
process by which competitive solicitations are to be conducted in order
for a competitive solicitation to be used to set QF rates. In that
regard, the Commission noted that it 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,\578\ the Bidding NOPR, and the Hydrodynamics
case \579\ all suggest factors that could be considered in establishing
an appropriate competitive solicitation that is conducted in a
transparent and non-discriminatory manner.
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\578\ Allocation of Capacity on New Merchant Transmission
Projects and New Cost-Based, Participant-Funded Transmission
Projects, 142 FERC ] 61,038 (2013).
\579\ 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 competitive solicitation would retain their existing PURPA right
to sell energy as available to the electric utility, if the state
has concluded that such QF capacity puts tendered after an
competitive solicitation 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, 94 FERC ] 61,293 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.'')).
---------------------------------------------------------------------------
366. These factors, as proposed in the NOPR, include, among others:
(a) An open and transparent process; (b) solicitations should be open
to all sources to satisfy the purchasing electric utility's capacity
needs, taking into account the required operating characteristics of
the needed capacity; \580\ (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 proposed
that a state may use a competitive solicitation to set avoided cost
energy and capacity rates, provided that such competitive solicitation
process is conducted pursuant to procedures ensuring the solicitation
is transparent and non-discriminatory. The Commission proposed that
such a competitive solicitation must be conducted in a process that
includes, but is not limited to, the factors identified above which
would be set forth in proposed subsection (b)(8).
---------------------------------------------------------------------------
\580\ See 18 CFR 292.304(e); Windham Solar, 157 FERC ] 61,134 at
PP 5-6.
---------------------------------------------------------------------------
367. In addition, the Commission sought comment on whether it
should provide further guidance on whether, and under what
circumstances, a competitive solicitation can be used as a utility's
exclusive vehicle for acquiring QF capacity.\581\
---------------------------------------------------------------------------
\581\ The Commission proposed that, even if a competitive
solicitation were used as an exclusive vehicle for an electric
utility to obtain QF capacity, QFs that do not receive an award in
the competitive solicitation would be entitled to sell energy to the
electric utility at an as-available avoided cost energy rate.
---------------------------------------------------------------------------
b. Comments
i. Comments in Opposition
368. Several commenters oppose the NOPR proposal to allow states
the ability to set avoided cost energy and capacity rates through a
competitive solicitation such as an RFP.\582\
---------------------------------------------------------------------------
\582\ Allco Comments at 12; Blue Earth Comments at 1-2; Boulder
Comments at 6; CA Cogeneration Comments at 10-11; Green Power
Comments at 1-3; Industrial Energy Consumers Comments at 13.
---------------------------------------------------------------------------
369. Allco states that allowing a state commission to use a
competitive solicitation price is simply giving another tool to a state
commission to eliminate QF projects.\583\ Allco also contends that this
proposal creates an apples and oranges scenario where a competitive
solicitation could be won by solar projects of 80 MWs at a low, steeply
discounted price that may never get built, resulting in a state
commission publishing that as an avoided cost for a 1 MW solar project
connected to the distribution system.\584\ Allco points to California's
Renewable Marketing Adjustment Tariff program as an example of a
competitive solicitation price failure.\585\
---------------------------------------------------------------------------
\583\ Allco Comments at 12.
\584\ Id.
\585\ Id.
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370. CA Cogeneration states that relying on a competitive
solicitation violates PURPA's mandatory purchase obligation, and the
regulations must always preserve the right of a QF to negotiate a
contract for the purchase of its output at an avoided cost rate.\586\
CA Cogeneration states that reliance on a competitive solicitation also
fails to provide the necessary financial and operational encouragement
for combined heat and power.\587\
---------------------------------------------------------------------------
\586\ CA Cogeneration Comments at 10.
\587\ Id. at 11.
---------------------------------------------------------------------------
371. Covanta asserts that the Commission's proposed competitive
solicitation process would disadvantage technologies like Waste to
Energy that are not growing, or are closing facilities.\588\
---------------------------------------------------------------------------
\588\ Covanta Comments at 9.
---------------------------------------------------------------------------
372. Southeast Public Interest Organizations argue that, in the
states that currently require some form of competitive solicitation,
many utilities do not regularly hold competitive solicitations, do not
make competitive solicitations open to all QFs, or do not provide QFs
the ability to sell to the utility outside of a competitive
solicitation process.\589\ Southeast Public Interest Organizations
maintain that the competitive solicitation process can be overly
burdensome and costly for smaller facilities. Southeast Public Interest
Organizations assert that no state requires, and no utility conducts, a
competitive solicitation to determine how best to meet the ongoing
energy needs that it currently meets through the operation of its
existing generation fleet and market purchases.\590\ In particular,
Southeast Public Interest Organizations represent that: (1) Florida
does not require an independent evaluator as part of its competitive
solicitation process; (2) Colorado and Oklahoma allow utilities to
apply for waivers of the competitive solicitation requirement; and (3)
North Carolina allows the incumbent utility to participate in the
competitive bidding process and to receive preferential treatment in
the form of waiving post bid security required for any independently
owned projects.\591\ Southeast Public Interest Organizations conclude
that, while a well-designed and well-implemented competitive
solicitation process could be an appropriate procurement and rate-
setting tool in some cases, competitive solicitations should never be
the only way to set rates or for QFs to sell their output, and close
consideration should be given to determinations of utility capacity
needs that could be manipulated to limit renewable energy
procurements.\592\
---------------------------------------------------------------------------
\589\ Southeast Public Interest Organizations Comments at 26.
\590\ Id. at 26-27.
\591\ Id. at 27.
\592\ Id. at 25-26.
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[[Page 54686]]
373. Mr. Mattson states that precedent and legislative intent
remove competitive solicitations from being a PPA option.\593\ Both Mr.
Mattson and Two Dot Wind point to the Commission's ruling in
Hydrodynamics that ``requiring a QF to win a competitive solicitation
as a condition to obtaining a long-term contract imposes an
unreasonable obstacle to obtaining a legally enforceable obligation.''
\594\ Two Dot Wind also states that competitive solicitations have not
worked in Montana, and that the NOPR's suggestion that competitive
bidding can replace PURPA is not supported by the factual record in
Montana.\595\
---------------------------------------------------------------------------
\593\ Mr. Mattson Comments at 23.
\594\ Id.; Two Dot Wind Comments at 10 (citing Hydrodynamics,
146 FERC ] 61,193).
\595\ Two Dot Wind Comments at 9-10.
---------------------------------------------------------------------------
374. Industrial Energy Consumers expresses concern that the
parameters for competitive solicitations are not sufficiently developed
to ensure a well-structured, fairly administered, transparent, and non-
discriminatory process for procurement, and therefore opposes allowing
a competitive solicitation process to determine avoided costs at this
time.\596\
---------------------------------------------------------------------------
\596\ Industrial Energy Consumers Comments at 13.
---------------------------------------------------------------------------
ii. Comments in Support
375. Several commenters support the NOPR proposal to allow states
the ability to set energy and capacity rates through a competitive
solicitation such as an RFP.\597\
---------------------------------------------------------------------------
\597\ Alaska Power Comments at 1; Distributed Sun Comments at 2;
EEI Comments at 32-33; El Paso Electric Comments at 4; NARUC
Comments at 3; NRECA Comments at 11; South Dakota Commission
Comments at 2-3.
---------------------------------------------------------------------------
376. Multiple commenters, including EEI, NRECA, and the Oregon
Commission, support the notion that the states are in the best position
to tailor the competitive solicitation process to their needs, and that
the Commission should not provide detailed criteria governing the use
of competitive solicitations.\598\ EEI states that the fact that
competitive solicitations may be used to set avoided costs is an idea
nearly as old as PURPA.\599\ EEI also supports the Commission's
proposal for a state to allow a competitive solicitation to be used as
the exclusive vehicle for acquiring QF capacity.\600\ NRECA notes that
numerous NRECA members have already had success using competitive
solicitations to establish both energy and capacity rates in states
where competitive solicitations are permitted.\601\
---------------------------------------------------------------------------
\598\ EEI Comments at 32-33; NRECA Comments at 11; Oregon
Commission Comments at 3-4.
\599\ EEI Comments at 32.
\600\ Id. at 33.
\601\ NRECA Comments at 11.
---------------------------------------------------------------------------
377. Growth and Opportunity Center states that competitive
solicitation processes, in place of avoided cost calculations, provide
better signals to investors of where their electricity is most valuable
because competitive solicitations reflect more informed estimates of
the real-time needs of electricity consumers. Growth and Opportunity
Center contends that the proposed rule changes, by giving states more
latitude to use competitive solicitations in complying with PURPA,
should result in prices for consumers that more accurately reflect
market costs for electricity.\602\ Growth and Opportunity Center also
asserts that in states using competitive solicitation processes,
nondiscrimination rules should be enforced to ensure that solicitations
are competitive and that no providers receive preferential
treatment.\603\
---------------------------------------------------------------------------
\602\ Growth and Opportunity Center Comments at 9.
\603\ Id. at 10.
---------------------------------------------------------------------------
378. The Michigan Commission states that it recently approved using
competitive solicitations to determine avoided capacity costs for a
large electric utility in Michigan.\604\ The Michigan Commission states
that it believes that that recently approved structure aligns with the
Commission's proposal in the NOPR.\605\
---------------------------------------------------------------------------
\604\ Michigan Commission Comments at 4.
\605\ Id. at 5.
---------------------------------------------------------------------------
379. Portland General asserts that, because the output of an
competitive solicitation represents a resource's true market costs, a
competitive solicitation is the correct method to determine avoided
cost.\606\ Portland General states that, given the competitive nature
of competitive solicitations, bidders are highly motivated, which
results in the procurement of resources with high benefit-to-cost
ratios. Portland General cites as an example its recent competitive
solicitation, which resulted in a $40.70-levelized price and reflects a
combination of technologies (wind, solar, and battery), whereas QFs,
which Portland General asserts provide lower capacity, are currently
offered at a $45.19 levelized price for solar energy.\607\
---------------------------------------------------------------------------
\606\ Portland General Comments at 11.
\607\ Id.
---------------------------------------------------------------------------
380. Xcel urges the Commission's to give the states the option of
procuring all needed capacity through competitive bidding
processes.\608\ Xcel strongly believes that states must have the
ability to control capacity additions to ensure that customer needs and
state policy goals are met.\609\ Xcel explains that in many states,
including some in which the Xcel operating companies operate, resource
procurement is accomplished largely through state-administered IRP
processes, which are utilized to ensure a resource mix that meets the
overall public interest in affordable and clean energy. Xcel states
that these carefully calibrated processes can be upset when QFs bring
capacity on to a utility's system that does not align with the state's
vision of its optimal resource mix and when those QFs also attempt to
collect above-market payments from utilities and therefore customers.
Xcel states that Colorado's procurement efforts have been so successful
that in 2016 more than 400 bids for 238 distinct projects were
submitted for Public Service Company of Colorado alone, and that this
process resulted in some of the lowest prices for renewables seen as of
that date, with a median wind price of $19.30/MWh and a median solar
price of $30.96/MWh. Xcel argues that unsolicited puts by QFs, in
contrast, can impede the ability of states to meet their resource
planning goals and can undermine the competitive markets that states
like Colorado have already created or are striving to create.\610\
---------------------------------------------------------------------------
\608\ Xcel Comments at 10.
\609\ Id. at 8.
\610\ Id. at 9.
---------------------------------------------------------------------------
381. North Carolina Commission Staff states that North Carolina has
implemented a competitive solicitation process for solar energy that
complements the PURPA reforms adopted by the state, with the first
solicitation concluding in April 2019.\611\ North Carolina Commission
Staff states that an independent administrator estimated the initial
nominal savings for the competitive solicitation with a 20-year
contract versus traditional avoided cost pricing to exceed $370 million
for the utilities involved.\612\
---------------------------------------------------------------------------
\611\ North Carolina Commission Staff Comments at 3-4.
\612\ Id. at 4.
---------------------------------------------------------------------------
382. Duke Energy shares its state-specific experience with North
Carolina's competitive solicitation for renewable energy as a positive
example.\613\ Duke Energy states that Duke Energy Carolinas, LLC and
Duke Energy Progress, LLC recently completed their Tranche 1
Competitive Procurement of Renewable Energy RFP and procured
approximately 550 MW of new solar capacity for 20-year fixed price
contract terms at a projected savings of approximately $261 million
relative to administratively determined
[[Page 54687]]
forecasts of avoided costs over this same period.\614\
---------------------------------------------------------------------------
\613\ Duke Energy Comments at 10-12.
\614\ Id. at 12.
---------------------------------------------------------------------------
iii. Comments Requesting Modifications/Clarifications
(a) Requests for Clarification and/or Separate Proceedings
383. NIPPC, CREA, REC, and OSEIA argue that the NOPR fails to
explain (1) whether the Commission is proposing to merely clarify that
a state could use the lowest offer prices submitted in a competitive
solicitation to set the avoided costs of energy and capacity on a
prospective basis for any QF seeking a contract until the next
competitive solicitation, or (2) whether the Commission is proposing a
radical change in its precedent by revising its rules to provide that a
QF may only sell under a long-term contract if that QF wins a
competitive solicitation, which NIPPC, CREA, REC, and OSEIA assert
would be contrary to the Hydrodynamics \615\ and Winding Creek \616\
cases.\617\
---------------------------------------------------------------------------
\615\ Hydrodynamics, 146 FERC ] 61,193.
\616\ Winding Creek Solar LLC v. Peterman, 932 F.3d 861.
\617\ NIPPC, CREA, REC, and OSEIA Comments at 62-63.
---------------------------------------------------------------------------
384. NIPPC, CREA, REC, and OSEIA request that any requirement to
win a competitive solicitation to obtain a long-term PURPA contract
should exempt small facilities.\618\ NIPPC, CREA, REC, and OSEIA
further state that the Commission should: (1) Require that the
competitive solicitation include no utility-ownership options; or (2)
if utility-owned generation may result, the competitive solicitation
must be: (i) Administered and scored (not just overseen) by a qualified
independent party, not the utility; (ii) any utility or utility-
affiliate ownership bid must be capped at its bid price and not allowed
traditional cost-plus ratemaking treatment; and (iii) the product
sought, minimum bidding criteria, and detailed scoring criteria must be
made known to all parties at the same time.\619\ Additionally, NIPPC,
CREA, REC, and OSEIA contend that an option for long-term contracts
should remain available for both small QFs and existing QFs outside of
a competitive solicitation.\620\
---------------------------------------------------------------------------
\618\ Id. at 67.
\619\ Id.
\620\ Id. at 67-68.
---------------------------------------------------------------------------
385. The Michigan Commission states that it would welcome guidance
on whether, and under what circumstances, a competitive solicitation
can be used as a utility's exclusive vehicle for acquiring QF
capacity.\621\ Similarly, the Montana Commission recommends that the
Commission provide as much guidance to states as possible regarding the
requirements for transparency and non-discrimination.\622\
---------------------------------------------------------------------------
\621\ Michigan Commission Comments at 5.
\622\ Montana Commission Comments at 3.
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386. The California Commission states that the NOPR does not
provide states any more flexibility than they already have, and the
Commission's final order adopting revised regulations should clearly
state this.\623\
---------------------------------------------------------------------------
\623\ California Commission Comments at 23.
---------------------------------------------------------------------------
387. Several commenters suggest that the Commission should conduct
focused additional processes on this topic.\624\ Advanced Energy
Economy suggests that the Commission conduct one or more workshops or
technical conferences, to explore in detail the specific factors that
would make a utility competitive solicitation process a truly
competitive process of a ``comparative quality'' to competitive
wholesale energy and capacity markets.\625\ Advanced Energy Economy
contends that such workshops or technical conferences could ultimately
be the basis for developing proposed regulations better guiding the
states and electric utilities in implementing open and competitive
solicitation processes to obtain relief from the mandatory purchase
obligation under PURPA section 210(m)(1)(C).\626\ Industrial Energy
Consumers argues that, if the Commission seeks to allow states to rely
on competitive solicitation processes, the Commission should undertake
a separate inquiry, with necessary technical conferences, to develop
specific parameters to govern such processes.\627\ If the Commission
relies directly on competitive solicitation processes in the final
rule, Industrial Energy Consumers states that if, after undertaking the
competitive solicitation, the utility rejects all offers and decides to
self-build, then the all-inclusive price of the self-build option
should at least establish the avoided cost rate for QFs seeking to
develop in that area.\628\ EPSA argues that the Commission should
require further proceedings, including another technical conference, to
discuss the protections that would be necessary in order to have a
genuinely level playing field for competitive solicitations.\629\
---------------------------------------------------------------------------
\624\ Advanced Energy Economy Comments at 13; EPSA Comments at
15-16; Industrial Energy Consumers Comments at 13-14.
\625\ Advanced Energy Economy Comments at 13.
\626\ Id.
\627\ Industrial Energy Consumers Comments at 13-14.
\628\ Id. at 14.
\629\ EPSA Comments at 16.
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388. Commissioner Slaughter states that PURPA sits at the
intersection of competition and regulatory policy in an area of vital
and urgent interest, and that the Commission should establish fair,
non-discriminatory guidelines for competitive solicitations that would
help states and other stakeholders maximize the benefits of competition
from low-cost energy sources, particularly utility-scale renewable
energy facilities.\630\ Commissioner Slaughter states that such
guidelines could form the basis for transitioning many local markets
from administratively determined prices to environments of dynamic
price discovery in which the rapidly decreasing cost of utility-scale
renewable energy can put maximum pressure on both new and pre-existing
fossil fuel-based sources of electricity.\631\
---------------------------------------------------------------------------
\630\ Commissioner Slaughter Comments at 1-2.
\631\ Id. at 3.
---------------------------------------------------------------------------
389. EPSA states that the Commission should ensure that competitive
solicitations are properly designed to ensure that QFs have meaningful
opportunities to compete against resources owned by incumbent utilities
on a level playing field.\632\ EPSA states that the Commission should
use this opportunity to do a full assessment of how competitive
solicitations are working and could be enhanced, while providing
continued protections to prevent discrimination against QFs.\633\ EPSA
also emphasizes that, regardless of whatever competitive solicitation
rules the Commission ultimately adopts, the Commission must continue to
exercise its ``backstop'' oversight and enforcement authority to ensure
that any requirements are implemented in a consistent and appropriate
manner by individual states.\634\
---------------------------------------------------------------------------
\632\ EPSA Comments at 3.
\633\ Id. at 14.
\634\ Id. at 16-17.
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(b) Requests Regarding Proposed Criteria
390. Several commenters requested that the Commission clarify the
criteria that solicitations be conducted at regular intervals.\635\
Several commenters request that the Commission reconsider or remove
that criteria.\636\ sPower argues that the Commission should require
that such competitive solicitations be conducted at a minimum every two
years.\637\ Colorado Independent Energy
[[Page 54688]]
asserts that competitive solicitations should be held at regular
intervals to test the market, and that the Commission should consider
the entire market, not just projects 80 MW and under, in evaluating
whether there are full and competitive opportunities.\638\
---------------------------------------------------------------------------
\635\ APPA Comments at 17-18; Basin Comments at 9; Montana
Commission Comments at 3; sPower Comments at 9-10.
\636\ NorthWestern Comments at 7-8.
\637\ sPower Comments at 9-10.
\638\ Colorado Independent Energy Comments at 9-12.
---------------------------------------------------------------------------
391. Several commenters oppose the requirement for an independent
administrator.\639\ APPA argues that the entire PURPA administrative
construct is designed to entrust to state regulatory authorities the
responsibility to carry out the duties they are assigned under the
Commission's regulations.\640\ NRECA believes that states are in the
best position to determine the need for ``oversight by an independent
administrator'' and recommends this criterion be deleted.\641\ NRECA
requests that, if the Commission retains the requirement that
competitive solicitation processes include some type of oversight,
instead of requiring oversight by an independent administrator, the
Commission should allow states the flexibility to allow electric
utilities to retain a third-party consultant for this purpose.\642\
NRECA contends that many cooperatives have long-standing relationships
with third-party consultants that assist the cooperatives in evaluating
power supply options, and requiring those cooperatives to now use some
other entity (i.e., the independent administrator) would be disruptive
and costly.\643\ Colorado Independent Energy notes that, while
independent evaluators are helpful, they are often employed by
utilities and thus sometimes reluctant to offer third party criticism
of the bid evaluation process.\644\
---------------------------------------------------------------------------
\639\ APPA Comments at 18; NRECA Comments at 11.
\640\ APPA Comments at 18 (citing 16 U.S.C. 824a-3(f) (expressly
calling for state regulatory authorities and nonregulated electric
utilities to implement Commission-issued PURPA regulations)).
\641\ NRECA Comments at 11.
\642\ Id. at 12.
\643\ Id.
\644\ Colorado Independent Energy Comments at 8.
---------------------------------------------------------------------------
392. The Montana Commission requests clarification of the term
``independent administrator'' and ``certified'' as those terms are used
in the proposed revisions to Sec. 292.304(b).\645\
---------------------------------------------------------------------------
\645\ Montana Commission Comments at 3.
---------------------------------------------------------------------------
393. sPower disagrees that a competitive solicitation should ``take
into account the required operating characteristics of the needed
capacity'' in order to produce accurate avoided cost rates and
recommends that a final rule remove that language from condition (ii)
in the Commission's list of conditions that a competitive solicitation
must meet.\646\
---------------------------------------------------------------------------
\646\ sPower Comments at 8.
---------------------------------------------------------------------------
394. Colorado Independent Energy states that, in addition to the
guidelines provided in the NOPR, the Commission should include
additional guidelines, including that fairness of an ``all-source''
competitive solicitation must also be determined based on bid
evaluation and not just on a competitive solicitation. Colorado
Independent Energy asserts that competitive solicitation submissions
can be technology-specific, but not the evaluation or the analysis of
the need to be met by a competitive solicitation. Colorado Independent
Energy asserts that a true all-source selection process must allow
resource planning models to optimize among all bids received without
bias toward QF-eligible technologies such as renewable generation or
cogeneration.\647\
---------------------------------------------------------------------------
\647\ Colorado Independent Energy at 2.
---------------------------------------------------------------------------
395. Several commenters stated that competitive solicitations must
be assessed using the criteria set forth in Allegheny.\648\ EPSA
further states that, while the Allegheny principles provide a good
starting point, additional protections will be required to level the
playing field between independent generators and utilities.\649\ R
Street asserts that, if an auction can meet the Allegheny standard,
then generators in that state would not be eligible for QF
designations. R Street suggests that QFs should not be able to force
their power on utilities if they lose such fairly administered
auctions.\650\
---------------------------------------------------------------------------
\648\ EPSA Comments at 14-15 (citing Allegheny, 108 FERC ]
61,082); R Street Comments at 3-4; Solar Energy Industries
Supplemental Comments, Docket No. AD16-16-000, at 32-37 (filed Aug.
28, 2019).
\649\ EPSA Comments at 15.
\650\ R Street Comments at 3-4.
---------------------------------------------------------------------------
396. Solar Energy Industries asserts that the Commission should
require a purchasing electric utility to provide the state commission,
and make available for public inspection, a post-solicitation report
that: (1) Identifies the winning bidders; (2) includes a copy of any
reports issued by the independent evaluator; and (3) demonstrates that
the solicitation program was implemented without undue preference for
the interests of the purchasing utility or its affiliates. Solar Energy
Industries further assert that the solicitation program should include
clear details regarding the manner in which the bids will be scored and
clearly specify price and non-price criteria under which bids are
evaluated including: (1) Acceptable delivery points and any scoring
deductions for delivery to other points; (2) credit evaluation criteria
and development securing requirements; and (3) performance
requirements.\651\
---------------------------------------------------------------------------
\651\ Solar Energy Industries Supplemental Comments, Docket No.
AD16-16-000, at 21 (filed August 28, 2019).
---------------------------------------------------------------------------
397. Public Interest Organizations argue that the Commission's
proposal does not require that state competitive solicitation
procedures meet the statutory floor established through PURPA that
rates both (1) encourage small power producers and (2) not discriminate
relative to the utility's own generation and other non-QF
generators.\652\ To ensure competitive solicitations actually meet the
statutory criteria, the Commission must ensure that competitive
solicitations meet four minimum standards.\653\ First, Public Interest
Organizations state that solicitations must account for utility-owned
and non-QF generation and cannot be a limited competition between QFs
without the ability to displace non-QF generation.\654\ As an example
of an incorrectly-conducted, and unlawfully-discriminatory, bidding
process, Public Interest Organizations cite the Nevada competitive
solicitation process that is limited to QFs to meet a small, segregated
portion of the utility's energy and unmet capacity requirements.\655\
Second, to ensure that QFs receive the same price that other generation
receives, Public Interest Organizations state that all sources of
supply must compete in the competitive solicitation-- including the
utility's own generation.\656\ Third, Public Interest Organizations
state that the solicitation process cannot be used in any way to
curtail or delay a utility's obligation to purchase from QFs.\657\
Fourth, the ``required operating characteristics of the needed
capacity'' factor suggested in the NOPR cannot be used as a surrogate
to define characteristics of only non-QF generation or to allow a
utility to pick among favored generators.\658\
---------------------------------------------------------------------------
\652\ Public Interest Organizations Comments at 69-70.
\653\ Id. at 70.
\654\ Id.
\655\ Id. at 71-72.
\656\ Id. at 72.
\657\ Id. at 72-73.
\658\ Id. at 73.
---------------------------------------------------------------------------
398. Biogas states that, if QFs are to enter into competitive
solicitations as a vehicle for PURPA, then there must be some
correcting for the inequitable tax and regulatory provisions afforded
to incumbent utilities and select renewable
[[Page 54689]]
technologies, in order to ensure a fair market opportunity.\659\
---------------------------------------------------------------------------
\659\ Biogas Comments at 2.
---------------------------------------------------------------------------
399. American Dams requests that QFs competing against a utility
that can rate base the cost of new generation should be entitled to
similar valuation provided that QF costs are at or less than those of
the utility.\660\
---------------------------------------------------------------------------
\660\ American Dams Comments at 3.
---------------------------------------------------------------------------
(c) Other Requests
400. In their comments to the NOPR, Solar Energy Industries
reference their August 28, 2019 comments in Docket No. AD16-16-
000,\661\ in which they describe the ``SEIA Counterproposal.'' That
document proposes that, where a utility seeks to meet identified
capacity needs through an open, fairly designed, and independently
administered competitive solicitation: (i) The purchasing electric
utility would only have to pay QFs for capacity to the extent that the
purchasing electric utility failed to meet identified need through the
competitive solicitation; and (ii) the QF would be paid for its output
(energy and capacity) at the market rate established through the
competitive solicitation process.\662\
---------------------------------------------------------------------------
\661\ Solar Energy Industries Supplemental Comments, Docket No.
AD16-16-000, at 17-40 (filed Aug. 28, 2019).
\662\ Solar Energy Industries Comments at 38.
---------------------------------------------------------------------------
401. Solar Energy Industries request that the Commission supplement
proposed 18 CFR 292.304(b)(5) to require that: (1) Participants are
provided with complete and transparent information regarding
transmission constraints, levels of congestion, and interconnections;
and (2) the solicitation is linked with the purchasing utility's IRP
and is conducted for the entirety of a utility's anticipated capacity
needs.\663\
---------------------------------------------------------------------------
\663\ Id. at 39.
---------------------------------------------------------------------------
402. Solar Energy Industries request that the Commission expressly
implement safeguards to prevent utility self-dealing and affiliate
abuse, with regard to both price and non-price terms.\664\ Solar Energy
Industries reference their previous comments in this proceeding, which
they state describe practices of PacifiCorp,\665\ NorthWestern,\666\
Duke,\667\ and Xcel \668\ purportedly showing that these utilities have
attempted to reduce QFs' ability to sell while simultaneously seeking
to build and rate base their own substantial renewable resources.\669\
---------------------------------------------------------------------------
\664\ Id.
\665\ Solar Energy Industries Supplemental Comments, Docket No.
AD16-16-000, at 25-28 (filed August 28, 2019).
\666\ Id. at 28-29.
\667\ Id. at 29-31.
\668\ Id. at 21.
\669\ Solar Energy Industries Comments at 40.
---------------------------------------------------------------------------
403. ELCON states that it continues to see shortcomings in
competitive procurement practices across regions.\670\ A current
example ELCON provides is Dominion Energy Virginia's 2019 RFP which,
ELCON argues, limited competition in a manner that all but guarantees
that a Dominion self-build option will prevail because it restricts
participation to new resources only and does not permit an independent
third party to evaluate bids.\671\ Another example ELCON provides is a
recent Entergy Louisiana solicitation through which a natural gas
generating facility was approved despite opposition from Louisiana
industrial consumers who argued that the competitive solicitation was
improperly designed to limit resource options to new construction
comparable to a self-build.\672\
---------------------------------------------------------------------------
\670\ ELCON Comments at 27.
\671\ Id.
\672\ Id. at 28.
---------------------------------------------------------------------------
404. ELCON asserts that, to be competitive, a competitive
solicitation must be transparent, face independent oversight, have
safeguards against affiliate abuse involving transactions between
franchised utilities and their market-based affiliates, and have well-
defined technical parameters.\673\ ELCON states that experiences with
competitive solicitations thus far expose the challenges of achieving a
workably competitive process. ELCON urges the Commission to set a high
bar, with enforcement to verify that a process is sufficiently
competitive.\674\
---------------------------------------------------------------------------
\673\ Id. at 28-29.
\674\ Id.
---------------------------------------------------------------------------
405. NorthWestern states that it supports the Commission's proposal
to use competitive solicitations or RFPs to establish avoided capacity
costs, but not avoided energy costs, because NorthWestern believes that
an energy-only competitive solicitation has no relation to the market
whereas a capacity competitive solicitation does.\675\ NorthWestern
believes that use of a competitive solicitation should be the preferred
vehicle for setting avoided capacity rates for QFs because this will
ensure that the capacity is acquired at the least cost thereby
benefiting customers.\676\
---------------------------------------------------------------------------
\675\ NorthWestern Comments at 7.
\676\ Id.
---------------------------------------------------------------------------
406. Institute for Energy Research states that it would go even
further than the NOPR proposal and require that competitive
solicitations be the default whenever possible, with states having to
justify case-by-case why a non-competitive solicitation is needed,
because solicitation is the best expression of the Congressional
mandate to encourage competition.\677\
---------------------------------------------------------------------------
\677\ Institute for Energy Research Comments at 1.
---------------------------------------------------------------------------
407. Harvard Electricity Law states that the NOPR's proposed 18 CFR
292.304(b)(8)(ii), requiring solicitations must be open to ``all
sources''--could be read as inconsistent with the Commission's CPUC
orders \678\ and the 2019 CARE v. CPUC decision.\679\ Harvard
Electricity Law argues that, if the Commission amends its avoided cost
rules to allow states to set avoided cost rates based on competitive
solicitations, it should clarify that states may set tiered rates, as
the Commission and the U.S. Court of Appeals for the Ninth Circuit has
allowed in the above cases.\680\
---------------------------------------------------------------------------
\678\ Cal. Pub. Utils. Comm'n, 133 FERC ] 61,059, clarification
and reh'g denied, 133 FERC ] 61,059 (2010), reh'g denied, 134 FERC ]
61,044 (2011) (CPUC) .
\679\ Californians for Renewable Energy v. Cal. Pub. Utils.
Comm'n, 922 F.3d 929, 937 (9th Cir. 2019) (CARE v. CPUC) (holding
that ``where a state has [a renewable portfolio standard (RPS)] and
the utility is using a QF's energy to meet the RPS, the utility
cannot calculate avoided costs based on energy sources that would
not also meet the RPS[,]'' which ``comports with PURPA's goal to put
QFs on an equal footing with other energy providers'').
\680\ Harvard Electricity Law Comments at 31.
---------------------------------------------------------------------------
408. The Oregon Commission recommends that the Commission emphasize
the need for states to have adequate safeguards to protect bidders'
confidential and commercially sensitive proprietary information when
using competitive solicitations to determine or inform avoided cost
rates.\681\
---------------------------------------------------------------------------
\681\ Oregon Commission Comments at 4.
---------------------------------------------------------------------------
409. sPower states that the issue of using a competitive
solicitation process to establish avoided cost rates has sometimes been
conflated with using a competitive solicitation process to establish a
LEO, and sPower encourages the Commission to continue to analyze these
distinct issues separately.\682\
---------------------------------------------------------------------------
\682\ sPower Comments at 3.
---------------------------------------------------------------------------
410. Resources for the Future stresses that competitive
solicitations alone would minimize QF costs but would not establish
avoided cost rates, which depend on much more than the cost of QF
generation.\683\ However, used in concert with forward curves,
Resources for the Future states that competitive solicitations could
provide an effective complementary method.\684\
---------------------------------------------------------------------------
\683\ Resources for the Future Comments at 8-9.
\684\ Id. at 9.
---------------------------------------------------------------------------
c. Commission Determination
411. In this final rule, we affirm the NOPR proposal to revise the
PURPA Regulations to explicitly permit a state the flexibility to set
avoided energy and/or capacity rates using competitive solicitations
(i.e., RFPs), conducted
[[Page 54690]]
pursuant to appropriate procedures in a transparent and non-
discriminatory manner. A primary feature of a transparent and non-
discriminatory competitive solicitation is that a utility's capacity
needs are open for bidding to all capacity providers, including QF and
non-QF resources, on a level playing field. This level playing field
ensures that any QF's capacity rates that result from the competitive
solicitation are just and reasonable and non-discriminatory avoided
cost rates.
412. Consistent with our general approach of giving states
flexibility in the manner in which they determine avoided costs, we do
not prescribe detailed criteria governing the use of competitive
solicitations as tools to determine rates to be paid to QFs, as well as
to determine other contract terms. States arguably are 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.
413. In considering what constitutes proper design and
administration of a competitive solicitation, however, we find it
appropriate to establish certain minimum criteria governing the process
by which competitive solicitations are to be conducted in order for an
competitive solicitation to be used to set QF rates. These factors,
which we proposed in the NOPR and adopt here, 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; (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.
414. We affirm that such competitive solicitations must be
conducted in a process that includes, but is not limited to, the
factors identified above that will be set forth in 18 CFR
292.304(b)(8). This rule does not undo any competitive solicitations
conducted prior to the effective date of this final rule that may not
have met these criteria. This rule applies only to competitive
solicitations conducted after the effective date of the final rule. We
also provide modifications and clarifications to the NOPR proposal, as
described below.
i. Requests for Clarification and/or Separate Proceedings
415. As an initial matter, in the NOPR, the Commission addressed
competitive solicitations in two related but distinct contexts. The
first, to be discussed in this section, relates to the proposal to
explicitly permit a state the flexibility to set avoided cost energy
and/or capacity rates using competitive solicitations (i.e., RFPs),
conducted pursuant to appropriate procedures. The second, to be
discussed below, in section IV.G.2 of this final rule, concerns the
NARUC proposal that urged the Commission to give meaning to PURPA
section 210m(1)(C) by establishing a ``yardstick'' by which a
vertically integrated utility outside of an RTO or ISO could apply to
terminate the mandatory purchase obligation if it conducts sufficiently
competitive RFPs for energy or capacity.
416. More generally, we support the use of competitive
solicitations as a means to foster competition in the procurement of
generation and to encourage the development of QFs in a way that most
accurately reflects a purchasing utility's avoided costs. We believe
that allowing QFs to compete to provide capacity and energy needs,
through a properly administered competitive solicitation, may help
ensure an accurate determination of the purchasing electric utility's
avoided cost, and therefore result in prices meeting the PURPA's
statutory requirements. We also believe that it is reasonable for
states to choose to require QFs to be responsive to price signals as to
where and when capacity is needed.
We believe that a properly administered competitive solicitation
can help provide such price signals.
417. Furthermore, we believe that competitive solicitations may be
an especially appropriate tool for developing competition in the
markets outside of RTOs and ISOs, where there are no organized
competitive markets in place where QFs can make sales.
418. We emphasize, however, that neither the Commission's current
regulations, nor those adopted in this final rule, require a state or a
purchasing electric utility to use a competitive solicitation to
determine avoided cost rates for QFs. Consistent with other changes in
our regulations discussed above, we give states the flexibility to use
a properly structured competitive solicitation for this purpose, but we
do not mandate that they do so.
419. Furthermore, in light of the substantial experience the
industry has with competitive solicitations within and outside of the
PURPA context, and the voluminous comments the Commission has received
regarding competitive solicitations, we find that there is not
currently a need for a separate proceeding or additional procedures to
address competitive solicitation issues, such as holding workshops or
technical conferences. Should further procedures appear beneficial in
light of actual competitive solicitation experience under PURPA and the
regulations adopted today, such a proceeding may be appropriate in the
future.
ii. Proposed Criteria
420. We continue to find that competitive solicitations as
discussed in this final rule may accurately reflect a purchasing
electric utility's avoided costs and ensure that the resulting rates
for winners of such competitive solicitations are consistent with
PURPA. A competitive solicitation may more accurately value QF capacity
over time by subjecting it to competition with other sources. Such
competitive solicitations may provide more certainty both to QFs
regarding when and how often they will be eligible to compete and to
purchasing utilities regarding how they may expect to fulfill their
capacity needs.
421. The Commission clarifies that, if a utility acquires all of
its capacity through properly conducted competitive solicitations
(using the factors described above), and does not add capacity through
self-building and purchasing power from other sources outside of such
solicitations, the competitive solicitations could be the exclusive
vehicle for the purchasing electric utility to pay avoided capacity
costs from a QF. In this situation, using properly conducted
competitive solicitations as the exclusive vehicle to determine the
purchasing electric utility's avoided cost capacity rates would allow
QFs a chance to compete to provide the utility's capacity needs on a
level playing field with the utility. We clarify that it is up to the
states to determine whether to require that a utility's total planned
self-build and power purchase options must compete in the competitive
solicitations, and we will not direct such a requirement here.
422. If a state decides to require utility self-build and power
purchase options to participate in competitive solicitations, then a QF
that does not obtain an award in a competitive solicitation would have
no right to an avoided cost capacity rate more than zero because the
utility's full capacity needs would have been met by the competitive
solicitation.\685\ However,
[[Page 54691]]
QFs would continue to have the right to put energy to the utility at
the as-available avoided cost energy rate because the purchasing
utility will still be able to avoid incurring the cost of generating
energy even when it does not need new capacity.
---------------------------------------------------------------------------
\685\ This would be consistent with 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.'').
---------------------------------------------------------------------------
423. If the state does not require utility self-build and purchase
options to participate in competitive solicitations, then QFs that lose
in a competitive solicitation still may have the right to avoided cost
capacity rates more than zero if the state determines that the utility
still has capacity needs after the competitive solicitation that
otherwise could be met through the utility's self-build or purchase
options.
424. The Commission has held and we reaffirm here that, when
capacity is not needed, the avoided capacity cost rate can be
zero.\686\ Competitive solicitations conducted pursuant to the rules
adopted in this final rule that are held whenever capacity is needed
provide QFs a level playing field on which to compete to sell capacity.
This approach further shields purchasing electric utilities from
situations like those explained by Xcel, where QFs could simply sit out
the competitive solicitation process (or participate but not have their
bids accepted), but then seek to sell capacity to the purchasing
electric utility and to receive a separate higher administratively-
determined avoided cost rate including an avoided cost capacity rate,
and even potentially displace non-QF competitive solicitation
winners.\687\ This approach benefits ratepayers because allowing QFs to
compete in properly conducted, competitive solicitations that are held
whenever capacity is needed allows the purchasing utility to obtain
needed capacity efficiently. To be clear, the competitive solicitation
is not to be a means to determine a QF's right to put as-available
energy to the utility. But the competitive solicitation can be the
means to determine what, if any, rate the QF will be paid for capacity.
---------------------------------------------------------------------------
\686\ Id. 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.'').
\687\ See Xcel Comments at 2-3, 9-10.
---------------------------------------------------------------------------
425. Multiple commenters point out that using competitive
solicitations could be a beneficial way to carry out the Congressional
intent behind PURPA. However, many of these same commenters claim that
the competitive solicitations carried out to date do not live up to
this standard. In other words, commenters assert that the competitive
solicitations conducted to date have often not been properly conducted
and instead have been unfair. As described above, assertions about
specific states' competitive solicitation processes include that:
--The competitive solicitations conducted in Florida are unfair because
they do not require an Independent Evaluator as part of the competitive
solicitation process; \688\
---------------------------------------------------------------------------
\688\ Southeast Public Interest Organizations Comments at 27.
---------------------------------------------------------------------------
--the competitive solicitations conducted in Colorado and Oklahoma are
unfair because purchasing electric utilities are allowed to apply for
waivers of the competitive solicitation requirement; \689\
---------------------------------------------------------------------------
\689\ Id.
---------------------------------------------------------------------------
--The competitive solicitations conducted in North Carolina are unfair
because the incumbent purchasing electric utility can receive
preferential treatment in the form of waivers of the post bid security
otherwise required for any independently owned projects; \690\ and
---------------------------------------------------------------------------
\690\ Id.
---------------------------------------------------------------------------
--The competitive solicitations conducted in Nevada are unfair because
the process is limited to QFs to meet a small, segregated portion of
the utility's energy and unmet capacity requirements.\691\
---------------------------------------------------------------------------
\691\ Public Interest Organizations Comments at 71-72.
---------------------------------------------------------------------------
426. Commenters also make assertions about unfair practices of
purchasing electric utilities, including that the purchasing electric
utilities have attempted to reduce QFs' ability to sell while the
purchasing electric utilities are simultaneously seeking to build and
rate base their own substantial renewable resources.
427. The criteria proposed in the NOPR were aimed at ensuring that
competitive solicitations are conducted fairly. In this final rule, the
Commission finds that, in order to use the results of a competitive
solicitation to set avoided cost rates, the competitive solicitation
must be conducted in a transparent and non-discriminatory manner. Such
a competitive solicitation must be conducted in a process that
includes, but is not limited to, the following factors: (i) The
solicitation process is an open and transparent process that includes,
but is not limited to, providing equally to all potential bidders
substantial and meaningful information regarding transmission
constraints, levels of congestion, and interconnections, subject to
appropriate confidentiality safeguards; (ii) solicitations must 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 through a post-solicitation
report.
428. Without judging the competitive solicitations conducted to
date, we find that henceforth any competitive solicitation that does
not comply with these factors will be viewed as not transparent and
discriminatory, and not a basis for either setting the avoided cost
capacity rate that a QF may charge the purchasing electric utility or
limiting which generators can receive a capacity rate. Phrased
differently, we will presume that any future competitive solicitation
that does not comply with the factors adopted in this final rule does
not comply with the Commission's regulations implementing PURPA.
429. In addition, to further promote fairness, the Commission makes
several clarifications, as described below.
430. We clarify that competitive solicitations must also be
conducted in accordance with the Allegheny principles under which the
Commission evaluates a competitive solicitation: (1) Transparency, a
requirement that the solicitation process be open and fair; (2)
definition, a requirement that the product, or products, sought through
the competitive solicitation be precisely defined; (3) evaluation, a
requirement that the evaluation criteria be standardized and applied
equally to all bids and bidders; and (4) oversight, a requirement that
an independent third party design the solicitation, administer bidding,
and evaluate bids prior to selection.\692\ While the NOPR's proposed
guidelines for competitive solicitations were generally inclusive of
the Allegheny principles, in order to more precisely define what is and
what is not a properly conducted competitive solicitation that can be
used to determine what generators will be entitled to an avoided cost
capacity rate, and what that rate will be, we specifically clarify here
that the Allegheny principles apply as well.
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\692\ Allegheny, 108 FERC ] 61,082 at P 18.
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431. We also revise the proposed language in 18 CFR
292.304(d)(8)(i) to clarify that participants must be provided with
substantial and meaningful information regarding transmission
constraints, levels of congestion, and interconnections, subject to
appropriate confidentiality
[[Page 54692]]
safeguards. We believe that it is important that all participants in
the competitive solicitation have access to these data as a necessary
predicate for a nondiscriminatory competitive solicitation process, and
we find that requiring that this information be provided will help
ensure that a competitive solicitation is open and transparent. We
acknowledge the risk that competitive solicitation participants could
use this information to gain a competitive advantage that could be used
outside of the competitive solicitation, but find that this risk can be
minimized through the use of non-disclosure agreements and placing
reasonable limits on those persons permitted to review the information,
just as is done in other Commission proceedings where this issue
arises.
432. We also clarify that the requirement that the competitive
solicitation process be open and transparent includes that the electric
utility provide the state commission, and make available for public
inspection, a post-solicitation report that: (1) Identifies the winning
bidders; (2) includes a copy of any reports issued by the independent
evaluator; and (3) demonstrates that the solicitation program was
implemented without undue preference for the interests of the
purchasing utility or its affiliates. We find this consistent with the
requirement that competitive solicitations be open and transparent, to
not only ensure that utilities are not discriminating against QFs, but
also to help all stakeholders and the public at large better understand
the utility's competitive solicitation processes and thus to be
confident in the fairness of the process and of the results.
433. Regarding the requirement that solicitations must be open to
all sources to satisfy the purchasing electric utility's capacity
needs, taking into account the required operating characteristics of
the needed capacity, we decline to remove the phrase ``taking into
account the operating characteristics of the needed capacity.'' There
may be times when a utility needs capacity with specific attributes,
such as specific ramping capability, that cannot be filled by certain
types of generators. However, we agree with Public Interest
Organizations that this phrase may not be used to define
characteristics of only non-QF generation or to allow a utility to
select favored generators.\693\
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\693\ Public Interest Organizations Comments at 73.
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434. We decline to be overly prescriptive as to what constitutes
``regular intervals.'' In general, utilities should be reviewing their
capacity needs frequently, and the state or nonregulated electric
utility is in the best position to determine the frequency of that
review. However, there may be times when a utility's review of capacity
needs reveals that no capacity is needed, and it would not make sense
for a competitive solicitation to be mandated at such a time.
435. We similarly decline to be overly prescriptive as to what
constitutes an ``independent administrator.'' Commenters argue on both
sides whether the NOPR proposal goes too far or not far enough. On the
one hand, NRECA argues that states are in the best position to
determine the need for oversight by an independent administrator and
recommends this criterion be deleted.\694\ On the other hand, Colorado
Independent Energy notes that independent administrators are often
employed by utilities and thus sometimes reluctant to offer third party
criticism of the bid evaluation process.\695\ We clarify that the
independent administrator, who is responsible for administering the
competitive solicitation, must be an entity independent from the
purchasing electric utility in order to help ensure fairness. Whether
the entity is called an independent administrator or a third-party
consultant, the substantive requirement of this factor is that the
competitive solicitation not be administered by the purchasing electric
utility itself or its affiliates, but rather by a separate, unbiased,
and unaffiliated entity not subject to being influenced by the
purchasing utility. We recognize, however, that such an independent
administrator will need to be selected and paid. Though we are not
directing a process, we note that the selection and payment could be
done under the auspices of a state regulatory authority or by mutual
agreement between the utility and the competitive solicitation
participants.
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\694\ NRECA Comments at 11. In this final rule, we note, for
ease of readability we have used the word ``state'' to refer to both
state regulatory authorities and to nonregulated electric utilities.
Thus, in the context of nonregulated electric utilities in
particular, to say that the ``state'' can fairly administer the
competitive solicitation is to say that the nonregulated electric
utility can, essentially, be both the purchasing electric utility
and potentially the independent administrator of its own competitive
solicitation. That is a result we cannot countenance.
\695\ Colorado Independent Energy Comments at 8.
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436. In response to the Montana Commission's request for
clarification as to what ``certified'' means within the guideline that
requires certification of the competitive solicitation by the state
regulatory authority or nonregulated electric utility as fulfilling the
above criteria, we clarify that, after a thorough review of the
competitive solicitation procedures used and the competitive
solicitation results, certification of the competitive solicitation
requires a written, formally-issued finding by the state that the
competitive solicitation and its results comply with PURPA and this
Commission's PURPA regulations--and must include the independent
administrator's report to the same effect.
437. We decline at this time to add any additional requirements for
competitive solicitations. We continue to believe that states may be in
the best position to consider their particular local circumstances. We
think that the guidelines adopted here, in conjunction with the
Allegheny principles and other clarifications made here, provide an
adequate framework for competitive solicitations to be conducted
efficiently, transparently and in a nondiscriminatory manner.
438. We also clarify that, if a competitive solicitation is not
conducted fairly and in accordance with the guidelines here, then an
aggrieved entity may challenge the state's competitive solicitation in
the appropriate forum, which could include any one or more of the
following: (1) Initiating or participating in proceedings before the
relevant state commission or governing body; (2) filing for judicial
review of any state regulatory proceeding in state court (under PURPA
section 210(g)); or, alternatively (3) filing a petition for
enforcement against the state at the Commission and, if the Commission
declines to act, later filing a petition against the state in U.S.
district court (under PURPA section 210(h)(2)(B)).
iii. Other Requests
439. We decline to grant Solar Energy Industries request to require
that solicitations be linked with the purchasing electric utility's
IRP. Where a state has an IRP,\696\ it may make sense to link the
competitive solicitation processes with the IRP so that the competitive
solicitation is conducted for the entirety of a utility's anticipated
capacity needs. On the other hand, IRPs may come in a variety of forms.
For example, an IRP may merely be a general projection of short- and
long-term load growth and potential resources to meet such growth, and
each generation project may be subject to specific approval based on
actual specific need. In order to provide states flexibility in
conducting these
[[Page 54693]]
processes, we will not require such links between competitive
solicitations and IRPs, although such links certainly are permitted if
a state deems it to be appropriate.
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\696\ 16 U.S.C. 2621(a), (d)(7) (requiring states to consider
whether to employ integrated resource planning).
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440. Regarding facilities not designed primarily to sell
electricity to the purchasing electric utility, such as waste to power
small power production facilities and cogeneration facilities, we find
that an exemption from competitive solicitation processes is
unnecessary. We do not exempt small power production facilities from
the competitive solicitation process; we are not persuaded that such an
exemption is appropriate given that exempting large classes of small
power producers could frustrate the price discovery function of the
competitive solicitation. A large number of exempted small facilities
could disrupt the competitive solicitation process. We clarify,
however, that QFs whose capacity is 100 kW or less already are entitled
to standard rates regardless of whether they compete in a competitive
solicitation and we do not change that regulation in this final
rule.\697\ Given that we view competitive solicitations as an important
price discovery tool and that states already are required to establish
standard rates for such entities, there is no need to determine prices
for QFs at 100 kW or less through a competitive solicitation.
---------------------------------------------------------------------------
\697\ See 18 CFR 292.304(c).
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441. The Commission clarifies that any competitive solicitation
conducted may not force alteration of existing QF contracts. A QF
receiving a capacity payment is entitled to that payment for the
duration of the term of its contract, and a competitive solicitation is
necessarily forward looking based on the results of that auction.
C. Relief From Purchase Obligation in Competitive Retail Markets
1. NOPR Proposal
442. The Commission in the NOPR proposed to add regulatory text at
the end of Sec. 292.303(a) of the PURPA Regulations to provide that a
utility's 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 stated that it was
reasonable for electric utilities' PURPA capacity purchase obligations
to be reduced to the extent retail choice reduces their supply
obligations. To the extent Provider of Last Resort (POLR) supplies are
obtained through solicitations having a particular contract term such
as one year, the Commission proposed that 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.
443. The Commission proposed, 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
intended that this proposal would apply prospectively from the
effective date of a final rule and would not disturb contracts in
effect at the time the utility's supply obligation is reduced.
2. Comments
444. APPA, DTE Electric, EEI, Institute for Energy Research,
NorthWestern, NRECA, Pennsylvania Commission, Portland General, and We
Stand for Energy filed comments in support of the Commission's proposal
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.\698\
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\698\ APPA Comments at 20; DTE Electric Comments at 4-5; EEI
Comments at 41-42; Institute for Energy Research Comments at 1-2;
NorthWestern Comments at 8; NRECA Comments at 13-14; Pennsylvania
Commission Comments at 6-7; Portland General Comments at 12-13; and
We Stand Comments at 1.
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445. New England Small Hydro, NIPPC, CREA, REC, and OSEIA, and
Public Interest Organizations filed opposing comments arguing that the
Commission lacks the statutory authority to implement this proposal
because the Commission lacks discretion to reduce an electric utility's
mandatory purchase obligation except through PURPA section 210(m).\699\
New England Small Hydro claims that PURPA section 210(a) clearly states
that electric utilities must purchase the electric energy from QFs, and
that the Commission does not have the authority to deviate from the
statute.\700\ NIPPC, CREA, REC, and OSEIA argues that the Commission's
existing regulations adequately address the concern at issue because
any reduction in the long-term capacity needs of the utility due to
retail access should be reflected in avoided capacity rates offered to
QFs.\701\ Public Interest Organizations claim that the Commission
proposes to remove state authority by requiring QF contracts with a
POLR to match the term of the POLR's other supply contracts.\702\
Public Interest Organizations also state that even if the Commission
had such authority, there is no evidence in the record to support
matching QF contract lengths with a POLR's other supply contracts.
Public Interest Organizations also assert that the Commission's
proposal unlawfully discriminates against QFs to the extent that it
fails to treat QF contracts in parity with any of a POLR's other supply
contracts.\703\
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\699\ New England Small Hydro Comments at 15-16; NIPPC, CREA,
REC, and OSEIA Comments at 68-69; and Public Interest Organizations
Comments at 74-75.
\700\ New England Small Hydro at 16 (citing Chevron U.S.A., Inc.
v. Nat. Res. Def. Council, 467 U.S. 837 (1984)).
\701\ NIPPC, CREA, REC, and OSEIA Comments at 69.
\702\ Public Interest Organizations Comments at 74.
\703\ Id. at 75.
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446. Biogas and Covanta argue that the rationale for this proposal
is unclear and that the NOPR fails to justify the reduction of a
utility's obligation to purchase QF power based on the amount of any
non-utility generator's supply into the utility's service
territory.\704\ Covanta states that the NOPR incorrectly concludes that
all public power is renewable power.\705\ Biogas and Covanta assert
that the existence of a competitive retail market does not mean there
is a competitive retail market for biogas or waste-to-energy QFs.\706\
Biogas and Covanta also argue that the NOPR would reduce that already
limited market by providing greater leverage to the purchasing electric
utility, and urge the Commission to remove barriers to local government
options for energy purchase rates.
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\704\ Biogas Comments at 2; Covanta Comments at 9.
\705\ Covanta Comments at 9.
\706\ Biogas Comments at 2; Covanta Comments at 9-10.
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447. Ohio Commission Energy Advocate states that under Ohio law, an
electric distribution utility is required to provide consumers within
its certified territory a standard service offer of all competitive
retail electric services necessary to maintain essential electric
services to customers, including a firm supply of electric generation
services.\707\ Ohio Commission Energy Advocate claims that all PUCO-
regulated electric distribution utilities satisfy this obligation
through competitive solicitation for default service within the context
of an electric security plan.\708\ Ohio Commission Energy Advocate
believes that the electric distribution utility should retain the full
purchase obligation because the regulated utility maintains the
obligation to serve as the POLR for all
[[Page 54694]]
``wires-connected'' customers.\709\ Ohio Commission Energy Advocate
also states that it is concerned by the lack of alternatives to the
mandatory purchase obligation and would question any interpretation of
PURPA that contemplates a scenario where no entity has a purchase
obligation for a QF.\710\
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\707\ Ohio Commission Energy Advocate Comments at 5.
\708\ Id. at 6.
\709\ Id. at 6-7.
\710\ Id.
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448. ELCON, California Utilities, Chamber of Commerce, Connecticut
Authority, and Michigan Commission request further clarification on how
the Commission's proposal will be implemented. ELCON states that
industrial customers conditionally support the reduction in obligation
to purchase based on a state retail choice program, subject to the
development of clear and enforceable criteria that exclude mandatory
purchase obligation relief for default supply obligations that
utilities meet with their own generation.\711\
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\711\ ELCON Comments at 19.
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Similarly, California Utilities state that because of the various
ways states have developed restructured retail markets, the Commission
should provide additional guidance as to the various ways that state
commissions can address load reductions due to retail choice while
protecting legacy utilities.\712\ California Utilities explain that
they need Commission guidance to ensure that cost recovery for past and
future mandated QF purchases is equitable to the remaining retail
customers in the legacy utilities' distribution service areas and that
future PURPA mandates or costs are fairly allocated consistent with
cost-causation principles.\713\ Chamber of Commerce states that the
Commission should clarify that the reduction in a utility's QF purchase
obligation is measured against the amount of a utility's load that has
elected an alternative supplier, as opposed to eligible load.\714\
Chamber of Commerce claims that in certain states, only a portion of an
electric utility's load is eligible to select an alternative
electricity supplier and that such percentage would serve as the limit
for any corresponding reduction in a utility's QF purchase obligation.
Michigan Commission states that its retail choice program caps retail
choice at 10 percent of an electric utility's retail customer demand,
and seeks clarification on (1) whether the reduction in a utility's
purchase obligation would equal the reduction in its supply obligation,
be based on the percentage of its customer demand participating in the
state's retail choice program, or some other metric; and (2) how
fluctuations in the state's retail choice program and resulting
purchase obligation should be addressed.\715\
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\712\ California Utilities Comments at 5.
\713\ Id. at 7.
\714\ Chamber of Commerce Comments at 5.
\715\ Michigan Commission Comments at 5-6.
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449. Connecticut Authority supports the proposal to modify
distribution utilities' must-purchase obligations.\716\ Connecticut
Authority states that since Connecticut's electric industry
restructuring, distribution utilities' purchases of QF output have not
been used to serve retail customers, rather the distribution utility
acts as an intermediary selling output into the New England markets.
Connecticut Authority asserts that the Commission should clarify that
the state regulatory authority is responsible for determining the
appropriate adjustment to the distribution utility's must-purchase
obligation and providing notice of such determination to the
Commission.\717\
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\716\ Connecticut Authority Comments at 16.
\717\ Id. at 17.
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450. Connecticut Authority claims that QF output is different from,
and cannot be substituted in for, distribution utility-provided default
standard or last resort services. Connecticut Authority explains that
standard service is procured in six-month tranches, last resort service
is procured in three-month tranches, and that distribution utilities do
not self-manage their default service supply portfolios.\718\
---------------------------------------------------------------------------
\718\ Id.
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451. Connecticut Authority states that while it agrees that
matching the contract terms for default service supply and QF supply
could potentially reduce the burden of over-estimated avoided costs and
give states flexibility to respond quickly to changes to a distribution
utility's default supply obligation, the Commission should not mandate
any term length for the mandatory purchase obligation.\719\ Instead,
Connecticut Authority asserts that the Commission should allow the
state to establish the term based on state-specific circumstances.
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\719\ Id. at 18.
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452. California Utilities request that the Commission reaffirm that
all alternative retail suppliers, including Electric Service Providers
(ESP) and Community Choice Aggregators (CCA), are electric utilities
subject to the PURPA purchase obligation.\720\ California Utilities
explain that ESPs and CCAs are the two types of entities that
California allows to sell power to retail customers in the distribution
service territories of CPUC-regulated utilities, and argues that such
entities meet the definition of electric utility used in PURPA.\721\
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\720\ California Utilities at 9.
\721\ Id. at 9-10.
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453. California Utilities state that the Commission should clarify
that a state has no authority to exempt any traditional or alternative
retail supplier from the PURPA mandatory purchase obligation in order
to ensure QFs that there is a robust market to sell their energy and
capacity to entities that actually serve load in the event a legacy
utility is relieved of all or part of its PURPA obligations.\722\
California Utilities also state that the Commission should clarify that
alternative retail suppliers must make avoided cost information
publicly available to allow QFs to locate and identify potential buyers
that may have higher avoided costs than legacy utilities that have lost
load and may no longer have capacity needs.
---------------------------------------------------------------------------
\722\ Id. at 11.
---------------------------------------------------------------------------
454. California Utilities argue that for states such as California
that allow alternative retail suppliers to opt out of procuring
capacity and require legacy utilities to provide capacity on their
behalf, it would be unfair for legacy utilities to pay a QF any amount
for energy greater than the LMP unless the price differential for which
the legacy utility can sell the energy in the market is paid for by the
alternative retail supplier that was short on capacity.\723\ California
Utilities explain that this would prevent cost shifts to customers who
remain with the legacy utility such that all costs associated with the
mandatory PURPA purchases made by the legacy utility on behalf of the
alternative retail supplier would be borne by customers of the
alternative retail supplier.\724\ California Utilities also argue that
the Commission should clarify that if legacy utilities are required to
procure capacity from QFs on behalf of alternative retail suppliers,
states must require alternative retail suppliers to pay for such QF
purchases at the avoided cost rate set by the state for the legacy
utility for capacity.
---------------------------------------------------------------------------
\723\ Id. at 12.
\724\ Id. at 13.
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455. California Utilities urge the Commission to adopt a stranded
cost regulation addressing PURPA obligations incurred by legacy
utilities that lose load to retail competition consistent with the cost
recovery guarantee in PURPA section 210(m)(7)(A).\725\ California
Utilities argue that such regulation should be clear that prudently
incurred costs include any costs associated with a
[[Page 54695]]
purchase under a state-mandated contract. California Utilities propose
new language to Sec. 292.304(g) regarding implementation of the cost
recovery mandate in section 210(m)(7)(A) of PURPA stating, in part,
that ``[a] state commission may not find any costs associated with any
legally enforceable obligation that it has imposed on an electric
utility imprudent.'' \726\
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\725\ Id. at 14.
\726\ Id. at 15.
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3. Commission Determination
456. In this final rule, we decline to adopt the proposed
regulation permitting states with retail competition to allow relief
from the purchase obligation. We instead clarify that the Commission's
existing PURPA Regulations already require that states, to the extent
practicable, must account for reduced loads in setting QF rates.
457. Specifically, 18 CFR 292.304(e)(3) already does and will
continue to allow states, when setting avoided cost rates, to take into
account ``the ability of the electric utility to avoid costs, including
the deferral of capacity additions.'' We regard this existing
regulation as allowing a state to consider reductions in a purchasing
electric utility's supply obligations given retail competition and the
purchasing electric utility's POLR obligations under state law. We
further clarify that this clarification is not intended to be reflected
as a MW-for-MW reduction (or increase) based on yearly changes in load
and therefore does not and may not serve to terminate a purchasing
utility's mandatory purchase obligation under PURPA section
210(a).\727\
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\727\ 18 CFR 292.304(e)(3).
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D. Evaluation of Whether QFs Are at Separate Sites
1. Rebuttable Presumption of Separate Sites
a. NOPR Proposal
458. The Commission proposed 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 proposed that this change would be effective as of the date
of the 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.
459. The Commission proposed that an entity can seek to rebut the
presumption only for those facilities that are located more than one
mile apart and less than 10 miles apart. The Commission believed 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.\728\ That latter distance, the Commission believed, is 10
miles or more apart. Thus, if two affiliated facilities are one mile or
less apart, they would continue to be irrebuttably presumed to be a
single facility at a single site. If affiliated facilities are 10 miles
or more apart, they would be irrebuttably presumed to be separate
facilities at separate sites.
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\728\ NOPR, 168 FERC ] 61,184 at P 101. As discussed in detail
in section IV.D.1.d below, this final rule will change the
references to ``separate facilities'' or ``the same facility'' to
``at separate sites'' or ``at the same site.''
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460. The Commission proposed that if affiliated facilities are more
than one mile apart and less than 10 miles apart, there would still be
a presumption, but it would 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 10
miles apart and argue that they should be treated as a single facility.
The Commission could also act sua sponte. The Commission proposed that
self-certifications will remain effective after a protest has been
filed, until such time as the Commission issues an order revoking the
certification.
461. The Commission proposed allowing an entity seeking QF status
to provide further information in its certification (both self-
certification and application for Commission certification), to
preemptively defend against rebuttal by asserting factors that
affirmatively show that the affiliated facilities are indeed separate
facilities at separate sites.\729\ 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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\729\ 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 a self-certification or application for Commission
certification), if the QF's status is later challenged (i.e., by a
petition for declaratory order), 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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462. The Commission proposed 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 proposed 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.
463. The Commission proposed that physical and ownership factors
may be asserted to rebut or defend against rebuttal. Noting that no
single factor would be dispositive, the Commission proposed the
following factors: (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 solicited 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.
464. The Commission stated that it will continue to rely on its
definition of ``affiliate'' provided in 18 CFR 35.36(a)(9), and noted
that subsection (iii) provides that the Commission may determine, after
appropriate notice and
[[Page 54696]]
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.\730\ The
Commission intended, 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 stated that it
could take into consideration many of the same factors that would
reasonably be considered in evaluating whether facilities located over
one and less than 10 miles apart are a single facility or separate
facilities.
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\730\ 18 CFR 35.36(a)(9)(iii).
---------------------------------------------------------------------------
465. The Commission believed that this change, together with the
proposed definition of ``electrical generating equipment'' and revision
to the FERC Form No. 556, would more closely align with Congress's
requirement that QFs seeking to certify as small power production
facilities are in fact below the 80 MW statutory limit for such
facilities.\731\
---------------------------------------------------------------------------
\731\ 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'').
---------------------------------------------------------------------------
b. Commission Determination
466. As further discussed and revised in the following sections, we
adopt the NOPR proposal. Henceforth, if a small power production
facility seeking QF status is located one mile or less from any
affiliated small power production QFs that use the same energy
resource, it will be irrebuttably presumed to be at the same site as
those affiliated small power production QFs. If a small power
production facility seeking QF status is located ten miles or more from
any affiliated small power production QFs that use the same energy
resource, it will be irrebuttably presumed to be at a separate site
from those affiliated small power production QFs. If a small power
production facility seeking QF status is located more than one mile but
less than ten miles from any affiliated small power production QFs that
use the same energy resource, it will be rebuttably presumed to be at a
separate site from those affiliated small power production QFs.
467. We adopt the proposal to allow a small power production
facility seeking QF status to provide further information in its
certification (both self-certification and application for Commission
certification) or recertification (both self-certification and
application for Commission recertification), to preemptively defend
against anticipated challenges by identifying factors that
affirmatively show that its facility is indeed at a separate site from
affiliated small power production QFs that use the same energy resource
and that are more than one but less than 10 miles from its facility. We
will correspondingly allow any interested person or entity to challenge
a QF certification (both self-certification and application for
Commission certification) or recertification (both self-recertification
or application for Commission recertification) that makes substantive
changes to the existing certification as further described below).\732\
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\732\ We note that a protester must separately file for
intervention seeking to be made a party to the proceeding; the
filing of a protest does not make that person or entity a party. 18
CFR 385.102(c), 385.211(a)(2).
---------------------------------------------------------------------------
468. As explained in section IV.D.1.f below, we adopt the NOPR's
proposed factors, with certain additions.
469. We adopt the proposal to clarify that challenges to QF status
require that the interested person or entity filing a protest must
specify facts that make a prima facie demonstration that the facility
described in the certification (both self-certification and application
for Commission certification) or recertification (both self-
recertification and application for Commission recertification) does
not satisfy the requirements for QF status. Additionally, any protest
must be adequately supported, with supporting documents, contracts, or
affidavits, as appropriate. General allegations or unsupported
assertions will not provide a basis for denial of certification or
recertification. We additionally limit protests, as described more
fully in section IV.E below, by clarifying that protests may be made to
an initial certification (both self-certification and application for
Commission certification) filed on or after the effective date of this
final rule, but only to a recertification (both self-recertification
and application for Commission recertification) filed on or after the
effective date of this final rule that makes substantive changes to the
existing certification. We adopt the proposal to limit protests by
requiring that once the Commission has affirmatively certified an
applicant's QF status in response to a protest opposing a self-
certification or self-recertification, or in response to an application
for Commission certification or recertification, any later protest to a
recertification (self-recertification or application for Commission
recertification) making substantive changes to a QF's existing
certification must demonstrate changed circumstances from the facts on
which the Commission acted on the certification filing that call into
question the continued validity of the earlier certification.\733\
Finally, the Commission retains the discretion to summarily reject
protests where a protest reiterates arguments already made against the
same QF that the Commission previously denied or otherwise rejected.
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\733\ An interested person or entity can choose to file a
petition for declaratory order, with fee, at any time (that is, not
only within 30 days from the date of the filing of the Form No.
556). However, if the Commission has affirmatively certified an
applicant's QF status in response to a protest opposing a self-
certification or self-recertification, or in response to an
application for Commission certification or recertification, any
later petition for declaratory order protesting the QFs existing
certification must demonstrate changed circumstances from the time
the Commission acted on the certification that call into question
the continued validity of the earlier certification.
---------------------------------------------------------------------------
c. Need for Reform
i. Comments
470. Multiple parties have expressed concern 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
slightly more than one mile apart in order to qualify as separate small
power production facilities.\734\ Several commenters state that the
NOPR-proposed changes will reduce the opportunity for gaming.\735\
---------------------------------------------------------------------------
\734\ See APPA Comments at 21; Center for Growth and Opportunity
Comments at 5-6; Consumers Energy Comments at 4; East River Comments
at 1-2; EEI Comments at 43; ELCON Comments at 35; Governor of Idaho
Comments at 1; Idaho Commission Comments at 5-7; Idaho Power
Comments at 13; Missouri River Energy Comments at 5; Mr. Moore
Comments at 2; Northern Laramie Range Alliance Comments at 2;
NorthWestern Comments at 9; NRECA Comments at 14-15; Portland
General Comments at 14.
\735\ APPA Comments at 21; Center for Growth and Opportunity
Comments at 5-6; Consumers Energy Comments at 4; East River Comments
at 1-2; EEI Comments at 43; ELCON Comments at 35; Governor of Idaho
Comments at 1; Idaho Commission Comments at 5-7; Idaho Power
Comments at 13; Missouri River Energy Comments at 5; Mr. Moore
Comments at 2; Northern Laramie Range Alliance Comments at 2;
NorthWestern Comments at 12; NRECA Comments at 14-15; Portland
General Comments at 14.
---------------------------------------------------------------------------
471. Several commenters argue, to the contrary, that there is no
evidence of
[[Page 54697]]
gaming of the current one-mile rule.\736\ Con Edison argues that
utilities are not overwhelmed with QFs using the one-mile rule and
there is little to no evidence to the contrary.\737\ sPower states that
it is difficult to see how developers that comply with this clear
bright-line rule could be said to be circumventing.\738\ New England
Small Hydro argues that the Commission is attempting to address
perceived abuses of the 80 MW limitation by burdening projects that do
not abuse the system.\739\
---------------------------------------------------------------------------
\736\ Solar Energy Industries Comments at 51; Southeast Public
Interest Organizations Comments at 31; SC Solar Alliance Comments at
19.
\737\ Con Edison Comments at 5.
\738\ sPower Comments at 5.
\739\ New England Small Hydro Comments at 17.
---------------------------------------------------------------------------
ii. Commission Determination
472. The record shows that, since the establishment of the one-mile
rule in the PURPA Regulations in 1980, the development of large numbers
of affiliated renewable resource facilities, requires a revision of the
one mile-rule. We find that the final rule will reduce the opportunity
for developers of small power production facilities to circumvent the
current one-mile rule by strategically siting small power production
facilities that use the same energy resource slightly more than one
mile apart.\740\ While such circumvention may not be an everyday
occurrence, we agree with commenters that the record demonstrates it is
still a sufficient possibility under the current regulations that the
Commission is justified in addressing it in order to comply with the
statute.\741\ The final rule, as adopted, still retains the presumption
that small power production QFs more than one mile apart are located at
separate sites, but simply makes the presumption rebuttable for small
power production QFs located more than one mile but less than 10 miles
apart, allowing the Commission the ability to address those
circumstances.
---------------------------------------------------------------------------
\740\ The regulation, in practice, is only of consequence if the
facilities located ``at the same site'' would exceed a power
production capacity of 80 MW, as that is the size limit for a small
power production facility to qualify as a QF. 16 U.S.C.
796(17)(A)(ii).
\741\ See APPA Comments at 21; Center for Growth and Opportunity
Comments at 5-6; Consumers Energy Comments at 4; East River Comments
at 1-2; EEI Comments at 43; ELCON Comments at 35; Governor of Idaho
Comments at 1; Idaho Commission Comments at 5-7; Idaho Power
Comments at 13; Missouri River Energy Comments at 5; Mr. Moore
Comments at 2; Northern Laramie Range Alliance Comments at 2;
NorthWestern Comments at 9; NRECA Comments at 14-15; Portland
General Comments at 14.
---------------------------------------------------------------------------
d. Site Definition
i. Comments
473. Solar Energy Industries state that, in El Dorado County Water
Agency, the Commission found that ``the critical test under PURPA
relates to whether the facilities are located at one site rather than
whether they are integrated as a project.'' \742\ Solar Energy
Industries argue that the proposed rule, as drafted, abandons the focus
on whether the facilities are located at one site and transforms it
into an analysis as to whether affiliated QFs are part of the same
project. Solar Energy Industries similarly contend that it is arbitrary
to change from a ``same site'' to an ``integrated project''
standard.\743\
---------------------------------------------------------------------------
\742\ Solar Energy Industries Comments at 60 (quoting El Dorado
Cty. Water Agency, 24 FERC ] 61,280, at 61,578 (1983)).
\743\ Id. at 61-62.
---------------------------------------------------------------------------
474. NIPPC, CREA, REC, and OSEIA state that the existing rule is a
reasonable means of implementing the statutory phrase ``same site,''
particularly given the statutory directive to encourage QF development,
and state that they prefer the current bright line rule.\744\ Allco
argues that the proposed rule is divorced from the statutory use of
``site.'' Allco asserts that the Commission lacks authority to define
the term ``site'' in a manner other than one reasonably related to its
ordinary meaning and argues that the Commission's definition of site
arbitrarily limits QF development for no apparent reason.\745\ The DC
Commission would like the Commission to leave the resolution of certain
disputes over whether QFs are separate to state commissions.\746\ Idaho
also requests that states be given as much discretion as possible.\747\
---------------------------------------------------------------------------
\744\ NIPPC, CREA, REC, and OSEIA Comments at 70.
\745\ Allco Comments at 16.
\746\ DC Commission Comments at 9.
\747\ Idaho Comments at 1.
---------------------------------------------------------------------------
475. EEI states that the interpretation of ``same site'' is
determined by the Commission, and that there is nothing in the statute
that prevents the Commission from modifying its interpretation of the
term ``same site.'' \748\
---------------------------------------------------------------------------
\748\ EEI Comments at 42.
---------------------------------------------------------------------------
ii. Commission Determination
476. We modify the NOPR proposal to change terminology relating to
the determination of whether small power production facilities are
separate facilities to focus not on whether they are separate
facilities, but rather to mirror the statutory language and thus focus
on whether they are at ``the same site.'' In that regard, we change
references to ``separate facilities'' or ``the same facility'' to ``at
separate sites'' or ``at the same site.''
477. The NOPR refers to determining whether affiliated facilities
are ``separate facilities'' or ``a single facility.'' However, both the
statute and the existing regulations contemplate that the Commission
will determine what is ``the same site,'' \749\ and do not require the
Commission to determine whether two facilities are a single facility.
The statute defines a small power production facility as an eligible
facility, which, together with other facilities located at the same
site (as determined by the Commission), has a power production capacity
no greater than 80 MW,\750\ and the Commission's regulations have long
approached the matter as defining how to determine ``the same site.''
\751\ We find that the Commission's determination of whether or not a
small power production facility is a QF (i.e., exceeds a power
production capacity of 80 MW) should continue to be focused on whether
the small power production facility seeking QF status and other nearby
affiliated small power production QFs are at the same site or at
separate sites.
---------------------------------------------------------------------------
\749\ 16 U.S.C. 796(17)(A)(i); 18 CFR 292.204(a).
\750\ 16 U.S.C. 796(17)(A)(i).
\751\ 18 CFR 292.204(a).
---------------------------------------------------------------------------
478. We also modify the NOPR proposal to change the irrebuttable
and rebuttable presumptions regarding affiliated facilities to instead
apply to affiliated small power production qualifying facilities. As
noted, the NOPR refers to determining whether affiliated facilities are
``separate facilities'' or ``a single facility.'' We find that only
affiliated small power production QFs are relevant to the determination
of whether the small power production facility seeking QF status and
other nearby facilities are at the same site or separate sites.\752\
Correspondingly, as further detailed below, we will allow entities
challenging a QF certification (both self-certification and application
for Commission certification) or recertification (both self-
recertification and application for Commission recertification) to
rebut the presumption that a small power production facility seeking QF
status is at a separate site from any affiliated small power production
QFs that use the same energy resource and that are located
[[Page 54698]]
more than one but less than 10 miles from it.\753\
---------------------------------------------------------------------------
\752\ We note, however, that, in the context of a PURPA section
210(m) proceeding, all affiliates are relevant in evaluating whether
a QF has nondiscriminatory access to a competitive market.
\753\ Though not at issue here, we also note that the facilities
need to use the same energy resource. 18 CFR 292.204(a)(1).
---------------------------------------------------------------------------
479. We therefore modify the language proposed in the NOPR. In sum,
we find that if a small power production facility seeking QF status is
located one mile or less from any affiliated small power production QFs
that use the same energy resource, it will be irrebuttably presumed to
be ``at the same site'' as those affiliated small power production QFs
(rather than a single facility at a single site, as proposed in the
NOPR). The Commission finds that if a small power production facility
seeking QF status is located ten miles or more from any affiliated
small power production QFs that use the same energy resource, it will
be irrebuttably presumed to be at a separate site from those affiliated
small power production QFs (rather than separate facilities at separate
sites, as proposed by the NOPR). We find that if a small power
production facility seeking QF status is located more than one but less
than ten miles from any affiliated small power production QFs that use
the same energy resource, it will be rebuttably presumed to be at a
separate site from those affiliated small power production QFs (rather
than separate facilities at separate sites, as proposed in the NOPR).
480. Purchasing electric utilities and others will be able to file
a protest and identify factors attempting to rebut the presumption for
a small power production facility seeking QF status that has an
affiliated small power production QF that uses the same energy resource
more than one but less than 10 miles from it, and argue that the small
power production facility seeking QFs status should be treated as ``at
the same site'' as the affiliated small power production QF located
more than one but less than 10 miles from it (rather than as a single
facility, as proposed in the NOPR). We will allow a small power
production facility seeking QF status to provide further information in
its certification (both self-certification and application for
Commission certification) or recertification (both self-recertification
and application for Commission recertification) to preemptively defend
against rebuttal by identifying factors that affirmatively show that
its facility is indeed at a separate site from an affiliated small
power production QF located more than one but less than 10 miles from
it (rather than separate facilities at separate sites, as proposed in
the NOPR).
481. Regarding the requests to allow states to decide whether
affiliated small power production QFs are located at separate sites, we
note that, in PURPA section 201, now codified in section 3 (17) of the
FPA, Congress authorized the Commission to determine whether the
applicant and other facilities are located at the same site. This
Commission will therefore continue to make these determinations.
e. Distance Between Facilities
i. Comments
482. Several commenters contend that the proposal to institute a
rebuttable presumption for facilities that are more than one mile but
less than 10 miles apart is arbitrary and lacks sufficient supporting
evidence.\754\ ELCON notes that the choice of 10 miles as the threshold
is not supported by any evidence.\755\
---------------------------------------------------------------------------
\754\ Allco Comments at 16; Ares Comments at 7; Borrego Solar
Comments at 4; ELCON Comments at 19; Public Interest Organizations
Comments at 93; SC Solar Alliance Comments at 17; Solar Energy
Industries Comments at 60, 62.
\755\ ELCON Comments at 35-36.
---------------------------------------------------------------------------
483. Regarding the proposed rebuttable presumption for QFs more
than one but less than 10 miles apart, Terna Energy argues that the
NOPR effectively increases the ``exclusion zone'' around a QF's
electrical generating equipment from approximately three square miles
(3.1415 square miles, the circle with one-mile radius around the QF's
electrical generating equipment, assuming a point generating source) to
over 300 square miles (i.e. a 10-mile radius circle), a 100-times
increase to the ``exclusion area'' for a single QF.\756\
---------------------------------------------------------------------------
\756\ Terna Energy Comments at 4.
---------------------------------------------------------------------------
484. New England Small Hydro notes that hydroelectric generators
are located where river conditions are ideal for generating and that,
while they are not generally located within one mile, there may be some
projects owned by affiliates that are within 10 miles of each
other.\757\
---------------------------------------------------------------------------
\757\ New England Small Hydro Comments at 17.
---------------------------------------------------------------------------
485. Borrego Solar opposes applying the proposed changes to the
one-mile rule to distributed generation and finds that it would
restrict the ability of developers to follow market signals when
locating projects and significantly increase the regulatory burden.
Borrego Solar notes that there are several reasons that otherwise
different projects from the same company would be within 10 miles of
each other, including land zoning restrictions, available substation
capacity, and optimal topology or insolation.\758\ Borrego Solar notes
that it is common for projects on the distribution system to be within
two miles of a substation or three-phase lines to reduce
interconnection costs. Borrego Solar states that it is also common for
multiple unaffiliated developers to site their projects in a single
area within just a few miles of each other, and later sell those
projects to a single entity much later in the process, inadvertently
violating the Commission's rules.\759\ Borrego Solar would like the
Commission to exclude projects directly interconnected to the
distribution system or initially developed by different entities from
any presumption of common development. Borrego Solar urges the
Commission to, at a minimum, establish a streamlined, low-cost option
for challenging any presumption of common development, to avoid casting
a chill over project development and driving developers and long-term
owners out of the market due to the risks of having the projects
disqualified.\760\
---------------------------------------------------------------------------
\758\ Borrego Solar Comments at 3-4.
\759\ Id. at 4.
\760\ Id. at 5.
---------------------------------------------------------------------------
486. North Carolina DOJ argues that the proposed rule, by
discouraging facilities from being placed close to one another, also
runs counter to a North Carolina policy based on efficient use of
electric resources.\761\ North Carolina DOJ and North Carolina
Commission Staff state that the rules in North Carolina incentivize the
installation of production facilities close to substations so projects
naturally appear in clusters surrounding transmission and distribution
infrastructure.\762\ North Carolina DOJ says that the proposed rule
fails to take into account the complex and regionally specific factors
driving the siting, financing, operation, and maintenance of production
facilities.\763\
---------------------------------------------------------------------------
\761\ North Carolina DOJ Comments at 8.
\762\ Id.; North Carolina Commission Staff Comments at 6.
\763\ North Carolina DOJ Comments at 6.
---------------------------------------------------------------------------
487. Industrial Energy Consumers state that the NOPR does not
distinguish between merchant small power production QFs built to sell
electricity to third parties and self-supply QFs built primarily to
support manufacturing or industrial processes. Industrial Energy
Consumers state that there are many manufacturing company sites that
are of a 10-mile length. Industrial Energy Consumers state that the
Commission's proposed changes to the one-mile rule should be clarified
to exclude ``self-supply'' QFs.\764\
---------------------------------------------------------------------------
\764\ Industrial Energy Consumers Comments at 16.
---------------------------------------------------------------------------
488. Solar Energy Industries believes that for facilities less than
one mile
[[Page 54699]]
apart the Commission should continue to waive the rule where
appropriate.\765\
---------------------------------------------------------------------------
\765\ Solar Energy Industries Comments at 60-61 (citing
Windfarms, Ltd., 13 FERC ] 61,017, at 61,032 (1980) (Windfarms)).
---------------------------------------------------------------------------
489. Regarding the proposed irrebuttable presumption that
facilities located more than 10 miles apart are separate facilities,
NorthWestern urges the Commission to consider increasing the distance.
NorthWestern explains that its operations in Montana are geographically
very expansive and 10 miles in Montana is not a substantial distance,
especially when compared to other states that are geographically much
smaller. NorthWestern states that Montana's electric system has more
than 24,450 miles of electric transmission and distribution lines to
serve approximately 374,000 customers, and that its electric operations
are very rural and cover more than 97,500 square miles.\766\
NorthWestern therefore recommends that the Commission consider
expanding this distance to accommodate utilities in the West that have
very large service territories.\767\
---------------------------------------------------------------------------
\766\ NorthWestern Comments at 10.
\767\ Id.
---------------------------------------------------------------------------
ii. Commission Determination
490. We adopt the NOPR proposal that an entity can seek to rebut
the presumption of separate sites only for an entity seeking small
power production QF status with an affiliated small power production QF
or QFs that are located more than one and less than 10 miles from it.
491. We recognize, as we have previously for the one-mile
rule,\768\ that it is debatable as to where exactly these thresholds
are most appropriately set. PURPA requires that no small power
production facility, together with other facilities located ``at the
same site,'' exceed 80 MWs, and Congress has tasked the Commission with
defining what constitutes facilities being at the same site for
purposes of PURPA. We find that providing set geographic distances will
limit unnecessary disputes over whether facilities are at the same
site, and therefore must choose reasonable distances at which small
power production facilities will be considered irrebuttably at the same
site or irrebuttably at separate sites. There are some affiliated small
power production facilities using the same energy resource that are so
close together that it is reasonable to treat them as irrebuttably at
the same site. The Commission finds that one mile or less is a
reasonable distance to treat such facilities as irrebuttably at the
same site. Likewise, there are some small power production facilities
that are affiliated and may use the same energy resource but that are
sufficiently far apart that it is reasonable to treat them as
irrebuttably at separate sites. The Commission finds that 10 miles or
more is a reasonable distance to treat such facilities as irrebuttably
at separate sites. For affiliated small power production facilities
using the same resource that are more than one mile but less than 10
miles apart, the Commission finds that the distinction between same
site or separate site is not as clear, and therefore finds that it is
reasonable to treat them as rebuttably at separate sites, and to allow
interested parties to provide evidence to attempt to rebut that
presumption. The Commission finds that establishing these reasonable
distances, and particularly establishing the ability to rebut the
presumption of separate sites for affiliated small power production
facilities more than one mile but less than 10 miles apart, better
allows the Commission to address the evolving shape and configuration
of resources, such as modular solar or wind power plants, that are
being developed as QFs, and provides for improved administration of
PURPA. The Commission therefore finds that the one-mile and 10-mile
limits are reasonable inflection points for differentiating between the
same site and separate sites.
---------------------------------------------------------------------------
\768\ See Windfarms, 13 FERC at 61,032.
---------------------------------------------------------------------------
492. The Commission understands that there may be many reasons that
guide developers' decisions on where to site facilities, and for siting
them near to (or far from) each other. The Commission reiterates that
for affiliated small power production QFs that are more than one and
less than 10 miles apart, there is still a presumption that they are at
separate sites, though the Commission today makes that presumption a
rebuttable presumption.\769\ We also adopt today the proposal to allow
an entity seeking QF status to provide further information in its
certification (both self-certification and application for Commission
certification) or recertification (both self-recertification and
application for Commission recertification) to preemptively defend
against rebuttal by identifying factors that affirmatively show that
its facility is indeed at a separate site from affiliated small power
production QFs more than one but less than 10 miles from it.
Additionally, we note that we are retaining waiver provision in 18 CFR
292.204(a)(3), allowing the Commission to waive the method of
calculation of the size of the facility for good cause.\770\
---------------------------------------------------------------------------
\769\ For hydroelectric generating facilities, the regulations
currently provide that the same energy resources essentially means
``the same impoundment for power generation,'' see 18 CFR
292.204(a)(2)(i), and it is unlikely that hydroelectric generating
facilities located more than a mile apart would rely on the same
impoundment. Should that circumstance arise, though, the applicant
facility could seek waiver, arguing that the facilities should not
be considered to be at the same site. See 18 CFR 292.204(a)(3).
\770\ See 18 CFR 292.204(a)(3).
---------------------------------------------------------------------------
493. Borrego Solar raises the concern that unaffiliated developers
may site their projects within a few miles of each other, and later
sell those projects to a single entity much later in the process,
inadvertently violating the Commission's rules. The Commission finds
that it is reasonable to expect the single purchasing entity in the
example to be on notice about the size and locations of its QF
acquisitions and the requirements of both PURPA and the Commission's
regulations, just as it would need to consider other regulatory
requirements associated with its acquisition. Moreover, ownership by a
single entity of multiple small power production QFs in close proximity
to each other that together exceed a power production capacity of 80
MW, and whether this improperly circumvents the Commission's
regulations, is precisely what the new rebuttable presumption is
seeking to address.
494. Regarding Industrial Energy Consumers' request that the
Commission's changes be clarified to exclude ``self-supply'' QFs, the
Commission declines to do so. PURPA limits the power production
capacity of a small power production QF, together with any other
facilities located at the same site (as determined by the Commission),
to 80 MW.\771\ The Commission finds that Industrial Energy Consumer's
argument that ``self-supply'' QFs are built primarily to support
manufacturing and industrial processes does not negate the fact that
the ``self-supply'' QFs in question are small power production
facilities limited to 80 MW. Similarly, its argument also does not
justify different application of the same site determination. The
Commission will therefore apply the same site determinations to all
small power production QFs. The Commission notes that, as with other
small power production QFs, an individual ``self-supply'' QF may assert
relevant factors to show why it should not be considered to be at the
same site as an affiliated small power production QF that is more than
one but less than 10 miles away from it. For example, if a self-supply
facility seeking QF status was within 10 miles of an affiliated
[[Page 54700]]
small power production QF, but the energy from each facility was used
primarily to supply different end users, the self-supply facility
seeking QF status could argue that this fact supports that it is at a
separate site from the affiliated small power production QF, and the
Commission would consider this fact in its evaluation.
---------------------------------------------------------------------------
\771\ 16 U.S.C. 796(17)(A)(ii).
---------------------------------------------------------------------------
495. Regarding Terna Energy's contention that the new rule causes a
100-times increase to the ``exclusion zone'' around a QF's electrical
generating equipment, we believe that the rule providing for a
rebuttable presumption for affiliated small power production QFs
located more than one but less than 10 miles apart, as promulgated
today, is necessary to address allegations of improper circumvention of
the one-mile rule that both previously and in comments have been
presented to the Commission.
496. We reject NorthWestern's request to increase the distance of
the irrebuttable presumption of separate sites to more than 10 miles.
Northwestern argues that 10 miles is not a significant distance
compared to the geographic expansiveness of its system. We believe this
is an irrelevant comparison; what matters is not how large or small the
purchasing electric utility's service territory is or how rural it may
be or how many miles of transmission lines it may have, but the
question presented by the statute, i.e., whether or not the affiliated
small power production QFs are located at the same site. As described
above, we have decided that 10 miles is a reasonable and appropriate
distance at which to apply the irrebuttable presumption of separate
sites, irrespective of how expansive, or diminutive, the purchasing
electric utility's system may be.
f. Factors
i. Comments
497. Several commenters state that they support the factors for
evaluating whether or not facilities are at the same site, which are
described in the NOPR.\772\ SC Solar Alliance and the Southeast Public
Interest Organizations support considering a common point of
interconnection or a single real estate parcel or owner as factors
weighing towards a determination that multiple projects are a single
facility.\773\
---------------------------------------------------------------------------
\772\ APPA Comments at 21-22; Connecticut Authority Comments at
19-20; Idaho Commission Comments at 6-7; NARUC Comments at 5;
Portland General Comments at 15.
\773\ SC Solar Alliance Comments at 17; Southeast Public
Interest Organization Comments at 34.
---------------------------------------------------------------------------
498. Several commenters offer additional factors for
consideration.\774\ North Carolina Commission Staff states that the
Commission should also consider whether the QF is attempting to game
the system by getting rates for which they would otherwise be
ineligible, as well as where the facilities were constructed and when
common ownership commenced.\775\ Northern Laramie Range Alliance
suggests that relevant factors could include, for example, direct or
indirect ownership by the same party or parties, interconnection at a
single substation, simultaneous site acquisition and/or state and local
permitting.\776\ Allco proposes that the criteria to determine if sites
are separate should be whether they share infrastructure, private roads
or interconnection agreements in common.\777\ NRECA proposes that the
types of evidence could include evidence of contemporaneous
construction, shared interconnection, common communication and control,
use of the same step-up transformer, and common permitting and land
leasing.\778\ The Idaho Commission proposes that relevant factors
include whether they share an interconnection agreement, obtained
local, state or federal permits under the same application or as the
same entity, and if they have a revenue sharing agreement.\779\
---------------------------------------------------------------------------
\774\ Allco Comments at 16; Idaho Commission Comments at 6-7;
North Carolina Commission Staff Comments at 6; Northern Laramie
Range Alliance Comments at 3; NRECA Comments at 15-16.
\775\ North Carolina Commission Staff Comments at 6.
\776\ Northern Laramie Range Alliance Comments at 3.
\777\ Allco Comments at 16.
\778\ NRECA Comments at 15-16.
\779\ Idaho Commission Comments at 6-7.
---------------------------------------------------------------------------
Portland General suggests that the Commission include past
ownership of projects as a factor.\780\
---------------------------------------------------------------------------
\780\ Portland General Comments at 15.
---------------------------------------------------------------------------
499. Regarding the relative weight of the factors, the Southeast
Public Interest Organizations would like the Commission to identify
which factors would be definitive in a QF being able to proactively
demonstrate that their site is separate.\781\ Both Basin and EEI would
like the Commission to clarify that the list of factors to be
considered is not exhaustive or weighted.\782\ NorthWestern contends
that the Commission should specify that a showing of any one factor is
sufficient to rebut the presumption. NorthWestern argues that the
Commission should have the flexibility to deal with this issue on a
case-by-case basis and expand or modify the list of factors where
appropriate.\783\
---------------------------------------------------------------------------
\781\ Southeast Public Interest Organization Comments at 34.
\782\ Basin Comments at 12; EEI Comments at 45.
\783\ NorthWestern Comments at 11.
---------------------------------------------------------------------------
500. NorthWestern states that it has concerns about the
Commission's reliance on 18 CFR 35.36(a)(9), because, according to
NorthWestern, developers carefully structure the ownership of their
companies to ensure that they are not, technically, legal affiliates
when, in fact, considering the totality of the circumstances, they are
affiliates. For these reasons, NorthWestern strongly urges the
Commission to consider the physical characteristic factors identified
for determining the distance between facilities in order to also
determine if facilities are owned by affiliates.\784\ NorthWestern
states that, for example, if one facility only owns five percent voting
interest in another facility, but the two facilities have one
interconnection request and use the same collector system, the
Commission should be able to find that there are sufficient facts so
that they are treated as affiliates for purposes of the one-mile
rule.\785\
---------------------------------------------------------------------------
\784\ Id. at 12.
\785\ Id.
---------------------------------------------------------------------------
501. Several commenters opposed the Commission's proposed
factors.\786\ SC Solar Alliance states that the range of factors
included under the categories of ``ownership/other characteristics''
and ``physical characteristics'' is overly broad and could be subject
to inconsistent or problematic interpretation. For example, SC Solar
Alliance states that the term ``infrastructure'' is undefined and
ambiguous, and ``control facilities,'' ``access and easements,''
``collector systems or facilities,'' and ``property leases'' are all
vague and imprecise.\787\ SC Solar Alliance agrees with Solar Energy
Industries' emphasis that under no scenario should common financing be
relevant, as unquestionably distinct facilities are frequently financed
as part of a bundled portfolio.\788\
---------------------------------------------------------------------------
\786\ Ares Comments at 5-7; Borrego Solar Comments at 3-4;
NIPPC, CREA, REC, and OSEIA Comments at 73; Solar Energy Industries
Comments at 62; SC Solar Alliance Comments at 16-18; Southeast
Public Interest Organizations Comments at 34.
\787\ SC Solar Alliance Comments at 17.
\788\ Id. at 16 (citing Solar Energy Industries Supplemental
Comments, Docket No. AD16-16, at 55-56 (August 28, 2019)).
---------------------------------------------------------------------------
502. NIPPC, CREA, REC, and OSEIA strongly oppose use of common
interconnection facilities as a factor because separately owned
facilities are likely to share interconnection facilities to reduce
costs and build off of existing infrastructure. NIPPC, CREA, REC, and
OSEIA state that, given that there are only a limited number of
qualified
[[Page 54701]]
maintenance providers and other service contractors, the fact that two
facilities use the same contractors should not be relevant to common
ownership and control of two facilities. NIPPC, CREA, REC, and OSEIA
state that the fact that two facilities are constructed within 12
months of each other could merely be evidence that the market
conditions at the time favored construction of the facilities, not that
the facilities are intended to be one facility.\789\
---------------------------------------------------------------------------
\789\ NIPPC, CREA, REC, and OSEIA Comments at 73-74.
---------------------------------------------------------------------------
503. SC Solar Alliance states that the extensive list of
``ownership/other characteristics'' as written is highly problematic.
Control and maintenance, particularly in North and South Carolina where
there are a substantial number of distributed solar facilities, is
often contracted for by a limited number of solar maintenance
companies. Allowing the existence of a common maintenance company to in
any way dictate QF status is entirely unreasonable and bears no
relationship to the question at hand.\790\ Similarly, other factors
included in the NOPR, including the sale of electricity to a common
utility, a common financing lender, the use of a mutual contractor for
project construction, the timing of contract execution, and the timing
of facilities being placed into service do not provide relevant
evidence as to common ownership requiring facilities to be considered a
single QF. Applying these factors would create an unnecessary and undue
burden on QFs, particularly smaller distribution-connected QFs that
have been constructed relatively nearby and which often rely on a
limited number of local contractors and partners to complete this
necessary work.\791\
---------------------------------------------------------------------------
\790\ SC Solar Alliance Comments at 17-18.
\791\ Id.
---------------------------------------------------------------------------
504. The Southeast Public Interest Organizations are concerned that
the use of common contractors, financing entity, maintenance companies,
or sales to the same entity and such could be used against QFs that are
built in the same area but are otherwise separate sites.\792\
---------------------------------------------------------------------------
\792\ Southeast Public Interest Organizations Comments at 34.
---------------------------------------------------------------------------
505. SC Solar Alliance states that the Commission's statement that
``no single factor would be dispositive'' is troubling, and that it is
inconceivable that QF ownership would not be dispositive in any such
rebuttable presumption. SC Solar Alliance states that it would be
wholly unjust and unreasonable to consider a solar facility owned by
one solar developer to be considered part of a solar facility owned by
a distinct and unaffiliated solar developer. SC Solar Alliance states
that any rebuttable presumption should include ``separate ownership''
as a dispositive indication of separate facilities.\793\
---------------------------------------------------------------------------
\793\ SC Solar Alliance Comments at 17.
---------------------------------------------------------------------------
506. North Carolina DOJ states that the element of common control
is a challenging question because of the limited number of companies
available to operate renewable energy facilities. North Carolina DOJ
asserts that a handful of firms are responsible for the operation and
maintenance work for close to half of the country's solar energy
production facilities.\794\
---------------------------------------------------------------------------
\794\ North Carolina DOJ Comments at 8.
---------------------------------------------------------------------------
507. NIPPC, CREA, REC, and OSEIA state that the Commission should
include substantially more specific parameters about what evidence a
project would need to submit to demonstrate single-project status and
should make clear that this test has no applicability unless generators
within one to 10 miles are owned by the same company or affiliates of
the same company. NIPPC, CREA, REC, and OSEIA assert that ``the
decisive factors are the `stream of benefits' from the project and
control of the venture,'' which the Commission defined ``to include
entitlement to profits, losses, and surplus after return of initial
capital contribution.'' \795\ These criteria could be used to
objectively evaluate whether two QFs within 10 miles are commonly owned
or controlled, as opposed to also putting two separately owned and
controlled facilities at risk of violating the rule based solely on
physical characteristics.\796\
---------------------------------------------------------------------------
\795\ NIPPC, CREA, REC, and OSEIA Comments at 73 (citing CMS
Midland, Inc., 50 FERC ] 61,098, at 61,278-279 (1990), aff'd Mich.
Municipal Coop. Group v. FERC, 990 F.2d 1377 (D.C. Cir. 1993)).
\796\ Id.
---------------------------------------------------------------------------
ii. Commission Determination
508. We adopt the physical and ownership factors proposed in the
NOPR, including as noted above the ability of a QF to preemptively
identify the factors in its filing in anticipation of protests to its
filing. As explained above in section IV.D.1.d we are modifying the
NOPR proposal to change terminology relating to the determination of
whether facilities are separate facilities to focus not on whether they
are separate facilities, but rather to mirror the statutory language
and thus focus on whether they are at ``the same site.'' Accordingly,
we adopt these factors as relevant indicia of whether affiliated small
power production facilities are ``at the same site.'' In addition, we
modify the NOPR proposal to identify the following additional physical
factors as indicia that small power production facilities should be
considered to be located at the same site: (1) Evidence of shared
control systems; (2) common permitting and land leasing; and (3) shared
step-up transformers.
509. Specifically, we adopt the factors listed below as examples of
the factors the Commission may consider in deciding whether small power
production facilities that are owned by the same person(s) or its
affiliates are located ``at the same site'': (1) Physical
characteristics, including such common characteristics as:
Infrastructure, property ownership, property leases, control
facilities, access and easements, interconnection agreements,
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, connections to the electrical grid, evidence of shared
control systems, common permitting and land leasing, and shared step-up
transformers; 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),\797\
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 small
power production qualifying facility in the same location, placed into
service within 12 months of an affiliated small power production QF
project's commercial operation date as specified in the power sales
agreement, or sharing engineering or procurement contracts.
---------------------------------------------------------------------------
\797\ Definitionally, if the facilities are not owned by the
same person(s) or its affiliates, then the issue of compliance with
the one-mile rule, even as revised in this final rule, becomes
irrelevant. See 18 CFR 292.204(a)(1). That is, two facilities owned
by two different persons are definitionally not located at the same
site.
---------------------------------------------------------------------------
510. We adopt the NOPR proposal to allow a small power production
facility seeking QF status to provide further information in its
certification (both self-certification and application for Commission
certification) or recertification (both self-recertification and
application for Commission recertification) to preemptively defend
against rebuttal, by identifying factors that affirmatively show that
its facility is indeed at a separate site from
[[Page 54702]]
affiliated small power production QFs more than one but less than 10
miles away from it. Any party challenging the QF certification (both
self-certification and application for Commission certification) or
recertification (both self-recertification and application for
Commission recertification) that makes substantive changes to the
existing certification would, in its protest, be allowed to
correspondingly identify factors to show that the small power
production facility seeking QF status and affiliated small power
production QFs more than one but less than 10 from that facility are
actually at the same site.
511. We reiterate that, as a general matter, no one factor is
dispositive.\798\ Rather, we will conduct a case-by-case analysis,
weighing the evidence for and against, and the more compelling the
showing that affiliated small power production QFs should be considered
to be at the same site as the small power production facility seeking
QF status in a specific case, the more likely the Commission will be to
find that the facilities involved in that case are indeed located ``at
the same site.''
---------------------------------------------------------------------------
\798\ But see supra note 797.
---------------------------------------------------------------------------
g. Exemptions
i. Comments
512. Ares notes that small power producers have certain exemptions
from utility regulation, including exemptions from FPA sections 203 and
204 if under 30 MW and exemptions from FPA sections 205 and 206 if
under 20 MW (or 30 MW in special cases), as well as exemptions from
some state utility laws and PUHCA if under 30 MW.\799\ Ares is
concerned that the rebuttable presumption and the factors will make
many small power QFs ineligible for these exemptions.\800\ Ares argues
that the aggregation of small power QFs may result in many required
applications for market-based rate authority for sales that are minor.
Ares argues that the Commission has no basis for, did not consider, and
has sought no comments on the removal of regulatory obligations when
small power QFs are aggregated under the new ten-mile proposal.\801\
---------------------------------------------------------------------------
\799\ Ares Comments at 4-5.
\800\ Id. at 5-6.
\801\ Id. at 11-12.
---------------------------------------------------------------------------
513. Solar Energy Industries note that many facilities could lose
their FPA and PUHCA exemptions if there are multiple facilities within
10 miles, which is particularly harmful to QFs that are not selling to
their host utility. Solar Energy Industries state that PURPA section
210(e)(1) instructs that the Commission shall exempt QFs from
regulation if such exemption ``is necessary to encourage cogeneration
and small power production.'' \802\
---------------------------------------------------------------------------
\802\ Solar Energy Industries Comments at 55.
---------------------------------------------------------------------------
ii. Commission Determination
514. The Commission's current one-mile rule is a rule used to
measure, ultimately, whether or not small power production facilities
are within PURPA's limit on small power production QFs of 80 MW, and
thus whether such facilities are QFs, and the Commission has
consistently applied the one-mile rule generally to the regulations
issued pursuant to PURPA.\803\ There is no persuasive reason it should
not be equally applied in the context of the regulations implementing
section 210(e) of PURPA. That being said, we are not removing or
amending the exemptions provided by the regulations implementing PURPA
section 210(e). If a QF qualifies for exemptions pursuant to PURPA
section 210(e) and the Commission's implementing regulations,\804\ then
that QF is entitled to those exemptions. But, if a small power
production facility does not meet the 80 MW limit for whatever reason,
including because an affiliated small power production QF is located at
the same site, then it does not qualify for such exemption because it
would not be a QF.\805\ There is nothing inappropriate about this
consequence; a facility that is not a QF is not entitled to the
exemptions available to QFs. We further note that there will now be a
rebuttable presumption that affiliated small power production QFs
located more than one but less than 10 miles apart are indeed located
at separate sites. That is no different than the one-mile rule as it
has long existed. What is different is that, with this final rule, the
presumption will be rebuttable while before it was irrebuttable; the
presumption that the facilities are at separate sites, though, remains
unchanged. Only if a party rebuts that presumption and shows that the
small power production facility seeking QF status and affiliated small
power production QFs should be viewed as located at the same site will
the capacity of such facilities be counted together. In that event, if
the small power production facility seeking QF status and affiliated
small power production QFs located at the same site have a combined
power production capacity that exceeds 80 MW, the entity seeking QF
status would not qualify as a QF and would properly not be entitled to
the exemptions that are available to QFs.
---------------------------------------------------------------------------
\803\ SunE B9 Holdings LLC, 157 FERC ] 61,044, at P 16 & n.24
(2016) (citing Windfarms, 13 FERC ] 61,017 at 61,031).
\804\ 18 CFR 292.601, 292.602.
\805\ See 16 U.S.C. 796(17)(A)(ii).
---------------------------------------------------------------------------
2. Electrical Generating Equipment
a. NOPR Proposal
515. The Commission proposed 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 expected 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. The
Commission sought comments on this approach, and on what equipment--if
not individual wind turbines and solar panels--should be considered
``electrical generating equipment'' for wind and solar plants.
516. The Commission also proposed specifying how to measure the
distance between facilities that have multiple, separate sets of
``electrical generating equipment'' such as wind farms and solar
facilities. The Commission proposed measuring the distance between the
nearest ``electrical generating equipment'' of any two facilities such
that, for the facilities to be presumed irrebuttably separate, all such
equipment of one QF must be at least 10 miles away from all such
equipment of another QF. The Commission believed 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.
517. The Commission sought comment on this approach, and whether
alternative approaches would be more appropriate. For example, some
parties had 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.'' \806\ The Commission was concerned
these approaches could be easily gamed, but sought comment on whether
they may be constructed in a way that would prevent gaming, and whether
such
[[Page 54703]]
formulations would be preferable to the proposed approach.
---------------------------------------------------------------------------
\806\ See Beaver Creek Wind II, LLC, 160 FERC ] 61,052, at P 9
(2017).
---------------------------------------------------------------------------
b. Comments
518. Many commenters support the definition of ``electrical
generating equipment'' proposed in the NOPR.\807\ However, ELCON
objects to both the proposed definition of ``electric generating
equipment'' and the approach to measuring distance.\808\
---------------------------------------------------------------------------
\807\ Alliant Energy Comments at 19; APPA Comments at 23; Basin
Comments at 11; Connecticut Authority Comments at 19-20; EEI
Comments at 49; Idaho Commission Comments at 6; Kentucky Commission
Comments at 7; NRECA Comments at 17; Portland General Comments at
16-17; Southeast Public Interest Organizations Comments at 37-38.
\808\ ELCON Comments at 36.
---------------------------------------------------------------------------
519. Many commenters support the method for measuring distance
between sites proposed in the NOPR, which would require measuring the
distance between the nearest ``electrical generating equipment'' of any
two affiliated facilities.\809\ Several commenters note their
opposition to measuring the distance between sites using the geographic
center of the plant or a weighted average of the locations of
individual pieces of ``electrical generating equipment,'' both methods
the Commission sought comment on in the NOPR.\810\ The Southeast Public
Interest Organizations request clarification of whether to measure from
the edge of a solar panel or the center of a solar array.\811\
---------------------------------------------------------------------------
\809\ Alliant Energy Comments at 19; APPA Comments at 23; Basin
Comments at 11; Connecticut Authority Comments at 19-20; EEI
Comments at 49; Kentucky Commission Comments at 7; NARUC Comments at
4-5; Portland General Comments at 16-17; Southeast Public Interest
Organizations Comments at 37-38.
\810\ Connecticut Authority Comments at 21; Kentucky Commission
Comments at 7; NorthWestern Comments at 12-13; NRECA Comments at 18;
Portland General Comments at 18.
\811\ Southeast Public Interest Organizations Comments at 38.
---------------------------------------------------------------------------
520. Several commenters request that the Commission discuss how
energy storage (sometimes referred to as battery storage) would be
considered in relation to the proposed definition of electrical
generating equipment.\812\ The California Commission requests that a
battery storage facility be excluded from consideration as electrical
generating equipment provided the storage is charged solely by the
small power production facility, and that energy stored by the storage
facility be considered to be of the same energy source of that energy
before it was stored.\813\ The California Commission also requests that
the Commission affirm that storage does not permit a facility to exceed
the maximum size criteria of a small power production facility.\814\
EEI requests that the Form 556 collect data on storage resources as
well as electrical generating equipment for purposes of measuring
distance to an affiliated small power production QF.\815\
---------------------------------------------------------------------------
\812\ Alliant Energy Comments at 19; EEI Comments at 46-47;
Energy Storage Comments at 3; NorthWestern Comments at 13.
\813\ California Commission at 16-17.
\814\ Id. at 15.
\815\ EEI at 51-52.
---------------------------------------------------------------------------
c. Commission Determination
521. We adopt the NOPR proposal that ``electrical generating
equipment'' refers to all boilers, heat recovery steam generators,
prime movers (any mechanical equipment driving an electric generator),
electrical generators, photovoltaic solar panels, 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. Each wind turbine at a wind facility 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.
522. We require the distance between the facility seeking small
power production QF status and any affiliated small power production
QFs using the same energy resource to be measured by the distance
between the nearest ``electrical generating equipment'' of each such
facility, such that, for the entity seeking QF status to be presumed
irrebuttably at a separate site from any affiliated small power
production QF, all such equipment of the affiliated small power
production QF must be at least 10 miles away from all such equipment of
the entity seeking small power production QF status. The Commission
finds that this is the most appropriate way to measure the distance
between affiliated sets of ``electrical generating equipment'' at small
power production facilities because this reflects the distance between
the components directly tied to producing electric energy.
523. The point used in the distance calculation will always be from
the edge of the electrical generating equipment closest to the
affiliated small power production QF's nearest electrical generating
equipment. Thus, we clarify that for a solar facility, the measurement
should be from the edge of the small power production facility seeking
QF status' solar panel or inverter that is closest to the edge of the
nearest ``electrical generating equipment'' of that affiliated small
power production QF. For a wind facility, the measurement should
similarly be from the edge of the small power production facility
seeking QF status' wind turbine or inverter closest to the edge of the
nearest ``electrical generating equipment'' of the affiliated small
power production QF. For a wind facility, we clarify that the relevant
point for measuring distance of an individual wind turbine is the tower
(not the projection of the blade's wingspans onto the ground). We also
clarify that only horizontal distances are taken into consideration for
purposes of this rule (such that elevation changes have no effect on
facility distance).
524. We find that the role of battery storage in QFs, including
with regard to the distance between QFs, is beyond the scope in this
proceeding.
E. QF Certification Process
1. NOPR Proposal
525. In the NOPR, the Commission proposed to revise 18 CFR
292.207(a) to allow interested persons to intervene in, 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 with which it is
interconnected and those to which it will be selling) as well as the
relevant state regulatory authorities, the Commission proposed to 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).\816\
---------------------------------------------------------------------------
\816\ 18 CFR 292.207(c)(1).
---------------------------------------------------------------------------
526. 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. 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-
[[Page 54704]]
recertification to demonstrate that the claims raised in the protest
are incorrect and that certification is, in fact, warranted.
527. QF self-certification is effective upon filing and would
remain effective if a protest is filed, until such time as the
Commission rules that certification is revoked. The Commission proposed
that it would issue an order within 90 days of the date the protest is
filed. The Commission also reserved the right to request more
information from the protester, the entity seeking QF status, or
both.\817\ If 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.
---------------------------------------------------------------------------
\817\ Such information requests could be issued by the
Commission or by staff under any applicable delegated authority. For
example, under 18 CFR 375.307(b)(3)(ii), the Director of the Office
of Energy Market Regulation is authorized to ``[i]ssue and sign
requests for additional information regarding applications, filings,
reports and data processed by the Office of Energy Market
Regulation.''
---------------------------------------------------------------------------
528. There may be instances, however, when the Commission may need
additional time to review the record in light of the nature of the
protests. In those cases, the Commission proposed 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 within one additional 60-day period. The Commission proposed to
delegate to the Commission's Secretary, or the Secretary's designee,
the authority to toll the 90-day period for this purpose.
529. The Commission believed these procedures would allow for
timely but thorough review of protested self-certifications and self-
recertifications. The Commission sought comment on whether these
procedures impose an undue burden on the QF even though the QF remains
certified pending the review.
2. Comments
530. Many commenters raise the issue of granting legacy treatment,
colloquially known as ``grandfathering,'' to existing QF certifications
and their future recertifications.\818\ Most of these comments support
granting legacy treatment to current QFs and their future
recertifications.\819\ Several commenters note that the application of
the rule to existing or recertifying QFs will create uncertainty and
cause disruptions of the sale of these QFs.\820\
---------------------------------------------------------------------------
\818\ Ares Comments at 12; Basin Comments at 11; BluEarth
Comments at 2; DC Commission at 9; New England Small Hydro Comments
at 17; Industrial Energy Consumers Comments at 17; NIPPC, CREA, REC,
and OSEIA Comments at 74; Solar Energy Industries Comments at 61-63;
SC Solar Alliance Comments at 18; Southeast Public Interest
Organizations Comments at 29-31; Terna Energy Comments at 16-18.
\819\ Ares Comments at 12; BluEarth Comments at 2; New England
Small Hydro Comments at 17; Industrial Energy Consumers Comments at
17; NIPPC, CREA, REC, and OSEIA Comments at 74; Solar Energy
Industries Comments at 61-63; SC Solar Alliance Comments at 18;
Southeast Public Interest Organizations Comments at 29-31; Terna
Energy Comments at 16-18.
\820\ New England Small Hydro Comments at 17; NIPPC, CREA, REC,
and OSEIA Comments at 74; Terna Energy Comments at 16-18.
---------------------------------------------------------------------------
531. New England Small Hydro warns that applying the proposed rule
to existing QFs could trigger financing defaults if those QFs lose
their status.\821\ The Southeast Public Interest Organizations state
that the proposed rebuttable presumption has implications for existing
solar QFs in the Southeast, noting that QFs would be required to seek
recertification as their existing PPAs expire, adding a significant
burden.\822\ The Southeast Public Interest Organizations provide maps
showing the ten-mile radius of utility-scale projects could lead to
many overlapping affiliated territories under the new rules.\823\ SC
Solar Alliance also notes the large number of small solar QFs
overlapping within a ten-mile radius across North Carolina and South
Carolina and finds that the application of the more-than-one-but-less-
than-10-miles rebuttable presumption to recertifications will be
burdensome and unwieldy.\824\ NIPPC, CREA, REC, and OSEIA warn that the
application of the new rule to existing QFs will effectively bar the
transfer or sale (or potentially any number of less significant
changes) of existing assets that were lawfully qualified under the one-
mile rule but would pass the 80 MW aggregate threshold under the new
rule. NIPPC, CREA, REC, and OSEIA find this to be a violation of the
existing QFs contractual and constitutional rights.\825\
---------------------------------------------------------------------------
\821\ New England Small Hydro Comments at 17.
\822\ Southeast Public Interest Organizations Comments at 29.
\823\ Id. at 30-31.
\824\ SC Solar Alliance Comments at 18.
\825\ NIPPC, CREA, REC, and OSEIA Comments at 75.
---------------------------------------------------------------------------
532. Terna Energy states that granting legacy treatment to existing
QFs and their recertifications is necessary to protect investment
decisions and contracts made under the long-standing one-mile
rule.\826\ Terna Energy contends that, without clarification on the
legacy treatment of recertifications, QFs could lose their status even
for non-substantive revisions to their FERC Form No. 556s such as
contact information, street address, ownership or operation.\827\ Terna
Energy warns that absent the clarification of legacy treatment for
existing QF recertifications, QFs might go to extremes to avoid
updating their FERC Form No. 556s with information changes.\828\
---------------------------------------------------------------------------
\826\ Terna Energy Comments at 1-2.
\827\ Id. at 2.
\828\ Id. at 7.
---------------------------------------------------------------------------
533. Solar Energy Industries state that retroactively applying a
more-than-one-but-less-than-10-miles rebuttable presumption to physical
facilities that were developed based on the original one-mile rule will
inject instability, will erode trust from the investment community, and
will discourage the development of QFs as well as investment in the
industry in general.\829\ Ares notes that not granting legacy treatment
to existing QFs is inconsistent with past Commission actions on PURPA,
such as the granting of legacy treatment to existing QF contracts in
Order No. 671 or other QF related proceedings.\830\
---------------------------------------------------------------------------
\829\ Solar Energy Industries Comments at 62.
\830\ Ares Comments at 12.
---------------------------------------------------------------------------
534. New England Small Hydro supports granting legacy treatment to
existing QFs to avoid upsetting the settled expectations of existing
generation.\831\ New England Small Hydro gives the example of three
hypothetical projects, each located nine miles apart that, when
capacities are totaled, exceed 80 MW. If there is an ownership change
that triggers the need for a recertification but the entities remain
affiliates, under the Commission's proposed rule, all three projects
would lose QF status. According to New England Small Hydro, this could
trigger defaults under financing documents and the utility might be
able to terminate the power contract, because many PPAs for QFs require
the project to remain a QF for the term of the PPA. New England Small
Hydro states that, as a result, a minor ownership change could have
cascading negative effects to QFs.\832\
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\831\ New England Small Hydro Comments at 17.
\832\ Id.
---------------------------------------------------------------------------
535. Terna Energy requests that existing QFs be granted legacy
treatment as long as they do not make changes to electrical generating
equipment of the facility, because that is the equipment that
determines compliance with the one-mile rule. Terna Energy argues that
otherwise an existing QF could be subject to challenge anytime it makes
a non-substantive revision to its FERC Form No. 556, including a change
to contact information, street address, ownership, or operator,
effectively
[[Page 54705]]
eliminating legacy treatment.\833\ Terna Energy states that granting
legacy treatment is necessary to protect the sanctity of investments
and contracts made in reliance upon the Commission's current PURPA
regulations and the one-mile rule.\834\ Terna Energy submits revised
language for 18 CFR 292.204(a)(2) and (3) to clarify that existing QF
recertifications, unless they change the electrical generating
equipment, should not be subject to the new rules.\835\
---------------------------------------------------------------------------
\833\ Terna Energy Comments at 2.
\834\ Id. at 1-2.
\835\ Id. at 8-9.
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536. Basin, on the other hand, asks the Commission to be clear that
recertifications filed by QFs will trigger application of the proposed
rule.\836\ Basin also recommends the Commission allow petitions seeking
de-certification of QFs that have previously filed self-certifications
because some QFs self-certify at an early stage of project development
and ultimately never proceed to development.\837\
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\836\ Basin Comments at 11.
\837\ Id.
---------------------------------------------------------------------------
537. The DC Commission would like the Commission to clarify whether
the changes to the one-mile rule will apply to QFs under construction
when the rule goes into effect.\838\ The DC Commission would like the
Commission to leave the issue of legacy treatment of existing QFs up to
the states.\839\
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\838\ DC Commission Comments at 9.
\839\ Id.
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538. Several commenters oppose the NOPR proposal 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 pay the associated filing fee.\840\ Several commenters argue
that this proposal will lead to a flood of challenges that will
discourage the growth of QFs.\841\ Several commenters state that there
will be substantial costs associated with this proposal that will fall
on ratepayers and QFs.\842\ Several commenters state that the proposed
changes will lead to increased administrative burden and expense \843\
or litigation risk.\844\ Several commenters state that the proposed
changes will lead to uncertainty \845\ and deter development.\846\
---------------------------------------------------------------------------
\840\ Allco Comments at 21; BluEarth Comments at 3; CARE
Comments at 7; Con Edison Comments at 5; Distributed Sun Comments at
3; ENGIE Comments at 4; Public Interest Organizations Comments at 9,
97-98; Western Resource Councils Comments at 144; Solar Energy
Industries Comments at 57-59.
\841\ Allco Comments at 21; BluEarth Comments at 3; Distributed
Sun Comments at 3; Public Interest Organizations Comments at 97;
Western Resource Councils Comments at 144.
\842\ Con Edison Comments at 5; ENGIE Comments at 4; Public
Interest Organizations Comments at 97; Solar Energy Industries
Comments at 58.
\843\ Ares Comments at 6; Borrego Solar Comments at 4; Con
Edison Comments at 5; Public Interest Organizations Comments at 97-
98; Solar Energy Industries Comments at 51-52, 54, 57-58; SC Solar
Alliance Comments at 15-18; Southeast Public Interest Organizations
Comments at 29, 35; sPower Comments at 14.
\844\ Con Edison Comments at 5; Distributed Sun Comments at 3;
ELCON Comments at 19-20; NIPPC, CREA, REC, and OSEIA Comments at 71-
72; Public Interest Organizations Comments at 97-98; Solar Energy
Industries Comments at 58-60; SC Solar Alliance Comments at 16, 18;
Southeast Public Interest Organizations Comments at 29,35; sPower
Comments at 14.
\845\ Ares Comments at 9; Distributed Sun Comments at 3; ELCON
Comments at 19-20, 38; NIPPC, CREA, REC, and OSEIA Comments at 69-
72; Public Interest Organizations Comments at 97-98; Solar Energy
Industries Comments at 58-60, 62-63; SC Solar Alliance Comments at
16, 18; Southeast Public Interest Organizations Comments at 29, 35,
38, 93, 97-98; sPower Comments at 14.
\846\ Allco Comments at 16; Borrego Solar Comments at 4-5;
Biological Diversity Comments at 9; Con Edison Comments at 4-5;
Distributed Sun Comments at 3; NIPPC, CREA, REC, and OSEIA Comments
at 72-73; North Carolina DOJ Comments at 8; Public Interest
Organizations Comments at 93, 99; Solar Energy Industries Comments
at 51-52, 59-63; SC Solar Alliance Comments at 2, 18; Southeast
Public Interest Organizations Comments at 31-36, 38, 93.
---------------------------------------------------------------------------
539. Solar Energy Industries state that the proposed changes to the
one-mile rule will substantially increase the regulatory burden on QFs
and the self-certification process will no longer be quick.\847\ Solar
Energy Industries is concerned that QFs may need to defend numerous
self-certifications over a facility's lifetime, and assert that QFs
could be forced to recertify any time the information represented in
the Form No. 556 changes, including ownership changes to affiliated
facilities located within 10 miles.\848\ Solar Energy Industries state
that the burden will be increased exponentially if the one-mile rule is
expanded in a ten-mile rule.\849\ Solar Energy Industries state that
the NOPR's estimate of an additional eight hours and $632 per docket
for each QF self-certification or re-certification is a substantial
underestimation.\850\ Solar Energy Industries estimate that it would
require an additional approximately 90 to 120 hours per year to comply
with the new requirements. Solar Energy Industries state that a QF
could be forced to recertify any time the information represented
changes, including ownership changes to affiliated facilities located
within 10 miles. Solar Energy Industries note that a QF may have to
engage in multiple defenses of its status, each time needing to engage
legal counsel and devote internal company resources to preserve the
status of its already-installed plant.\851\ Solar Energy Industries
assert that the flood of self-certification filings and updates would
be a substantial burden on Commission staff and provide little value to
the Commission or the public.\852\ Solar Energy Industries also state
that, unless and until the Commission makes a determination on the
burden associated with collecting, reporting, and updating the
Connected Entity \853\ information, it would be unjust and unreasonable
for the Commission to impose similar burdens on QF entities through the
FERC Form No. 556.\854\ Solar Energy Industries state that the
increased regulatory burden that will arise for these entities is
similar in scope and the Commission has not provided a rationale for
the increased information collection requirements.\855\
---------------------------------------------------------------------------
\847\ Solar Energy Industries Comments at 52.
\848\ Solar Energy Industries at 57.
\849\ Id. at 53.
\850\ Id. at 52.
\851\ Id. at 58.
\852\ Id. at 53-54.
\853\ Id. at 54 (citing Data Collection for Analytics and
Surveillance and Market-Based Rate Purposes, Order No. 860, 168 FERC
] 61,039, at P 183 (2019)).
\854\ Id. at 54, 57.
\855\ Id. at 54.
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540. Allco describes the Commission's Regulatory Flexibility Act
(RFA) analysis of the proposed rules' effect on small businesses as
improperly limited to proposed paperwork changes, ignoring the impact
on small QFs' abilities to construct facilities.\856\ Allco states that
the Commission did not attempt to minimize the impacts on small
renewable energy producers, consider alternative structures, or
describe these steps or considerations in a mandatory final RFA
analysis.\857\ Allco asserts that the Commission failed to support its
finding that the NOPR's proposed revisions will not significantly
impact a substantial number of small entities (specifically, solar
energy QFs); Allco therefore claims that the Commission violated the
Small Business Regulatory Enforcement Fairness Act.\858\
---------------------------------------------------------------------------
\856\ Allco Comments at 33.
\857\ Id.
\858\ Id.
---------------------------------------------------------------------------
541. Solar Energy Industries state that the NOPR lacks important
details such as whether the Commission's determination is subject to
rehearing, and whether a final decision can be appealed under the FPA
to an appellate court.\859\ Solar Energy Industries state that an
adverse determination by the Commission could impose upwards of $100
million in harm on a QF, and it is unclear whether the QF would have a
path to relief if the Commission erred in its determination. Solar
Energy
[[Page 54706]]
Industries state that the current practice, where the challenger bears
the responsibility of seeking declaratory relief, strikes an
appropriate balance.\860\
---------------------------------------------------------------------------
\859\ Id. at 58.
\860\ Id. at 59.
---------------------------------------------------------------------------
542. Several commenters, on the other hand, support the NOPR
proposal 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.\861\ Several commenters argue that the proposed amendment would
strike the right balance and distribute the burdens of proof
appropriately.\862\ Several commenters also state that this proposal
would increase the efficiency of the process, reduce administrative
costs, and could solve potential certification problems before they
even begin.\863\
---------------------------------------------------------------------------
\861\ Alaska Power Comments at 2; Alliant Energy Comments at 22-
23; APPA Comments at 31-35; Duke Energy Comments at 23-24; Indiana
Municipal Comments at 10; NRECA Comments at 21-22; Portland General
Comments at 21-22; Ohio Commission Energy Advocate Comments at 10;
Chamber of Commerce Comments at 8; We Stand Comments at 3.
\862\ APPA Comments at 31-35; NRECA Comments at 21-22; Ohio
Commission Energy Advocate Comments at 10.
\863\ Indiana Municipal Comments at 10; NRECA Comments at 21-22;
Portland General Comments at 21-22.
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543. Other commenters support the NOPR proposal, but with caveats
or extra requests.\864\ Golden Valley recommends that the 30-day clock
to challenge QF self-certification or self-recertification begins when
the QF serves notice to the interested electric utility, not when the
QF makes its filing with the Commission.\865\ NIPPC, CREA, REC, and
OSEIA state that the Commission should provide a 60-day deadline after
the filings are complete by which time a failure of the Commission to
rule results in the objection being denied by operation of law.\866\
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\864\ DTE Electric Comments at 9-10; Golden Valley Electric
Comments at 1-2, 3-7; Industrial Energy Consumers Comments at 14;
Northern Laramie Range Alliance Comments at 3; NorthWestern Comments
at 17-18; ELCON Comments at 19-20, 37-38.
\865\ Golden Valley Electric Comments at 2.
\866\ NIPPC, CREA, REC, and OSEIA Comments at 74.
---------------------------------------------------------------------------
544. NorthWestern requests the QFs be subject to various discovery
requests when they self-certify or self-recertify.\867\ Two commenters
argue that any challenging party should be required to include an
affidavit from a company official.\868\
---------------------------------------------------------------------------
\867\ NorthWestern Comments at 17-18.
\868\ Industrial Energy Consumers Comments at 14; ELCON Comments
at 20, 38.
---------------------------------------------------------------------------
545. NorthWestern and Northern Laramie Range Alliance request that
QF developers seeking certification with the Commission should be
required to publish notice in local newspapers in the states in which
the development would be located, in order to alert affected parties so
they could intervene in the certification process.\869\ El Paso
Electric is concerned by the proposal to limit the ability to challenge
QF status once it has been certified in a Commission certification
proceeding or in response to a challenge unless the new challenger can
demonstrate a change in the facility circumstances that threaten the
validity of the previous finding. El Paso Electric states that
sometimes QFs fail to provide utilities with their QF application and
so the utility does not know to protest.\870\
---------------------------------------------------------------------------
\869\ NorthWestern Comments at 3; Northern Laramie Range
Alliance Comments at 3.
\870\ El Paso Electric Comments at 5.
---------------------------------------------------------------------------
546. Ares notes that small power production QFs could be aggregated
under the more-than-one-but-less-than-10-miles rebuttable presumption
and not even be aware of the other small power production QFs because
of a lack of information.\871\
---------------------------------------------------------------------------
\871\ Ares Comments at 6.
---------------------------------------------------------------------------
3. Commission Determination
547. We adopt the NOPR proposal to revise 18 CFR 292.207(a) to
allow an interested person or entity to seek to intervene and to file a
protest of a self-certification or self-recertification of a QF, and
not have to file a petition for declaratory order and pay the filing
fee for petitions.\872\ We also adopt the other changes to the QF
certification process proposed in the NOPR, with the additions detailed
below. We find that any increased administrative burden or litigation
risk imposed by the new rule is justified by the need to ensure that
QFs meet the statutory criteria for QF status.
---------------------------------------------------------------------------
\872\ We amend the proposed regulation in the NOPR to move the
sections referring to protests and interventions from 18 CFR 292.204
to 18 CFR 292.207.
---------------------------------------------------------------------------
548. The ability to intervene and to file a protest of a self-
certification or self-recertification of a QF without having to file a
petition for declaratory order and pay the filing fee for petitions is
effective as of the effective date of the final rule. However, we will
grant legacy treatment to existing QFs under certain circumstances, as
we explain below. With the exceptions noted below, protests pursuant to
this final rule will not be allowed to QF certifications and
recertifications (including self-certifications and self-
recertifications) that are submitted before the effective date of the
final rule, although entities may still challenge by filing a petition
for declaratory order and submitting the required fee. Conversely,
protests can be made to QF certifications (both self-certification and
application for Commission certification) or recertifications (both
self-recertification and application for Commission recertification)
that are submitted on or after the effective date of this final rule.
We note here that it is the date of filing for certification or
recertification, and not the date of construction, that determines
whether our new protest rule applies to the certification or
recertification.
549. Many commenters have argued for expansive legacy treatment for
recertification of existing projects. They have noted that QFs need to
recertify when property is transferred, PPAs expire, or even for non-
substantive changes, such as changes in contact information or street
address.\873\ Commenters argue that, if the new protest rules apply to
recertifications, existing QFs could lose their QF status, even if
their configuration or other relevant factors do not materially change,
when they file their recertifications, upsetting the settled
expectations under which the QFs built their facilities.
---------------------------------------------------------------------------
\873\ NIPPC, CREA, REC, and OSEIA Comments at 75; Terna Energy
Comments at 1-2, 7.
---------------------------------------------------------------------------
550. We agree that QF recertifications to implement or address non-
substantive changes should not be subject to our new protest rule; the
settled expectations of the QFs should be respected in such instances.
Accordingly, we find that protests may be filed to an initial
certification (both self-certification and application for Commission
certification) filed on or after the effective date of this final rule,
but only to a recertification (both self-recertification and
application for Commission recertification) that makes substantive
changes to the existing certification and that are filed on or after
the effective date of this final rule. Substantive changes that may be
subject to a protest may include, for example, a change in electrical
generating equipment that increases power production capacity by the
greater of 1 MW or 5 percent of the previously certified capacity of
the QF, or a change in ownership in which an owner increases its equity
interest by at least 10% from the equity interest previously reported.
We find that recertifications (both self-recertifications and
applications for Commission recertifications) making ``administrative
only'' changes should not be subject to
[[Page 54707]]
a protest pursuant to this final rule.\874\ We believe that excepting
from protests QF recertifications making non-substantive changes will
allow QFs to make such changes and recertify without potentially losing
their QF status.
---------------------------------------------------------------------------
\874\ As noted elsewhere in this final rule, our allowing
protests does not eliminate the ability to file a petition for
declaratory order seeking revocation of qualifying status.
---------------------------------------------------------------------------
551. Solar Energy Industries asserts that the certification process
will no longer be quick, and estimates that it would require an
additional approximately 90 to 120 hours per year to comply with these
new requirements. Solar Energy Industries is concerned that QFs may
need to defend numerous self-certifications over a facility's lifetime,
and asserts that QFs could be forced to recertify any time the
information represented in the Form No. 556 changes.\875\
---------------------------------------------------------------------------
\875\ Solar Energy Industries at 57.
---------------------------------------------------------------------------
552. We do not agree with Solar Energy Industries' estimates.
First, we note that 18 CFR 292.207(d) (which we are not altering in
this rule except to renumber as 18 CFR 292.207(f)) already states that
if a QF fails to conform with any material facts or representations
presented in the certification, the QF status of the facility may no
longer be relied upon,\876\ and hence it is long-standing practice that
a QF must recertify when material facts or representations in the Form
No. 556 change.
---------------------------------------------------------------------------
\876\ 18 CFR 292.207(d), which this final rule will renumber to
18 CFR 292.207(f).
---------------------------------------------------------------------------
553. Second, certifications and recertifications are already
subject to protests, albeit in the form of petitions for declaratory
order, and therefore dealing with objections to a certification or
recertification is not new. Although the new procedures may result in
more protests being filed than the number of petitions that have been
filed, we believe that the conditions we impose in this final rule will
limit the number of protests filed. The Commission anticipates that
most, though not all, of the protests filed pursuant to the new 18 CFR
292.207(a) will relate to the new more-than-one-but-less-than-10-miles
rebuttable presumption.\877\ Such protests will necessarily be limited
because not all certifications and recertifications will be subject to
the new more-than-one-but-less-than-10-miles rebuttable presumption.
Only small power production facilities seeking QF status that have an
affiliated small power production QF more than one but less than 10
miles away and that uses the same energy resource are subject to the
rebuttable presumption. Small power production facilities that do not
have multiple small power production facilities or affiliates will not
be affected by the new rebuttable presumption. Nor will cogeneration
QFs be affected by the new rebuttable presumption.\878\ Additionally,
in general as described above, protests may only be made to an initial
certification (both self-certification and application for Commission
certification) filed on or after the effective date of this final rule,
and only to a recertification (self-recertification or application for
Commission recertification) that makes substantive changes to the
existing certification that are filed after the effective date of this
final rule.
---------------------------------------------------------------------------
\877\ While we anticipate that most protests will involve
interested persons or entities attempting to rebut the presumption
of separate sites for affiliated small power production qualifying
facilities that are more than one and less than 10 miles apart, we
note that protesters may also protest any fact or representation in
the Form No. 556, or other aspect of a QF's filing they believe is
inconsistent with PURPA or our PURPA Regulations.
\878\ The 80 MW limit and same site determination only apply to
small power production facilities, not cogeneration facilities. See
16 U.S.C. 796(17)(A).
---------------------------------------------------------------------------
554. Third, we are also instituting time limits on protests that
may be filed under this final rule. We adopt the NOPR proposal that
interested parties will have 30 days from the date of the filing of the
Form No. 556 at the Commission to file a protest (without paying a
fee).\879\ Additionally, a protestor must concurrently serve its
protest on the Form No. 556 applicant pursuant to 18 CFR 385.2010.
---------------------------------------------------------------------------
\879\ We note that section 292.207(c) of the PURPA Regulations
requires the applicant to concurrently with its filing serve a copy
of the filing on each applicable electric utility as well as the
applicable State regulatory authority. We expect an applicant
seeking QF status (or recertifying its status) to timely comply with
that regulation. Therefore, a utility should also receive the filing
at the same time that the filing is made at the Commission.
---------------------------------------------------------------------------
555. Fourth, regarding Solar Energy Industries' concern that a QF
may have to engage in multiple defenses of its status, in addition to
the above limits on protests, once the Commission has affirmatively
certified an applicant's QF status in response to a protest opposing a
self-certification or self-recertification, or in response to an
application for Commission certification or Commission recertification,
any later protest to a recertification (self-recertification or
application for Commission recertification) making substantive changes
to a QF's existing certification, e.g., asserting that the entity
seeking QF status is at the same site as affiliated small power
production QFs more than one but less than 10 miles from it, must
demonstrate changed circumstances from the facts on which the
Commission acted on the certification filing that call into question
the continued validity of the earlier certification.
556. Finally, even if it indeed takes some small power production
facilities an additional 90 to 120 hours (and we think that unlikely),
that is not an unreasonable burden to impose to ensure that a
generating facility that seeks to be a QF is, in fact, entitled to QF
status and complying with PURPA.\880\
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\880\ The regulations adopted in this final rule explicitly make
self-certifications and self-recertifications effective upon filing
and allow them to remain effective even if challenged until such
time as the Commission finds that a facility does not qualify to be
a QF. Additionally, entities seeking QF status can file self-
certifications years in advance of facility operation, such that the
few months contemplated by the new process should not cause delay.
Finally, with regard to the time it may take to fill in the Form No.
556, we note that while an entity seeking QF status may choose to
preemptively defend against claims that it should be considered to
be at the same site as affiliated small power production qualifying
facilities located more than one but less than 10 miles from it,
this is optional, not required.
---------------------------------------------------------------------------
557. Turning to the requirements for a protest, as proposed in the
NOPR, we will require any person or entity filing a protest to specify
facts that make a prima facie demonstration that the facility described
in the certification (both self-certification and application for
Commission certification) or recertification (both self-recertification
or application for Commission recertification) does not satisfy the
requirements for QF status. We will also require any protest to be
adequately supported with any supporting documents, contracts, or
affidavits, as appropriate. Just as public utilities are typically not
subject to discovery with regard to their rate filings under section
205 of the FPA prior to the Commission's instituting trial-type
evidentiary hearings,\881\ we similarly decline to make QFs subject to
discovery requests when they self-certify or self-recertify.
---------------------------------------------------------------------------
\881\ 18 CFR 385.401(a).
---------------------------------------------------------------------------
558. The Commission also orders here that an applicant's response
to a protest will be allowed under 18 CFR 385.213(a)(2). By this final
rule, we are consistent with that regulation, ``otherwise order[ing]''
that such answers may be filed. They will be due no later than 30 days
after the filing of the protest.
559. Rooftop solar developers frequently finance the initial
development of rooftop solar photovoltaic (PV) systems of individual
homeowners, and then retain ownership of such PV systems for extended
periods of time until the ownership is
[[Page 54708]]
eventually transferred to the relevant homeowners. While these rooftop
solar PV systems are owned by the developer, each individual rooftop
solar PV system would be considered affiliated electrical generating
equipment of every other rooftop solar PV system owned by that
developer. When there are multiple co-owned rooftop solar PV systems
within a mile, and thus at the same site, they may exceed 1 MW and
therefore be required to file for certification or recertification
unless they receive a waiver.\882\ Moreover, whenever they add an
additional rooftop solar PV system to their portfolio, or alternatively
transfer the ownership of such a rooftop solar PV system to the
relevant homeowner, their facility could be viewed as no longer
conforming with the material facts in their prior certification or
recertification; thus they would need to recertify.
---------------------------------------------------------------------------
\882\ See Sunrun, Inc., 167 FERC ] 61,059 (2019).
---------------------------------------------------------------------------
560. Due to the unique nature of rooftop solar PV developers, the
Commission finds the recertification requirement for PV developers
could be unduly burdensome. Therefore, to lessen the burden on such
developers when recertifying, we will permit rooftop solar PV
developers an alternative option to file their recertification
applications. That is, rather than be required to file for
recertification each time the rooftop solar developer adds or removes a
rooftop facility, a rooftop solar PV developer may recertify on a
quarterly basis. The filing would be due within 45 days after the end
of the calendar quarter. However, if in any quarter a rooftop solar PV
developer either has no changes or only has changes of power production
capacity of 1 MW or less, then it would not be required to recertify
until it has accumulated changes greater than 1 MW total over the
quarters since its last filing.\883\ Additionally, we note that rooftop
solar PV developers, like all small power production facilities, will
not be subject to protests when they file recertifications that are
``administrative only'' in nature, but would be subject to such
protests when they make substantive changes to the existing
certification as detailed above in this section.
---------------------------------------------------------------------------
\883\ For example, if a rooftop solar QF increases its power
production capacity by 0.9 MW in a quarter, it would not need to
file to recertify for that quarter. However, if in the next quarter
the rooftop solar QF increased its power production capacity by 0.9
MW, it would need to recertify for that quarter because cumulatively
over the quarters since its last filing it has changed its power
production capacity by more than 1 MW (i.e., under this example the
rooftop solar QF changed its power production capacity since its
last recertification filing by 1.8 MW).
---------------------------------------------------------------------------
561. We take this opportunity to clarify that, when the Commission
issues an order revoking QF certification, such order is subject to
rehearing and appeal pursuant to the FPA.\884\ The Commission's
authority to determine whether or not a facility is a qualifying small
power production facility stems from PURPA section 201, which amended
FPA section 3 to add paragraph (17).\885\ Similarly, FPA section 3(18)
grants the Commission authority to determine whether a cogeneration
facility meets the Commission's requirements.\886\ Because the
Commission's authority is grounded in the FPA, the Commission's order
revoking QF certification is subject to rehearing and appeal pursuant
to FPA section 313.\887\
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\884\ Similarly, when the Commission issues an order
affirmatively certifying an applicant's QF status (in response to a
protest opposing a self-certification or self-recertification, or in
response to an application for Commission certification or
recertification), any party to that proceeding aggrieved by the
order, including the protestant, may seek rehearing and appeal
pursuant to the FPA.
\885\ 16 U.S.C. 796(17). Section 3(17) of the FPA mandates a
size requirement for a small power production facility: It must have
``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.''
\886\ 16 U.S.C. 796(18).
\887\ 16 U.S.C. 825l. The Commission has previously entertained
rehearing of an order revoking QF status, Golden Valley Elec. Ass'n,
Inc., 167 FERC ] 61,208 (2019), reh'g denied, 170 FERC ] 61,025
(2020), and of an order denying petitions to revoke QF status, N.
Laramie Range All., 138 FERC ] 61,171, reh'g denied, 139 FERC ]
61,190 (2012), appeal dismissed, 733 F.3d 1030. There have also been
appeals of orders denying petitions to revoke QF status. N. Laramie
Range All. v. FERC, 733 F.3d 1030 (10th Cir. 2013) (dismissing
appeal on other grounds); Brazos Elec. Power Coop. Inc., v. FERC,
205 F.3d 235 (5th Cir. 2000) (denying petition for review). Unlike
PURPA section 210, PURPA section 201 amends the FPA and is therefore
subject to FPA section 313. See Portland Gen. Elec. Co. v. FERC, 854
F.3d 692, 700 (2017); Midland Power Coop. v. FERC, 774 F.3d 1, 3
(2014).
---------------------------------------------------------------------------
562. El Paso Electric states that sometimes the utility does not
know to protest, because sometimes QFs fail to provide utilities with
their QF application, and El Paso Electric is therefore concerned by
the Commission's proposal to limit protests by requiring that once the
Commission has affirmatively certified an applicant's QF status, any
later protest must demonstrate changed circumstances. We note that a QF
that is filing a FERC Form No. 556 is currently required by 18 CFR
292.207(c) (which we are not altering in this rule except to renumber
as 18 CFR 292.207(e)) to serve a copy on each electric utility with
which it expects to interconnect, transmit or sell electric energy to,
or purchase supplementary, standby, back-up or maintenance power from,
and the state regulatory authority of each state where the facility and
each affected utility is located. This final rule does not change that
requirement and we expect applicants to timely comply with that
regulation. Should an issue arise, though, the Commission can address
it on a case-by-case basis as the circumstances warrant. Additionally,
we note that, if a self-certification or self-recertification is not
protested within the 30 day-period permitted for protests, then, just
as it could prior to this final rule, a challenger still has the
ability to file a petition for declaratory order, with the filing fee,
without being required to show changed circumstances to do so.
563. Regarding Basin's request to allow petitions seeking de-
certification of QFs that have previously filed self-certifications and
ultimately never proceed to development,\888\ as we note above we limit
the ability to file a protest (rather than a petition for declaratory
order, with the accompanying filing fee) to within 30 days of the date
of the filing of the self-certification or self-recertification. If an
interested party would like to contest a self-certification or self-
recertification later than 30 days after the date of its filing, then
the interested party may file a petition for declaratory order with the
accompanying filing fee, just as they could prior to the effective date
of this final rule.
---------------------------------------------------------------------------
\888\ Basin Comments at 11.
---------------------------------------------------------------------------
564. We decline to adopt the requests that QF developers seeking
certification with the Commission be required to publish notice in
local newspapers in the states in which the development would be
located. We find that the service requirement already in our
regulations cited above should serve to provide adequate notice to
affected entities.
565. We decline to impose a 60-day deadline after which a failure
of the Commission to rule on the protest results in the protest being
denied by operation of law. Self-certification will be effective upon
filing and we adopt the NOPR proposal that the self-certifications will
remain effective after a protest has been filed, until such time as the
Commission issues an order revoking certification. We also clarify that
self-recertifications will likewise remain effective after a protest
has been filed, until such time as the Commission issues an order
revoking certification.
566. We also will adopt the NOPR's proposed timeline for issuance
of an order following protests to a QF self-certification and self-
recertification. The
[[Page 54709]]
Commission will issue an order within 90 days of the filing of a
protest. However, if 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. 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. We clarify, however, that, absent
Commission action by the date of the expiration of the tolling period,
a protest will be deemed denied, and the self-certification or self-
recertification will remain effective. We find that this timeline
provides both QFs and other interested persons with certainty about the
QFs' status within a reasonable amount of time.
567. Regarding Ares' concern that small power production QFs could
be aggregated under the new rule without being aware of the other small
power production QFs with which they are aggregated, the Commission
notes that this concern would only apply to small power production
facilities owned by the same person or its affiliates; it is unlikely
that the owner(s) of one facility would not be aware of other,
affiliated QFs. Furthermore, the presumption continues to be that a
small power production facility seeking QF status that is located more
than one but less than 10 miles from any affiliated small power
production QFs is at a separate site from those affiliated small power
production QFs, and the Commission here is simply making this
presumption rebuttable. If an entity challenges that presumption, the
applicant seeking QF status would necessarily be served with the
protest \889\ and thus informed of the challenge, and given the
opportunity to defend against the challenge.
---------------------------------------------------------------------------
\889\ 18 CFR 385.211(b).
---------------------------------------------------------------------------
568. Regarding Solar Energy Industries contention regarding the
currently pending Connected Entity proceeding, that is a separate
proceeding and beyond the scope of this proceeding. Moreover, the data
collection at issue in that proceeding does not eliminate the need for
the Commission to collect the data required by the FERC Form No. 556 so
that the Commission has the information it needs to determine whether a
facility qualifies to be a QF consistent with the standards laid out in
the statute. In any event, we note that the Connected Entity rulemaking
was about market-based rate sellers, not QFs, and it is likely that the
Connected Entity rulemaking would not apply to many QFs in the first
place since they often nether seek nor have the authority to sell at
market-based rates.
569. Regarding Allco's concerns about the RFA, we discuss the RFA
issue in section VII.
F. Corresponding Changes to the FERC Form No. 556
1. NOPR Proposal
570. The Commission proposed changes to the FERC Form No. 556,
corresponding to the new rules discussed above regarding whether QFs
are at separate sites. Currently, item 8a of FERC 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:
[GRAPHIC] [TIFF OMITTED] TR02SE20.000
571. The Commission proposed adding a new item 8b,\890\ 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.
---------------------------------------------------------------------------
\890\ Subsequent items in that section of the FERC Form No. 556
would be retained but re-numbered and moved down accordingly.
---------------------------------------------------------------------------
572. The Commission proposed 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 10 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,\891\ considering the
relevant physical and ownership factors. The Commission further
proposed to provide reference, in the instructions to the new item 8b,
to the paragraphs of this final rule which discuss the relevant
physical and ownership factors that may be asserted to defend against
rebuttal.
---------------------------------------------------------------------------
\891\ As discussed in detail in section IV.D.1.d, this final
rule will change the references to ``separate facilities'' or ``the
same facility'' to ``at separate sites'' or ``at the same site.''
---------------------------------------------------------------------------
573. The Commission sought comment on whether item 8a (existing)
should be revised and item 8b (as proposed) written to require that the
applicant specify the distance from the instant facility to each
affiliated facility listed. We also sought comment on whether items 8a
and (new) 8b should require the applicant to document (in the
Miscellaneous section on page 19 of the FERC Form No. 556) how the
distances reported were calculated. Specifically, we sought comment on
whether the applicant should be required to identify the particular
electrical generating equipment and associated geographic coordinates
used
[[Page 54710]]
in calculating the distance(s) between the facilities.
574. The Commission noted that item 8a currently requires
applicants to list all affiliated ``facilities.'' Under this
requirement, an applicant would have to list all affiliated QFs as well
as affiliated non-QFs. We requested comment on whether such a
requirement is more burdensome than necessary. It was 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.
575. The Commission also sought comment on whether item 3c
(geographic coordinates) and the Geographic Coordinates instructions on
page 4 of the current FERC 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 has been the case). We believed such
information may provide more transparency in measuring 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.
576. The Commission noted, as it did in Order No. 732,\892\ and as
in the general form instructions on page 4 of the FERC 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. The Commission also noted that the
Commission has a link on its QF web page (https://www.ferc.gov/industries-data/electric/power-sales-and-markets/purpa-qualifying-facilities) which provides assistance with determining geographic
coordinates of facilities. As such, the Commission believed that the
burden that would be created by requiring every QF to provide
geographic coordinates would be limited. Even so, the Commission sought
comment on whether the value of the information to the public and the
Commission would outweigh the limited burden.
---------------------------------------------------------------------------
\892\ 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).
---------------------------------------------------------------------------
2. Comments
577. A few commenters oppose the changes to FERC Form No. 556 as
proposed in the NOPR.\893\ Solar Energy Industries and the Southeast
Public Interest Organizations contend that the proposed new item 8b
that requests a list of all affiliated facilities within one to 10
miles from the certifying QF would be a significant increase in
information collection, time, effort, and cost of QF
certification.\894\
---------------------------------------------------------------------------
\893\ Solar Energy Industries Comments at 8; Southeast Public
Interest Organizations Comments at 36-37.
\894\ Solar Energy Industries Comments at 56; Southeast Public
Interest Organizations Comments at 36-37.
---------------------------------------------------------------------------
578. The Southeast Public Interest Organizations further object
that the obligation to show how distances are calculated and to
identify electrical generating equipment and their associated
geographic coordinates are overly burdensome for facilities that are
presumed to be separate and contradicts the rebuttable presumption of
separate facilities, which usually places the burden on the
challenger.\895\
---------------------------------------------------------------------------
\895\ Southeast Public Interest Organizations Comments at 37-38.
---------------------------------------------------------------------------
579. The Southeast Public Interest Organizations also assert it
would be reasonable to ask for only affiliated QFs and to exclude non-
QF affiliates from the questions in item 8.\896\
---------------------------------------------------------------------------
\896\ Id.
---------------------------------------------------------------------------
580. Several commenters support changes to FERC Form No. 556 as
proposed in the NOPR.\897\ A few commenters support the proposed
changes to item 8a and proposed new item 8b and argue that the
additional information might be otherwise difficult to find and will be
useful to clarify if the assumption of separate facilities is
appropriate.\898\ Some commenters support requiring all applicants to
supply geographic coordinates in item 3c, regardless of whether they
have a street address.\899\
---------------------------------------------------------------------------
\897\ APPA Comments at 23; EEI Comments at 50; Portland General
Comments at 17-18; Subsurface Engineering Association Comments at 1.
\898\ APPA Comments at 23-24; EEI Comments at 50.
\899\ EEI Comments at 50; Idaho Commission Comments at 7;
Subsurface Engineering Association Comments at 1.
---------------------------------------------------------------------------
581. Two commenters support the collection of information for all
affiliated facilities, not just QF affiliates, within the one or ten-
mile radius requested in item 8a and proposed item 8b, respectively,
because they believe it will be needed to identify QFs not complying
with the proposed rule.\900\
---------------------------------------------------------------------------
\900\ EEI Comments at 50-51; Portland General Comments at 18.
---------------------------------------------------------------------------
582. Solar Energy Industries assert that the proposed item 8b to
the Form No. 556, requiring a listing of all affiliated facilities
whose nearest electrical generating equipment is greater than one mile
and less than 10 miles from the electrical generating equipment of the
certifying QF, is a substantial expansion of the information collection
requirements and goes against the Commission's previously-granted
blanket exemptions for QFs to relieve the burden of public utility
regulation. Solar Energy Industries argue that this is not a mere
information collection requirement, but a request for information that
is not otherwise publicly available and is inconsistent with the
Commission's finding on the burden of collecting Connected Entity
information. Solar Energy Industries argue that collecting such
information from QFs is unwarranted discriminatory treatment and is
arbitrary and capricious.\901\
---------------------------------------------------------------------------
\901\ Solar Energy Industries Comments at 56-57.
---------------------------------------------------------------------------
583. A few commenters requested additional changes to FERC Form No.
556.\902\ North American-Central would like the Commission to create
separate Form No. 556 forms for small power producers and cogeneration
QFs for a more distinct and simplified application process.\903\ EEI
would like Form No. 556 to explicitly include battery storage.\904\ EEI
requests that the Form No. 556 collect information on the rated
capacity and notes that net capacity may not be the appropriate measure
of power production. Solar Energy Industries also noted that the
Commission stated in Order No. 732 that future changes to Form No. 556
would not go through a rulemaking and would instead be reviewed by the
Office of Management and Budget with a period for public comments.\905\
---------------------------------------------------------------------------
\902\ EEI Comments at 51; El Paso Electric Comments at 5-6;
North American-Central Comments at 7.
\903\ North American-Central Comments at 7.
\904\ EEI Comments at 51-52.
\905\ Solar Energy Industries Comments at 56.
---------------------------------------------------------------------------
3. Commission Determination
584. We adopt the NOPR proposals regarding changes to the FERC Form
No. 556, with the further clarifications and additions described below.
The revised Form No. 556 will be attached to this rule in eLibrary, but
will not be published in the Federal Register or Code of Federal
Regulations. The Commission finds that the added information collected
by these changes
[[Page 54711]]
is necessary to implement the changes made to the regulations in this
final rule, and thus justifies the increase in reporting burden.
585. The currently effective Form No. 556 contains a ``Who Must
File'' section which specifies when an applicant seeking QF status or
recertification of QF status must file a self-certification, and when
such applicant is exempt from the filing requirement. We will revise
the ``Who Must File'' section to clarify that the exemption from the
requirement to complete or file a Form No. 556 applies to an applicant
seeking QF status for a small power production facility that, together
with any affiliated small power production QFs within one mile of the
entity seeking small power production QF status, has a net power
production capacity of 1 MW or less. While we did not seek comment on
this corrective change in the NOPR, this change is consistent with the
Commission's determination in SunE B9 Holdings LLC, \906\ and serves to
make the Form No. 556 more transparent in its application.
---------------------------------------------------------------------------
\906\ 157 FERC ] 61,044 at P 16 (``the one-mile rule of section
292.204(a)(2) is a size determination which the Commission has
consistently applied generally to the regulations pursuant to PURPA,
and which applies here to determining the applicability of the less-
than-1-MW exemption of section 292.203(d)'') (internal citations
omitted).
---------------------------------------------------------------------------
586. We also revise the ``Who Must File'' section to include a
``Recertification'' section which provides the text of revised 18 CFR
292.207(f), (previously 18 CFR 292.207(d)) which states that a QF must
file for recertification whenever the QF ``fails to conform with any
material facts or representation presented . . . in its submittals to
the Commission.'' \907\
---------------------------------------------------------------------------
\907\ 18 CFR 292.207(d).
---------------------------------------------------------------------------
This addition does not alter our recertification requirements, and
we include it here simply to make the Form No. 556 clearer in its
application.
587. The total burden estimates in the ``Paperwork Reduction Act
Notice'' section of FERC Form No. 556 will be updated based on the
changes in this final rule, to provide the following estimates: 1.5
hours for self-certifications of facilities of 1 MW or less; 1.5 hours
for self-certifications of a cogeneration facility over 1 MW; 50 hours
for applications for Commission certification of a cogeneration
facility; 3.5 hours for self-certifications of small power producers
over 1 MW and less than a mile or more than 10 miles from affiliated
small power production QFs that use the same energy resource; 56 hours
for an application for Commission certification of a small power
production facility over 1 MW and less than a mile or more than 10
miles from affiliated small power production QFs that use the same
energy resource; 9.5 hours for self-certifications of small power
producers over 1 MW with affiliated small power production QFs more
than one but less than 10 miles that use the same energy resource; 62
hours for an application for Commission certification of a small power
production facility over 1 MW with affiliated small power production
QFs more than one but less than 10 miles that use the same energy
resource.
588. We find that an explanatory ``Protest to the Filing'' section
should be added to the FERC Form No. 556 to note that, pursuant to 18
CFR 292.207, an interested person or entity has 30 days from the date
of the filing of the FERC Form No. 556 to intervene or file a protest.
The ``Protest to the Filing'' section will state that the protestor
must concurrently serve a copy of such filing, pursuant to 18 CFR
385.211(b), on the Form No. 556 applicant. The ``Protest to the
Filing'' section will also state that the Form No. 556 applicant will
have 30 days to file any answer to a protest. The ``Protest to the
Filing'' section will also state that protests may be made to any
initial certification, and any recertifications on or after the
effective date of this final rule making substantive changes to the
existing certification, which may include, for example, a change in
electrical generating equipment that increases power production
capacity by the greater of 1 MW or 10 percent of the previously
certified capacity of the QF, or a change in ownership in which an
owner increases their equity interest by at least 10% from the equity
interest previously reported. The ``Protest to the Filing'' section
will note that ``administrative only'' changes will not be subject to
protests.
589. The Commission finds that item 3c (geographic coordinates) and
the Geographic Coordinates instructions on page 4 of the current FERC
Form No. 556 will be revised to require all applicants to report the
applicant facility's geographic coordinates, rather than only for
applications where there is no street address (as was the case
previously). We find that such information will provide more
transparency regarding the location of each site, and that such
transparency may be useful for both the public and Commission staff in
monitoring compliance with the Commission's QF regulations.
590. The Commission will change item 8a, which currently requires
applicants to list all affiliated facilities within one mile, to
instead require that the applicant only list affiliated small power
production QFs using the same energy resource within one mile.
591. We modify the NOPR's proposal to add the collection of
information for affiliated facilities whose nearest electrical
generating equipment is more than one but less than 10 miles from the
electrical generating equipment of the applicant's facility to instead
add the collection of information for affiliated small power production
QFs using the same energy resource located more than one mile but less
than 10 miles from the electrical generating equipment of the
applicant's facility. However, rather than adding a separate item 8b to
the Form No. 556 specifically for such QFs, as proposed in the NOPR, we
are expanding the existing item 8a to require the applicant to list all
affiliated small power production QFs using the same energy resource
whose nearest electrical generating equipment is less than 10 miles
from the electrical generating equipment of the entity seeking small
power production QF status.
592. We determine that the revised item 8a will require the
applicant to list the geographic coordinates of the nearest
``electrical generating equipment'' of both its own facility and the
affiliated small power production QF in question based on the
definitions adopted in this final rule. The distance between the entity
seeking small power production QF status and each affiliated small
power production QF will be automatically calculated based on these
coordinates. For any affiliated small power production QFs that cannot
be described in item 8a due to space limitations, the instructions will
direct applicants to provide the required information for such small
power production QFs in the Miscellaneous section of the form. To
facilitate the uniform calculation of distances for facility data that
are entered into the Miscellaneous section of the form, a distance
calculator will be added to the form, and the form instructions will
direct applicants to use the calculator to convert their facilities'
geographic coordinates into distance.
593. The Commission also adopts the NOPR proposal to allow
applicants with affiliated small power production QFs greater than one
mile and less than 10 miles from the electrical generating equipment of
the entity seeking small power production QF status identified under
item 8a to, if they choose, explain why the affiliated small power
production QFs greater than one mile and less than 10 miles from the
nearest electrical generating equipment of the entity seeking QF status
identified
[[Page 54712]]
under item 8a should be considered to be at separate sites from the
entity seeking QF status, considering the relevant physical and
ownership factors. The instructions will provide references to the
relevant physical and ownership factors, as defined in this final rule,
that may be asserted to defend against rebuttal.
594. Regarding Solar Energy Industries' concern regarding the
expansion of the information collection requirements, we find that the
added information collected by item 8a of the Form No. 556 is necessary
to implement the changes made to the regulations in this final rule,
and thus justifies the increase in reporting burden. As noted in
section IV.E, the currently pending Connected Entity proceeding is a
separate proceeding and beyond the scope of this proceeding. Moreover,
the data collection at issue in that proceeding does not eliminate the
need for the Commission to collect the data required by the FERC Form
No. 556 so that the Commission has the information it needs to
determine whether a facility qualifies to be a QF consistent with the
standards laid out in the statute.
595. We note that these changes and any future changes to Form No.
556 will continue to be reviewed by the Office of Management and Budget
following solicitation of comments from the public, as described in
Order No. 732.\908\
---------------------------------------------------------------------------
\908\ Order No. 732, 130 FERC ] 61,214.
---------------------------------------------------------------------------
596. We find the requests for additional changes to FERC Form No.
556 beyond the scope of this proceeding.
G. PURPA Section 210(m) Rebuttable Presumption of Nondiscriminatory
Access to Markets
1. PURPA Section 210(m) Implementation
a. NOPR Proposal
597. 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, fourteen years later, the
markets are more mature, and the mechanics of participation in such
markets are improved and better understood. Consequently, in the NOPR,
the Commission determined that small power production facilities below
20 MW should now be able to participate in such markets under most
circumstances. The Commission therefore proposed to revise 18 CFR
292.309(d) 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.
598. The Commission determined that, in light of the maturation of
organized electric markets, such a reduction was consistent with
Congress's intent to relieve electric utilities of their obligation to
purchase when a QF has nondiscriminatory access to competitive markets.
599. The Commission noted that, in establishing the original
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, it had acknowledged that ``there is no
unique and distinct megawatt size that uniquely determines if a
generator is small.'' \909\ The Commission noted that, in using 20 MW
to separate the presumption that large QFs had nondiscriminatory access
and small QFs lacked such access, the Commission had 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-A's
setting 20 MW as the demarcation for different interconnection
standards between small and large generators.\910\ The NOPR stated
that, while the Commission had not (and likewise did not in the NOPR)
propose to revise the exemptions for QFs from sections 205 and 206 of
the FPA, the Commission had elsewhere taken steps to ease both
interconnection and market access for generation resources with small
capacities since it first implemented section 210(m) of PURPA.
---------------------------------------------------------------------------
\909\ Order No. 688-A, 119 FERC ] 61,305 at P 97.
\910\ 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) (``[S]ales 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, 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).
---------------------------------------------------------------------------
600. For example, the Commission noted that it had 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),\911\ and had 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.\912\
While both of these changes do not apply only to generation types that
could become QFs or only to RTOs/ISOs, the Commission stated that it
believed 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. The Commission also stated that, under the NOPR proposal
and like QFs over 20 MW today, small power production facilities over 1
MW would still be able to rebut the presumption of access due to
operational characteristics or transmission constraints.\913\
---------------------------------------------------------------------------
\911\ 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).
\912\ Order No. 841, 162 FERC ] 61,127 at P 265.
\913\ See 18 CFR 292.309(c), (e), (f).
---------------------------------------------------------------------------
601. The Commission did not propose to make the same reduction
applicable to cogeneration facilities. The Commission stated that,
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.\914\ Consequently, the
production and sale of electricity is a byproduct of these thermal
processes, and owners of cogeneration facilities might not be as
familiar with energy markets and the technical requirements for such
sales. The Commission stated that retention of the existing 20 MW level
for the presumption of access to markets therefore would be appropriate
for cogeneration facilities.
---------------------------------------------------------------------------
\914\ 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).
---------------------------------------------------------------------------
b. Comments in Opposition
602. Numerous commenters oppose the NOPR proposal to revise 18 CFR
292.309(d) to reduce the net power production capacity level at which
the presumption of nondiscriminatory
[[Page 54713]]
access to a market attaches for small power production facilities, but
not cogeneration facilities, from 20 MW to 1 MW.\915\
---------------------------------------------------------------------------
\915\ Allco Comments at 2, 17-19; Advanced Energy Economy
Comments at 1-12; AllEarth Comments at 2; Biogas Comments at 2-3;
Biological Diversity Comments at 8-9; California Commission Comments
at 31-33; CARE Comments at 5-6; Con Edison Comments at 5; Covanta
Comments at 10-12; DC Commission Comments at 4-5; Distributed Sun
Comments at 2-3; ELCON Comments at 18, 31-35; Energy Recovery
Comments at 4-5; ENGIE Comments at 3-4; Commissioner Slaughter
Comments at 2, 4; Green Power Comments at 3; Industrial Energy
Consumers Comments at 6-10; Massachusetts AG Comments at 6-8;
Michigan Commission Comments at 6-7; North American-Central at 2-4;
One Energy Comments at 2; South Dakota Commission Comments at 5;
Solar Energy Industries Comments at 44-51; State Entities Comments
at 5-6; Western Resource Councils Comments at 1-144.
---------------------------------------------------------------------------
i. Insufficient Evidentiary Support
603. Several commenters argue that the record does not support the
proposal.\916\
---------------------------------------------------------------------------
\916\ AllEarth Comments at 2; Advanced Energy Economy Comments
at 5-9; Biological Diversity Comments at 9; ELCON Comments at 31-32;
Industrial Energy Consumers Comments at 8; New England Hydropower
Comments at 11-12; NIPPC, CREA, REC, and OSEIA Comments at 77;
Public Interest Organizations Comments at 76-78; SC Solar Alliance
Comments at 12; Solar Energy Industries Comments at 45-48; Southeast
Public Interest Organization Comments at 39-40.
---------------------------------------------------------------------------
604. Advanced Energy Economy asserts that, when an agency reverses
course on a policy issue, and the ``new policy rests upon factual
findings that contradict those which underlay'' the previous policy,
then the agency must ``provide a more detailed justification than what
would suffice for new policy created on a blank slate.'' \917\ Advanced
Energy Economy argues that the NOPR falls short of that standard.\918\
---------------------------------------------------------------------------
\917\ Advanced Energy Economy Comments at 6 (citing FCC v. Fox
Television Stations, Inc., 556 U.S. at 515).
\918\ Id. at 7.
---------------------------------------------------------------------------
605. Public Interest Organizations and NIPPC, CREA, REC and OSEI
argue that the Commission fails to cite any evidence supporting the
premise that the markets are more mature, and that the mechanics of
participation in such markets are improved and better understood.
Public Interest Organizations and NIPPC, CREA, REC, and OSEIA state
that the Commission asserts that QFs smaller than 20 MW can now
participate in markets on a nondiscriminatory basis ``under most
circumstances,'' but that the Commission does not explain what those
``circumstances'' are, or whether they apply as a general matter to
most small QFs.\919\
---------------------------------------------------------------------------
\919\ Public Interest Organizations Comments at 78; NIPPC, CREA,
REC, and OSEIA Comments at 77 (citing NOPR, 168 FERC ] 61,184 at P
126).
---------------------------------------------------------------------------
606. Several commenters state that, in Order No. 688-A, the
Commission, rejected utility proposals to set the threshold at 1 MW,
and confirmed that 20 MW was an appropriate threshold.\920\ Advanced
Energy Economy states that the Commission's explanation in Order No.
688-A, which stated that the rebuttable presumptions were based on the
Commission's experience of implementing non-discriminatory open access
transmission over the past 11 years, dealing with QF issues over the
past 29 years and its experience with RTO/ISO markets for almost 10
years, contradicts the Commission's justification in the NOPR of
limited experience with organized electric markets.\921\ Advanced
Energy Economy and Southeast Public Interest Organizations assert that,
since Order No. 688, the Commission has repeatedly found that utilities
in organized markets have failed to rebut the presumption of
nondiscriminatory access to QFs, instead finding that QFs 20 MW and
under do not have sufficient access.\922\
---------------------------------------------------------------------------
\920\ Advanced Energy Economy Comments at 5-6; ELCON Comments at
31-32.
\921\ Advanced Energy Economy Comments at 8-9.
\922\ Id. (citing, e.g., PPL Elec. Utils Corp., 145 FERC ]
61,053, at P 24 (2013); City of Burlington, 145 FERC ] 61,121, at P
36 (2013); Fitchburg Gas and Elec. Light Co., 146 FERC ] 61,186, at
PP 32-33 (2014); Va. Elec. & Power Co., 151 FERC ] 61,038, at P 21
(2015); N. States Power Co., 151 FERC ] 61,110 (2015)); Southeast
Public Interest Organizations Comments at 39-40.
---------------------------------------------------------------------------
607. Public Interest Organizations and NIPPC, CREA, REC, and OSEIA
argue that the Commission fails to explain the relevance of its Fast-
Track interconnection process or energy storage order or which barriers
these developments alleviate for small QFs' access to markets.\923\
Advanced Energy Economy asserts that the expansion of the Fast-Track
procedures only applied to a narrow slice of inverter-based resources
under 20 MW and is insufficient to support a rebuttable presumption
that all QFs under 20 MW have nondiscriminatory access.\924\
---------------------------------------------------------------------------
\923\ NIPPC, CREA, REC, and OSEIA at 77; Public Interest
Organizations Comments at 78 (citing Motor Vehicle Mfrs. Ass'n of
U.S., Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983)
(explaining that an agency's failure to consider the relevant
factors and supply a ``rational connection between the facts found
and the choice made'' renders its decision arbitrary and
capricious)).
\924\ Advanced Energy Comments at 7-8.
---------------------------------------------------------------------------
608. Solar Energy Industries and New England Hydro argue that, just
because some small QFs participate in energy markets, that is not
sufficient justification to find that all small QFs meet the statutory
standard required for granting waiver for all QFs 20 MW or less.\925\
Public Interest Organizations assert that proper implementation of
section 210(m) requires that exemption from the mandatory purchase
obligation only applies where QF development will be stimulated by
market forces; otherwise Congress intended QF development to continue
to be encouraged by the mandatory purchase obligation.\926\ Protesters
assert that the record does not provide evidence that could reasonably
allow the Commission to conclude that small QF development will be
stimulated by market forces. On the contrary, the Public Interest
Organizations assert that the Commission's proposal placing the burden
on small QFs to rebut the presumption of access is itself a barrier to
QF development.\927\
---------------------------------------------------------------------------
\925\ Solar Energy Industries Comments at 46; New England Hydro
Comments at 11-12.
\926\ Public Interest Organizations Comments at 76 (citing New
PURPA Section 210(m) Regulations Applicable to Small Power
Production and Cogeneration Facilities, Order No. 688, 117 FERC ]
61,078, at P 6 (2006), order on reh'g, Order No. 688-A, 119 FERC ]
61,305 (2007), aff'd sub nom. Am. Forest and Paper Ass'n v. FERC,
550 F.3d 1179).
\927\ Id.
---------------------------------------------------------------------------
609. Solar Energy Industries argue that, along with the energy
markets, the capacity markets in the RTO/ISO regions have not evolved
to provide a meaningful opportunity for any QF to sell long-term
capacity.\928\ Solar Energy Industries argue that PURPA section 210(m)
requires the Commission to find that a QF has nondiscriminatory access
to a market for long-term sales of capacity prior to relieving the
purchase obligation. Solar Energy Industries provide several examples
such as MISO's Planning Resources Auction that only provides a one-year
purchase agreement, PJM not purchasing capacity since the Commission's
July 2019 Order, and that SPP does not have a centralized capacity
market. Solar Energy Industries argue that without a specific finding
that RTO/ISO markets provide QFs with an opportunity to sell long-term
capacity, the Commission is statutorily required to maintain utilities'
obligation to purchase output from QFs 20 MWs or less.\929\
---------------------------------------------------------------------------
\928\ Solar Energy Industries Comments at 45.
\929\ Id. at 49.
---------------------------------------------------------------------------
610. Mr. Mattson asserts, without elaboration, that FPA sections
205 and 206 disallow the Commission from lowering the nondiscriminatory
access threshold from 20 MW to 1 MW, and, therefore, claims it would
amount to a violation of state-jurisdictional rights and a taking of
property.\930\
---------------------------------------------------------------------------
\930\ Mr. Mattson Comments at 10.
---------------------------------------------------------------------------
ii. Administrative Burden and Complex Market Rules
611. The DC Commission state that QFs 20 MW or less lack the
capability
[[Page 54714]]
to participate in a complicated wholesale market such as PJM where
there is a need to understand membership obligations and rules in order
to appropriately execute transactions.\931\
---------------------------------------------------------------------------
\931\ DC Commission Comments at 4-5.
---------------------------------------------------------------------------
612. Allco argues that, in retail choice states, PURPA is the only
way small QFs can sell to utilities. Allco asserts that in retail
choice states there is a shifting retail customer base, therefore
utilities want obligations reduced and contracts limited to a year.
Allco asserts that utilities and state commissions cannot limit
contracts due to a potentially disappearing customer base and then
argue that a sufficient wholesale market exists for long-term sales of
electric energy and capacity to support nondiscriminatory access for
small QFs under 20 MW.\932\
---------------------------------------------------------------------------
\932\ Allco Comments at 18.
---------------------------------------------------------------------------
613. Public Interest Organizations argue that giving special
exemptions to cogeneration facilities is discriminatory against small
power producer QFs.\933\ Two commenters also assert that small QFs are
at an inherent disadvantage compared to larger QFs because smaller QFs
are often engaged in other business enterprises, such as governmental
units distributing irrigation water or local companies unfamiliar with
energy markets.\934\
---------------------------------------------------------------------------
\933\ Public Interest Organizations Comments at 74.
\934\ NIPPC, CREA, REC, and OSEIA Comments at 18-19, 24-25; Mr.
Mattson Comments at 15.
---------------------------------------------------------------------------
c. Comments in Support
614. Numerous commenters support the proposal to revise 18 CFR
292.309(d) for small power production facilities but not cogeneration
facilities, to reduce the net power production capacity level at which
the presumption of nondiscriminatory access to a market applies from 20
MW to 1 MW.\935\ DTE Electric argues that RTO/ISOs can now provide
smaller resources non-discriminatory access, and therefore electric
utilities should no longer be required to purchase electric energy from
them.\936\ EEI supports the proposal because resource diversity has
improved and markets have evolved as smaller resources, including QFs,
are increasingly participating in the RTO/ISO markets. RTOs/ISOs have
also increasingly adjusted their bidding rules, forecasts, and
operations to better accommodate variable resources.\937\ Alliant and
the Ohio Commission Energy Advocate state that small resources have
increased access to wholesale markets and that RTO/ISO rule flexibility
allows for the non-discriminatory participation of very small resources
and the aggregation of even smaller resources in the markets, therefore
the 20 MW threshold is no longer appropriate.\938\
---------------------------------------------------------------------------
\935\ Alliant Energy Comments at 13-16; Tax Reform Comments at
2; APPA Comments at 24-26; Arizona Public Service Comments at 8-10;
Basin Comments at 12-13; Freedom Center Comments at 2; Colorado
Independent Energy Comments at 14; Connecticut Commission Comments
at 21-22; Conservative Action Comments at 2; Consumers Alliance
Comments at 1-2; Consumers Energy Comments at 4-5; DTE Electric
Comments at 4-5; East Kentucky Comments at 3; East River Comments at
2; EEI Comments 54-59; FirstEnergy Comments at 2-3; Idaho Power
comments at 14; Indiana Municipal Comments at 6-9; Institute for
Energy Research Comments at 2; Kentucky Commission Comments at 8;
Missouri River Energy Comments at 3-4; NorthWestern at 14; TAPS
Comments at 4; Ohio Commission Energy Advocate Comments at 8;
Taxpayers Protection Alliance Comments at 2; Chamber of Commerce
Comments at 7; We Stand Comments at 1-144; Taxpayer Protection
Alliance Comments at 2; TAPS Comments at 4.
\936\ DTE Electric Comments at 5-6.
\937\ EEI Comments at 56-58.
\938\ Alliant Energy Comments at 13-14; Ohio Commission Energy
Advocate Comments at 7-8.
---------------------------------------------------------------------------
615. Consumer Alliance and EEI argue that reducing the threshold
will reduce costs to customers because currently some QFs with access
to markets are foregoing the opportunity to participate in those
markets and electing to contract with electric utilities under state-
implemented PURPA programs, which EEI argues compensate QFs at an
above-market rate.\939\
---------------------------------------------------------------------------
\939\ EEI Comments at 58-59; Consumers Alliance Comments at 1-2.
---------------------------------------------------------------------------
616. The Ohio Commission Energy Advocate argues that the rebuttable
presumption process for QFs provides an appropriate safety valve for
the lower threshold.\940\
---------------------------------------------------------------------------
\940\ Ohio Commission Energy Advocate Comments at 8.
---------------------------------------------------------------------------
d. Comments Requesting Modifications/Clarifications
617. Institute for Energy Research requests that the Commission
expand the rebuttable presumption of non-discriminatory access to QFs 1
MW and below if the market structure in a given state is appropriate.
Institute for Energy Research gives the example of Texas's open market
model, where generation is open to all comers of all sizes. Institute
for Energy Research also suggests that the Commission should include
some threshold now such that when other states achieve similar open
access market designs QFs 1 MW and below could be rebuttably presumed
to have non-discriminatory access to those markets, without the need to
undertake, at that time, a separate rulemaking on QFs 1 MW and
below.\941\
---------------------------------------------------------------------------
\941\ Institute of Energy Research Comments at 2.
---------------------------------------------------------------------------
618. The Connecticut Commission suggests reducing the threshold at
which the presumption of nondiscriminatory access attaches to 0 MW
because the markets are more mature, the mechanics of participating in
the markets are improved and the law requires nondiscriminatory access
to the markets for all resources.\942\ Missouri River Energy recommends
lowering the threshold to 500 kW.\943\ FirstEnergy recommends the
Commission treat both small power production resources and cogeneration
resources consistently by lowering the rebuttable presumption threshold
from 20 MW to 1 MW for all QFs.\944\ Indiana Municipal requests that
the Commission automatically apply the 1 MW threshold to utilities that
have already been granted waiver for QFs over 20 MW to promote the
efficient use of the Commission's resources and savings to
utilities.\945\
---------------------------------------------------------------------------
\942\ Connecticut Commission Comments at 21-23.
\943\ Missouri River Energy Comments at 3.
\944\ FirstEnergy Comments at 2-3.
\945\ Indiana Municipal Comments at 8-9.
---------------------------------------------------------------------------
619. The Michigan Commission requests clarification on the NOPR
proposal specifically regarding: (1) How existing contracts with QFs
greater than 1 MW but below 20 MWs are to be treated under the NOPR,
and if they would be subject to early termination or would be granted
legacy treatment indefinitely or until the end of the existing contract
term; (2) whether utilities that have already received relief from the
mandatory purchase obligation from the Commission for operating within
the footprint of an organized wholesale electricity market
automatically qualify for relief under the 1 MW threshold; and (3) how
interconnection requirements would be considered for QFs between 1 MW
and 20 MWs--specifically whether these projects would need to
interconnect at transmission level voltages to be considered as having
access to the wholesale electricity market.\946\ The Michigan
Commission notes that there is some tension between the proposal and
the market rules for MISO and PJM.\947\
---------------------------------------------------------------------------
\946\ Michigan Commission Comments at 6-7
\947\ Id. at 7 (commenting that MISO, for example, utilizes a 5
MW threshold as the cut off point for Network Modeling purposes and
that resources less than 5 MW are modeled on a case-by-case basis
only).
---------------------------------------------------------------------------
620. Several commenters request that the Commission expand the
exemption for cogeneration to small power QFs whose primary purpose is
to self-supply but still rely on PURPA when making occasional sales to
the interconnected utility when QF output exceeds on-site
consumption.\948\ Industrial Energy
[[Page 54715]]
Consumers suggest that small power producers seeking a 20 MW self-
supply exemption meet the ``fundamental use test'' which currently
applies to cogeneration facilities.\949\ Other commenters assert that
behind-the-meter distributed energy resources,\950\ Waste to Energy
resources,\951\ and baseload renewables \952\ are similar to
cogeneration facilities and should be included in the exemption.
---------------------------------------------------------------------------
\948\ ELCON Comments at 32-33; Industrial Energy Consumers
Comments at 6-8; Chamber of Commerce Comments at 7.
\949\ Industrial Energy Consumers Comments at 9-10.
\950\ One Energy Comments at 2.
\951\ Industrial Energy Consumers Comments at 9-10.
\952\ Renewable Baseload Coalition Comments at 2.
---------------------------------------------------------------------------
621. Public Interest Organizations request that the Commission
clarify that utilities are required to petition to eliminate the must-
purchase obligation for small QFs, even for those utilities that have
previously made such a showing for QFs larger than 20 MW.\953\ NRECA,
concerned over a potential change in aggregation for distributed energy
resources in RTOs/ISOs, requests that the Commission clarify that the
presumption will only apply to those facilities having sufficient
transmission access to the RTO/ISO markets.\954\
---------------------------------------------------------------------------
\953\ Public Interest Organizations Comments at 76.
\954\ NRECA Comments at 18-19.
---------------------------------------------------------------------------
622. Hydropower Association asserts that, despite their potential,
hydropower resources do not receive the same tax treatment and
eligibility for state RPSs and therefore have not enjoyed the same
growth rate as other renewable energy small power producers. Hydropower
Association urges the Commission to retain the 20 MW rebuttable
presumption for hydropower resources, as would be the case for
cogenerators, because hydropower resources are required by the FPA
section 10(a) to be best adapted for comprehensive uses, including non-
power generation purposes such as irrigation, flood control,
navigation, recreation, environmental restoration, and wildlife
preservation. Hydropower Association states that non-powered dams by
definition were not constructed to generate power. Because power
generation is therefore a secondary use of these facilities, Hydropower
Association asserts that subjecting these facilities to new avoided
cost calculations will necessarily burden hydropower resources more
than other small power production facilities. Hydropower Association
also asserts that there is almost 5 GW of potential non-power dams that
could be developed and that the 20 MW exemption should be retained for
these resources.\955\
---------------------------------------------------------------------------
\955\ Hydropower Association Comments at 2-7 (citing 16 U.S.C.
803).
---------------------------------------------------------------------------
623. Ohio Consumers Counsel states that lowering the rebuttable
presumption could permit electric utilities and state policies to deny
QFs and distributed energy resources under 20 MW from having
unrestricted and nondiscriminatory access to wholesale markets. For
example, Ohio Consumers Counsel states that the NOPR would permit
electric distribution utilities to limit the availability of after-the-
meter generation and storage from PJM's markets, such as through
restrictive net metering requirements, unreasonably low compensation
for distributed energy resources, or other state regulatory and policy
restrictions. Ohio Consumers Counsel urges the Commission to require
that investor-owned electric distribution utilities demonstrate that
they have not restricted market access to QFs and distributed energy
resources rated between 1 MW and 20 MW.\956\
---------------------------------------------------------------------------
\956\ Ohio Consumers Counsel Comments at 2-5.
---------------------------------------------------------------------------
e. Commission Determination
624. We agree with commenters that, in Order Nos. 688 and 688-A,
given conditions at the time, the Commission established the rebuttable
presumption at QFs 20 MW or less. Furthermore, as commenters noted in
reviewing several individual cases in 2013-2015, the Commission
continued to find that those individual small power production
facilities 20 MW or less still needed the additional protections and
encouragement.\957\ However, since Order Nos. 688 and 688-A the
Commission has recognized multiple examples of small power production
facilities under 20 MW participating in RTO/ISO energy markets. The
Commission found that the electric utilities in those proceedings
rebutted the presumption of no market access and therefore terminated
the mandatory purchase obligation.\958\
---------------------------------------------------------------------------
\957\ PPL Elec. Utilities Corp., 145 FERC ] 61,053 at P 24; Va.
Elec. & Power Co., 151 FERC ] 61,038, at P 21; N. States Power Co.,
151 FERC ] 61,110.
\958\ See, e.g., Fitchburg Gas and Elec. Light Co., 146 FERC ]
61,186, at P 33 (2014); City of Burlington, Vt., 145 FERC ] 61,121,
at P 33 (2013).
---------------------------------------------------------------------------
625. We adopt the proposal to revise 18 CFR 292.309(d) 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 for cogeneration facilities. However,
recognizing some of the challenges that QFs near 1 MW have in
participating in such markets that have been identified by commenters,
in this final rule we lower the rebuttable presumption from 20 MW to 5
MW, rather than from 20 MW to 1 MW as proposed in the NOPR. Under the
final rule, small power production facilities with a net power
production capacity at or below 5 MW will be presumed not to have
nondiscriminatory access to markets, and, conversely, small power
production facilities with a net power production capacity over 5 MW
will be presumed to have nondiscriminatory access to markets.
626. A number of commenters oppose the reduction below 20 MW,
arguing the lack of a record to support the proposal. We disagree. In
Order Nos. 688 and 688-A, the Commission determined that small QFs may
not have nondiscriminatory access to wholesale markets and, therefore,
it was reasonable to establish a presumption for small QFs. At that
time, the Commission found that it was ``reasonable and
administratively workable'' to define ``small'' for purposes of this
regulation to be QFs below 20 MW.\959\ We also note that a number of
commenters, including state entities which are charged with applying
PURPA in their jurisdictions,\960\ supported a reduction in the 20 MW
threshold.
---------------------------------------------------------------------------
\959\ See Order No. 688, 117 FERC ] 61,078 at PP 74-78
(establishing rebuttable presumption); Order No. 688-A, 119 FERC ]
61,305 at P 95 (``There is no perfect bright line that can be drawn
and we have reasonably exercised our discretion in adopting a 20 MW
or below demarcation for purposes of determining which QFs are
unlikely to have nondiscriminatory access to markets.'').
\960\ See Connecticut Commission Comments at 20-21; Kentucky
Commission Comments at 8.
---------------------------------------------------------------------------
627. The Commission acknowledged that there is no unique number to
draw a line for determining what is a small entity.\961\ In
establishing 20 MW presumption as the line between large and small QFs
for purposes of section 210(m), the Commission looked at other non-QF
rulemaking orders in which it considered what was a small entity and
those orders showed 20 MW was a reasonable number at which to draw the
line.\962\ But, as explained below, the Commission has since
determined, based on changed circumstances since the issuance of Order
Nos. 688 and 688-A, that entities with capacity lower than 20 MW have
nondiscriminatory access to the markets and, therefore, capacity
[[Page 54716]]
level of 20 MW may no longer be a reasonable place to establish the
presumption on what constitutes a smaller entity under our regulations.
---------------------------------------------------------------------------
\961\ Order No. 688-A, 119 FERC ] 61,305 at P 97 (``Although
there is no unique and distinct megawatt size that uniquely
determines if a generator is small, in other contexts the Commission
has used 20 MW, based on similar considerations to those presented
here, to determine the applicability of its rules and policies.'').
\962\ See Order No. 688, 117 FERC ] 61,078 at P 76; Order No.
688-A, 119 FERC ] 61,305 at PP 96-97.
---------------------------------------------------------------------------
628. Similar to our analysis in Order No. 688, we have determined
that entities below 20 MW now can participate in RTO/ISO markets.\963\
Here, we are updating the rebuttable presumption based on industry
changes since Order No. 688. Moreover, it is reasonable to update the
rebuttable presumption as markets defined in PURPA section
210(m)(1)(A), (B), and (C) evolve because that statute itself does not
establish a presumption and we are updating the rules, as PURPA
provides we will do from time to time, to ensure we comply with PURPA.
However, because the revised presumption established in this final rule
is a rebuttable presumption, QFs can seek to overcome it.
---------------------------------------------------------------------------
\963\ In fact, when the Commission established the rebuttable
presumption of 20 MW, commenters in that proceeding cited instances
where QFs at 1 MW or above had already had nondiscriminatory access
to RTOs/ISOs. See Order No. 688, 117 FERC ] 61,078 at PP 64-66.
---------------------------------------------------------------------------
629. Over the last 15 years, the RTO/ISO markets have matured,
market participants have gained a better understanding of the mechanics
of such markets, and, as a result, we find that it is reasonable to
presume that access to the RTO/ISO markets has improved and that it is
appropriate to update the presumption for smaller production
facilities. As we did in Order No. 688, we have looked to indicia in
other orders to determine where the presumption should be set.
630. We find that at this time, market rules are inclusive of power
producers below 20 MW participating in markets. For example, since the
issuance of Order No. 688, the Commission has required public utilities
to increase the availability of a Fast-Track interconnection process
for projects up to 5 MW.\964\ That the Commission chose a 5 MW cut-off
for eligibility for the fast-track procedures represents an implicit
judgment by the Commission that facilities larger than 5 MW do not need
such procedures to be able to interconnect to the grid.
---------------------------------------------------------------------------
\964\ Order No. 792, 145 FERC ] 61,159, at P 103, clarified,
Order No. 792-A, 146 FERC ] 61,214.
---------------------------------------------------------------------------
631. While the existence of Fast-Track interconnection processes
does not on its own demonstrate nondiscriminatory access for resources
under 20 MW, it does indicate that entities smaller than 20 MW have
access to the market. Presuming that QFs above 5 MW have such access is
therefore a reasonable approach to identifying a capacity level at
which to update the rebuttable presumption of nondiscriminatory market
access.
632. Additionally, since the issuance of Order No. 688 the
Commission has required each RTO/ISO to update its tariff to include a
participation model for electric storage resources that established a
minimum size requirement for participation in the RTO/ISO markets that
does not exceed 100 kW.\965\ These proposals require RTO/ISOs to revise
their tariffs to provide easier access for smaller resources. Requiring
markets to accommodate storage resources to as low as 100 kW also
supports that resources smaller than 20 MW have nondiscriminatory
access to those RTO/ISO markets. The Commission believes that these
developments support updating the 20 MW presumption to a lower number.
---------------------------------------------------------------------------
\965\ Order No. 841, 162 FERC ] 61,127 at P 265.
---------------------------------------------------------------------------
633. Commenters argue that individually each of these changes in
circumstances, standing alone, may not support the reduction of the
threshold below 20 MW. But when the changes are viewed together, we
find that their cumulative effect demonstrates that it is reasonable
for the Commission to maintain a small entity rule but update its
determination of what is a small entity under this presumption under
the PURPA regulations. Additionally, the prospect of increased
participation of distributed energy resources in energy markets further
supports the proposition that wholesale markets are accommodating
resources with smaller capacities.\966\
---------------------------------------------------------------------------
\966\ See, e.g., Elec. Participation in Mkts Operated by Reg'l
Transmission Orgs and Independent Sys. Operators, 157 FERC ] 61,121,
P 129 (2016) (``The costs of distributed energy resources have
decreased significantly, which when paired with alternative revenue
streams and innovative financing solutions, is increasing these
resources' potential to compete in and deliver value to the
organized wholesale electric markets.'' (footnote omitted)).]
---------------------------------------------------------------------------
634. The Commission recognizes that certain of these precedents
would support reducing the presumption below 5 MW, and perhaps even
lower than 1 MW. However, the Commission has carefully considered the
comments detailing the problems that QFs have had in participating in
RTO/ISO markets, problems that necessarily are more acute for smaller
QFs at or near the 1 MW threshold proposed in the NOPR.\967\ The
Commission therefore has determined that a 5 MW is a more reasonable
threshold of non-discriminatory access to RTO/ISO markets.
---------------------------------------------------------------------------
\967\ See, e.g., Allco Comments at 17-19; Advanced Energy
Economy Comments at 10-11; DC Commission Comments at 5; Public
Interest Organizations Comments at 89-90; SEIA Comments at 45-49.
---------------------------------------------------------------------------
635. Based on the foregoing, we find it reasonable to update the
presumption under these regulations as to what constitutes a small
entity that has non-discriminatory access to RTO/ISO markets and
markets of comparable competitive quality below 20 MW, and that 5 MW
represents a reasonable new threshold that accounts for the change of
circumstances indicating that 20 MW no longer is appropriate but also
accommodates commenters' concerns that a 1 MW threshold would be too
low. We acknowledge that ``there is no unique and distinct megawatt
size that uniquely determines if a generator is small.'' \968\ We find
that a 5 MW threshold accords with PURPA's mandate to encourage small
power production facilities, recognizes the progress made in wholesale
markets as discussed above, and balances the competing claims of those
seeking a lower threshold and those seeking a higher threshold.
---------------------------------------------------------------------------
\968\ Order No. 688-A, 119 FERC ] 61,305 at P 97.
---------------------------------------------------------------------------
636. Individual small power production QFs that are over 5 MW and
less than 20 MW can seek to make the case, however, that they do not
truly have nondiscriminatory access to a market and should still be
entitled to a mandatory purchase obligation.
637. Regarding Advanced Energy Economy's argument that the
Commission failed to sufficiently justify its change in policy, we
disagree.\969\ In FCC v. Fox Television, the court stated that, when an
agency makes a change in policy, the agency must show that there are
good reasons for the change, ``[b]ut it need not demonstrate to a
court's satisfaction that the reasons for the new policy are better
than the reasons for the old one; it suffices that the new policy is
permissible under the statute, that there are good reasons for it, and
that the agency believes it to be better, which the conscious change of
course adequately indicates.'' \970\
---------------------------------------------------------------------------
\969\ Advanced Energy Economy Comments at 6 (citing FCC v. Fox
Television, 556 U.S. at 515).
\970\ FCC v. Fox Television, 556 U.S. at 515.
---------------------------------------------------------------------------
638. To be clear, we are maintaining our determination from Order
No. 688 that small entities potentially may not have non-discriminatory
access for purposes of PURPA section 210(m). However, as explained
above, the Commission has determined that using 20 MW as an indicator
of what constitutes a small entity is no longer valid. Entities below
20 MW increasingly have access to the markets, become familiar with
practices and procedures, and that markets have since
[[Page 54717]]
implemented several changes to provide easier access to smaller
facilities, including small power production QFs, storage facilities,
and distributed energy resources. These changes demonstrate a change in
facts since the time we issued Order No. 688 which supports our
updating of what constitutes a small entity for purposes of PURPA
section 210(m).
639. Accordingly, we decline to adopt Ohio Consumers Counsel's
suggestion that electric utilities continue to have the burden to
demonstrate that certain small power production QFs under 20 MW have
nondiscriminatory access to markets like PJM before being relieved of
the mandatory purchase obligation for such QFs.
640. While we find that it is reasonable to update the rebuttable
presumption from 20 MW to 5 MW, we recognize commenters' concerns
regarding specific barriers to participation in RTO markets that may
affect the nondiscriminatory access to those markets of some individual
small power production facilities between 5 MW and 20 MW.
To address these concerns, we additionally are revising 18 CFR
292.309(c)(2)(i)-(vi) to include factors that small power production
facilities between 5 MW and 20 MW can point to in seeking to rebut the
presumption that they have nondiscriminatory access. These factors are
in addition to the existing ability, pursuant to 18 CFR 292.309(c), to
rebut the presumption of access to the market by demonstrating, inter
alia, operational characteristics or transmission constraints.
641. Specifically, the Commission adds to 18 CFR 292.309(c) the
following five factors: (1) Specific barriers to connecting to the
interstate transmission grid, such as excessively high costs and
pancaked delivery rates; (2) the unique circumstances impacting the
time/length of interconnection studies/queue to process small power QF
interconnection requests; (3) a lack of affiliation with entities that
participate in RTO/ISO markets; (4) a predominant purpose other than
selling electricity which would warrant the small power QF being
treated similarly to cogenerators (e.g., municipal solid waste
facilities, biogas facilities, run-of-river hydro facilities, and non-
powered dams); (5) the QF has certain operational characteristics that
effectively prevent the qualifying facility's participation in a
market; and (6) the QF lacks access to markets due to transmission
constraints, including that it is located in an area where persistent
transmission constraints in effect cause the QF not to have access to
markets outside a persistently congested area to sell the QF output or
capacity. This is not intended to be an exhaustive list of the factors
that a QF could rely upon in seeking to rebut the presumption. These
factors, among other indicia of lack of nondiscriminatory access, will
be assessed by the Commission on a case-by-case basis in considering a
claim that the presumption of nondiscriminatory access to the defined
markets should be considered rebutted for a specific QF.
642. The addition of these factors addresses commenters' concern
that not all small power production facilities between 5 and 20 MW may
have nondiscriminatory access to competitive markets, and facilitates
the ability of small power production facilities facing barriers to
participation in RTO markets to demonstrate their lack of access. For
example, while a small power production facility between 5 MW and 20 MW
does not need to be physically interconnected to transmission
facilities to be considered as having access to the statutorily-defined
wholesale electricity markets, we recognize there are some small power
production facilities between 5 MW and 20 MW that may face additional
barriers, such as excessively high costs and pancaked delivery rates,
to access wholesale markets.
643. For example, several commenters express concern over the
resources or administrative burden for some small power QFs that lack
the necessary experience or expertise to participate in energy markets.
Recognizing these concerns, we have added consideration of both the
fact that some small power production facilities will face additional
difficulties due to costs, administrative burdens, length of the
interconnection study process and the size of the queues, and the fact
that some small power production QFs do not have access to the
expertise of affiliated entities.
644. We agree with commenters that some small power production
facilities are similar to cogeneration facilities because their
predominant purpose is not power production. Like cogeneration
facilities, the sale of electricity from these small power production
facilities is a byproduct of another purpose and these facilities might
not be as familiar with energy markets and the technical requirements
for such sales. Therefore, we will allow the small subset of small
power production facilities that are between 20 MW and 5 MW to rebut
the presumption of access to markets where the predominant purpose of
the facility is other than selling electricity, and the sale of
electricity is simply a byproduct of that purpose. Finally, like all
QFs over 20 MW, we recognize that there may be particular small power
production facilities with certain operational characteristics or that
are located in an area where persistent transmission constraints in
effect cause the QF not to have access to markets outside a
persistently congested area to sell the QF output or capacity.
645. While we appreciate Indiana Municipals' concern over
preserving Commission resources, we will deny its request to
automatically apply the lower threshold to utilities that have already
been granted termination for QFs over the 20 MW threshold. We find that
it is appropriate to require utilities that were previously granted
termination of the mandatory purchase obligation for new contracts and
obligations for QFs above 20 MW, but are now seeking to terminate the
mandatory purchase obligation for new contracts and obligations for
small power production facilities between 5 and 20 MW to follow the
procedures in 18 CFR 292.310, including procedures for providing notice
to those potentially affected QFs within their footprint. That is,
those utilities for which the Commission has already granted relief
from the mandatory purchase obligation for small power production
facilities over 20 MW must reapply with the Commission requesting
relief from the mandatory purchase obligation for small power
production facilities between 5 MW and 20 MW.
646. Among other factors, the regulation's notice provision
mentioned above will allow small power production facilities between 5
MW and 20 MW an opportunity, if applicable, to present evidence that
their facility does not have nondiscriminatory access to defined
markets based on the factors discussed above.\971\ In the proceeding in
which the utility seeks to terminate the mandatory purchase obligation
between 5 MW and 20 MW, we will not entertain arguments that the
utility should lose its previously granted termination of purchase
obligation at 20 MW and above; our regulations provide how a mandatory
purchase obligation can be reinstated. We do not, in this final rule,
change a QF's right to seek reinstatement of the mandatory purchase
obligation where the conditions set forth in 18 CFR 292.309(a), (b), or
(c) are no longer met.\972\
---------------------------------------------------------------------------
\971\ 18 CFR 292.310.
\972\ See 18 CFR 292.311.
---------------------------------------------------------------------------
647. Regarding the Michigan Commission's questions, this final rule
[[Page 54718]]
preserves the rights or remedies of any party under existing contracts
or obligations, in effect or pending approval before the appropriate
state regulatory authority or non-regulated electric utility on or
before December 31, 2020 with QFs between 5 MW and 20 MW. Consistent
with Commission precedent, this final rule defines the term
``obligations'' broadly to encompass any existing legally enforceable
obligation.\973\
---------------------------------------------------------------------------
\973\ See Cedar Creek Wind LLC, 137 FERC ] 61,006, at PP 35-36
n.62 (2011) (stating that courts have recognized negotiations
regarding terms that parties to the negotiations intend to become
finalized or written contract, may in some circumstances result in
legally enforceable obligations on those parties notwithstanding the
absence of a writing). See generally Burbach Broadcasting Co. of
Delaware v. Elkins Radio Corp., 278 F.3d 401, 407-09 (4th Cir.
2002); Adjustrite Systems, Inc. v. GAB Business Serv., Inc., 145
F.3d 543, 550 (2d Cir. 1998); Miller Constr. Co. v. Stresstek, 697
P.2d 1201, 1202-04 (Idaho 1985).); see also JD Wind 1, LLC, 129 FERC
] 61,148 at P 25; Grouse Creek Wind Park, LLC, 142 FERC ] 61,187 at
PP 40-41.
---------------------------------------------------------------------------
2. Reliance on RFPs and Liquid Market Hubs To Terminate Purchase
Obligation Under PURPA Section 210(m)
a. NOPR Discussion
648. In the NOPR, the Commission noted that NARUC had 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).\974\ After
describing generally how such a proposal might be structured, NARUC
suggested 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).'' \975\
---------------------------------------------------------------------------
\974\ NOPR, 168 FERC ] 61,184 at P 131 (citing NARUC
Supplemental Comments, Docket No. AD16-16-000 (filed Oct. 17,
2018)).
\975\ Id., attach. A at 9.
---------------------------------------------------------------------------
649. The Commission stated that, 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).\976\ The Commission further noted that 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).
---------------------------------------------------------------------------
\976\ Id. P 132 (citing 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)).
---------------------------------------------------------------------------
650. The Commission then stated that it believed 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
that it would consider such proposals on a case-by-case basis. Although
the Commission did not propose additional criteria a utility or
utilities may rely on to satisfy PURPA section 210(m)(1)(C), the
Commission sought 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).\977\
---------------------------------------------------------------------------
\977\ Id. P 133.
---------------------------------------------------------------------------
b. Comments
i. Comments in Opposition
651. A few commenters do not support allowing competition to be an
alternative to the mandatory purchase obligation.\978\ ELCON is
concerned that no state competitive procurement is robust enough to
replace avoided capacity costs.\979\ Solar Energy Industries supports
using RFPs to set avoided cost rates, but does not support using RFPs
to vitiate utilities' mandatory purchase obligations.\980\
---------------------------------------------------------------------------
\978\ Allco Comments at 17-19; Public Interest Organizations
Comments at 90.
\979\ ELCON Comments at 19.
\980\ Solar Energy Industries Comments at 24 (citing Solar
Energy Industries, Supplemental Comments, Docket No. AD16-16-000, at
10-37, 40-58 (filed Aug. 28, 2019)).
---------------------------------------------------------------------------
652. Public Interest Organizations contend that RFPs are not
comparable in quality to PURPA section 210(m)(1)(A) or (B) markets
because there is only a single buyer and there are no safeguards
against the anti-competitive behavior of that buyer, such as favoring
its own or an affiliate's generation.\981\ NIPPC, CREA, REC, and OSEIA
state that, while they agree in principle that competition should be
the motivating force in energy markets, their experience shows that
utility-sponsored RFP programs often fall far short of genuine
competition.\982\
---------------------------------------------------------------------------
\981\ Public Interest Organizations Comments at 93.
\982\ NIPPC, CREA, REC, and OSEIA Comments at 66.
---------------------------------------------------------------------------
653. Public Interest Organizations state that Order No. 688-A
specifies that demonstrating that a market offers ``a meaningful
opportunity to sell'' usually requires evidence of QF transactions,
which is not possible with a market hub.\983\ Public Interest
Organizations argue that market hubs are not equivalent to PURPA
section 210(m)(1)(A) or (B) markets because, unlike an independently
administered auction, there is no guarantee that a QF will be able to
sell their energy even if it is the lowest cost resource.\984\
---------------------------------------------------------------------------
\983\ Public Interest Organizations Comments at 92 (citing Order
No. 688-A, 119 FERC ] 61,305 at P 38).
\984\ Id.
---------------------------------------------------------------------------
654. Public Interest Organizations further contend that the
Commission does not have the authority to approve RFPs or liquid market
hubs as PURPA section 210(m)(1)(C) wholesale markets because they are
not of comparable qualify to Day 1 or Day 2 markets, i.e., to PURPA
section 210(a)(1)(A) or (B) markets.\985\
---------------------------------------------------------------------------
\985\ Id. at 90-91.
---------------------------------------------------------------------------
ii. Comments in Support
655. Several commenters support allowing competition to be an
alternative to the mandatory purchase obligation.\986\ ELCON supports
competitive procurements that exempt industrial self-supply.\987\
---------------------------------------------------------------------------
\986\ Advanced Energy Economy Comments at 12; APPA Comments at
29; Colorado Independent Energy Comments at 7; Xcel Comments at 11.
\987\ ELCON Comments at 19.
---------------------------------------------------------------------------
656. APPA supports the Commission reviewing factors that would
determine if a market is competitive and comparable to PURPA sections
210(m)(1)(A) and (B).\988\ Xcel proposes that the PURPA section
210(m)(1)(C) test should evaluate whether market players have a
reasonable opportunity to participate in the market, rather than
whether the type of market is similar to PURPA section 210(m)(1)(A) and
(B) markets.\989\ A few commenters requested a technical conference to
identify the criteria for determining what processes are
competitive.\990\ Colorado Independent Energy would like the RFP
standard for PURPA section 210(m)(1)(C) status to be higher than for QF
pricing and include evaluation of bid data and the modeling process to
show the absence of bias against renewable and cogeneration
[[Page 54719]]
projects and likewise the absence of bias for utility self-build
projects.\991\
---------------------------------------------------------------------------
\988\ APPA Comments at 26-29.
\989\ Xcel Comments at 11.
\990\ Advanced Energy Economy Comments at 13; ELCON Comments at
19.
\991\ Colorado Independent Energy Comments at 6, 11-12.
---------------------------------------------------------------------------
657. Arizona Public Service agrees with NARUC that the Commission
should allow utilities to rely on RFPs to establish eligibility to
terminate the utility's purchase obligation pursuant to PURPA section
210(m)(1)(C). Arizona Public Service believes this proposal is one way
a utility could demonstrate that a market is of comparable competitive
quality to the markets described in PURPA sections 210(m)(1)(A) and
(B).\992\
---------------------------------------------------------------------------
\992\ Arizona Public Service Comments at 8-10.
---------------------------------------------------------------------------
658. APPA argues that market hubs should be considered as possibly
comparable, particularly to PURPA section 210(m)(1)(B), which requires
that QFs have access to Commission-approved transmission service and
competitive wholesale markets for long and short-term capacity and
energy sales.\993\ APPA highlights the Commission finding that the Mid-
Columbia and Palo Verde hubs have sufficient liquidity to find just and
reasonable rates and adds that an empirical test of market liquidity
could be created.\994\
---------------------------------------------------------------------------
\993\ APPA Comments at 27.
\994\ Id. at 28.
---------------------------------------------------------------------------
c. Commission Determination
659. In this final rule, we affirm that we will consider utility
proposals to terminate the purchase obligation pursuant to PURPA
section 210(m)(1)(C) on a case-by-case basis, including utility
proposals based on competitive solicitations or liquid market hubs.
660. In response to Public Interest Organizations, as explained
above in Section IV.A.1, PURPA section 210(m) obligates the Commission
to grant any request to terminate a utility's obligation to purchase
from a QF with nondiscriminatory access to the specified markets that
satisfy that provision. Whether any particular market is of comparable
quality to a Day 1 or Day 2 market necessarily must be determined in
the context of an individual case.
661. We refrain from outlining here an exhaustive list of factors
that will be used in any such case-by-case evaluation, but at a minimum
we will be guided by the important criteria discussed previously in
this rule in section IV.B.8 on the use of competitive solicitations to
determine avoided costs.
662. Consistent with our findings and discussion in section IV.B.4
on the use of market hubs to determine avoided cost, the Commission
finds that competitive market prices in general should reflect the
avoided cost energy rates of utilities with access to such markets in a
given region. We will therefore consider, on a case-by-case basis,
whether a properly run RFP or competitive acquisition process may also
justify termination of the PURPA purchase obligation pursuant to PURPA
section 210(m)(1)(C).
H. Legally Enforceable Obligation
1. NOPR Proposal
663. The Commission proposed to add regulatory text in 18 CFR
292.304(d)(3) to require QFs to demonstrate that a proposed project is
commercially viable and that 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 proposed to provide that states have flexibility as
to what constitutes an acceptable showing of commercial viability and
financial commitment.
664. The Commission stated that its objective in requiring a
showing of commercial viability and the QF's financial commitment to
construct the project was 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. The NOPR proposed that
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. The
NOPR stated that these proposed indicia were not intended to be
exhaustive and the Commission sought comment on these indicia and
others that also might be appropriate for consideration.
665. The Commission stated that it believed requiring QFs to
demonstrate their commercial viability and financial commitment to
construct the facilities based on such indicia before obtaining a LEO
would allow electric utilities to reliably plan their systems while
ensuring resource adequacy. Additionally, the development and
definition of objective and reasonable factors to determine commercial
viability and financial commitment to construct a facility would
encourage the development of QFs by providing QFs with more certainty
as to when they will obtain a LEO.\995\
---------------------------------------------------------------------------
\995\ Because QFs already in operation have necessarily
demonstrated a commitment to construct the project, the Commission
stated that it 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.
---------------------------------------------------------------------------
2. Comments
a. Comments in Opposition
666. Several commenters oppose the Commission's proposal 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 and that states have flexibility as to what
constitutes an acceptable showing of commercial viability and financial
commitment, arguing it undermines PURPA's intent to promote QF
development.\996\
---------------------------------------------------------------------------
\996\ NIPPC, CREA, REC, and OSEIA Comments at 81; Public
Interest Organizations Comments at 98; Western Resource Councils
Comments at 144.
---------------------------------------------------------------------------
667. NIPPC, CREA, REC, and OSEIA argue that developers cannot
obtain financing without the financial commitment of a PPA or LEO from
the utility and therefore requiring financial viability as a condition
precedent to obtain a LEO is problematic.\997\ Western Resource
Councils argues that the NOPR proposal represents an onerous financial
and bureaucratic barrier that will lead to a substantial reduction in
the number of QFs.\998\
---------------------------------------------------------------------------
\997\ NIPPC, CREA, REC, and OSEIA Comments at 81.
\998\ Western Resource Councils Comments at 144.
---------------------------------------------------------------------------
668. Southeast Public Interest Organizations argue that the
proposal does not sufficiently narrow the range of divergent LEO tests
that have already been adopted by the states and opposes allowing
states additional flexibility in establishing criteria up to a fully
executed agreement.\999\ sPower requests that the Commission establish
specific criteria and prohibit states from imposing any additional
criteria.\1000\ Solar Energy Industries requests that the Commission
develop a concrete baseline
[[Page 54720]]
in determining when a QF is entitled to a purchase contract.
---------------------------------------------------------------------------
\999\ Southeast Public Interest Organizations Comments at 43
\1000\ sPower Comments at 14.
---------------------------------------------------------------------------
669. Solar Energy Industries and Public Interest Organizations
argue that requiring developers to invest additional capital prior to
obtaining a LEO will prevent smaller companies who are unable to invest
heavily in early state development activity from participating.\1001\
Solar Energy Industries argue that it is unjust and unreasonable to
require QFs to invest millions of dollars in site control, permit
acquisition and interconnection costs in order to secure the
opportunity to negotiate with the purchasing utility. For those states
that do not willingly disclose their avoided cost rates or methodology,
the NOPR's LEO proposal requires QFs to incur substantial expense to
establish their commercial viability without a reasonable understanding
of what their rate may be.\1002\
---------------------------------------------------------------------------
\1001\ Solar Energy Industries Comments at 41; Public Interest
Organization Comments at 80-82.
\1002\ Solar Energy Industries Comments at 41.
---------------------------------------------------------------------------
670. In striking a balance between interconnection and development
risk, Solar Energy Industries proposes that the first prerequisite to a
LEO formation be either: (a) The completion of the System Impact Study
(or the equivalent in the state interconnection process); or (b) where
the utility cannot complete the System Impact Study within a reasonable
period of time, one year after tendering an interconnection request to
the host utility.\1003\ Where a QF has obtained site control, initiated
state permitting processes, submitted an interconnection request and
associated study deposit, and has been certified through the submission
of a Form No. 556, the Commission should find that the QF is eligible
to establish a LEO to sell to the purchasing utility, provided that:
(1) The QF has received a System Impact Study report (or equivalent) or
one year has elapsed since the QF's interconnection request was
tendered to the host utility; and (2) the QF commits to achieving
commercial operation within 180 days of the completion of all
interconnection facilities and network upgrades by the utility.\1004\
Solar Energy Industries asserts that QFs would, upon satisfaction of
these criteria, be legally entitled to negotiate with the purchasing
utility to develop a PPA setting forth the terms and conditions of the
purchase, including liability if the QF fails to perform. Projects that
reach agreement will proceed according to the terms of the PPA and the
purchasing utility can establish milestones with enough financial
protection to ensure that ratepayers will not be harmed if the QF fails
to begin operations.\1005\
---------------------------------------------------------------------------
\1003\ Id. at 43.
\1004\ Id.
\1005\ Id.
---------------------------------------------------------------------------
671. American Dams argues that Interconnection Agreements are
generally processed far too slowly, a problem that should be addressed
by the Commission.\1006\
---------------------------------------------------------------------------
\1006\ American Dams Comments at 5-6.
---------------------------------------------------------------------------
672. Southeast Public Interest Organizations support the
requirement of demonstrating site control, but state that requiring
permits can be time-consuming and costly such that pre-financing QFs
may not have the resources for the lengthy permitting process, and it
is unreasonable to expect a QF to incur these expenses until it has
secured a price for its output so that it can in turn secure financing
for the project.\1007\
---------------------------------------------------------------------------
\1007\ Southeast Public Interest Organization Comments at 43-44.
---------------------------------------------------------------------------
b. Comments in Support
673. Numerous commenters support the NOPR's LEO proposal, asserting
that state agencies are better positioned to develop criteria that
reflect their unique operational circumstances, resource planning needs
and risk appetite.\1008\ Several commenters note that the proposed
factors provide a reasonable balance between the planning needs of the
connecting utility and certainty to QF developers.\1009\ Several
commenters assert that requiring QFs to demonstrate commercial
viability and financial commitment will reduce the reliability or other
risks a utility faces by having to plan for its system needs or
resource adequacy around a QF that is never developed.\1010\
---------------------------------------------------------------------------
\1008\ Alaska Power Comments at 1-2; APPA Comments at 30;
Chamber of Commerce at 8; Colorado Independent Energy Comments at
13; Connecticut Authority Comments at 24-25; Consumer Alliance
Comments at 2; Consumers Energy Comments at 5; East Kentucky
Comments at 3-4; East River at 2; El Paso Electric Comments at 6-7;
Golden Valley Comments at 7-8; Indiana Municipal Comments at 11-12;
Institute for Energy Research Comments at 2; Massachusetts DPU
Comments at 10; NARUC Comments at 7-8; NIPPC, CREA, REC, and OSEIA
Comments at 81; NRECA Comments at 21; North Carolina Commission
Staff Comments at 6; Northern Laramie Range Alliance Comments at 3-
4; Ohio Commission Energy Advocate Comments at 10; Oregon Commission
at 6.
\1009\ Alliant Energy Comments at 21; Industrial Energy
Consumers Comments at 14-16.
\1010\ Duke Energy Comments at 19; EEI Comments at 37.
---------------------------------------------------------------------------
674. Several commenters agree that the proposed regulations will
provide certainty to host utilities and state commissions while
decreasing systems impact and associated costs.\1011\
---------------------------------------------------------------------------
\1011\ Alliant Energy Comments at 21-22; NRECA at 21; Northern
Laramie Range Alliance Comments at 3-4.
---------------------------------------------------------------------------
675. Connecticut Authority supports the proposal arguing that the
factors included in the NOPR will provide greater certainty and less
risk to QF developers and purchasing utilities which is consistent with
PURPA's goal of developing renewable resources.\1012\ The Chamber of
Commerce argues that the proposed factors indicate a developer's good-
faith intention to ultimately develop its proposed QF.\1013\ The
Michigan Commission states that it supports the proposal, currently has
a rulemaking and several cases pending regarding LEOs, and appreciates
any additional clarity the Commission could provide.\1014\
---------------------------------------------------------------------------
\1012\ Connecticut Authority Comments at 24-25.
\1013\ Chamber of Commerce Comments at 8.
\1014\ Michigan Commission Comments at 7-8.
---------------------------------------------------------------------------
c. Comments Requesting Modification
676. NIPPC, CREA, REC, and OSEIA request that the Commission: (1)
Further define the terms ``commercial viability'' and ``financial
commitment'' to avoid litigation; (2) clarify that any changes to the
LEO rules will not affect the viability of any executed contract
between a developer and utility, regardless of the facility's
development status; and (3) clarify that the LEO rules will not
preclude nor bar any utility from executing a PPA before the QF may be
able to demonstrate compliance with the implementation of LEO
rules.\1015\
---------------------------------------------------------------------------
\1015\ NIPPC, CREA, REC, and OSEIA Comments at 81-83.
---------------------------------------------------------------------------
i. Studies
677. NorthWestern requests that the Commission require more than
just the submission of an interconnection application prior to
obtaining a LEO in order to demonstrate that the proposal is more than
a speculative paper project.\1016\ Portland General requests that the
Commission allow states to require developers to have completed the
first interconnection study.\1017\ The South Dakota Commission states
that developers should be required to have completed a transmission
feasibility study or system impact study with a determination of the
interconnection costs the QF would be required to pay prior to
obtaining a LEO.\1018\ Portland General requests that off-system QFs be
required to have completed the first study milestone of the
transmission service request.\1019\
---------------------------------------------------------------------------
\1016\ NorthWestern Comments at 15-16.
\1017\ Portland General Comments at 20.
\1018\ South Dakota Commission Comments at 2.
\1019\ Portland General Comments at 20.
---------------------------------------------------------------------------
678. SC Solar Alliance requests that the Commission adopt a recent
South Carolina Commission ruling that a QF should be able to establish
a LEO after
[[Page 54721]]
receiving a System Impact Study or within one year if a System Impact
Study is not provided in a timely manner and that PPA in-service dates
must be extended based on interconnection delays.\1020\
---------------------------------------------------------------------------
\1020\ SC Solar Alliance Comments at 15.
---------------------------------------------------------------------------
ii. Commercial Viability
679. Alliant Energy requests that the Commission consider requiring
QF developers to have contracts in place with equipment suppliers and
an analysis of interconnections needed.\1021\
---------------------------------------------------------------------------
\1021\ Alliant Energy Comments at 22.
---------------------------------------------------------------------------
680. North Carolina Commission Staff requests that the Commission
adopt a North Carolina Commission standard that QFs must (1) commit to
sell their power via a written notice of commitment by the earlier of
105 days after submission of an interconnection request or upon receipt
of the system impact study, (2) have filed a report of proposed
construction, and (3) submitted an interconnection request under the
state's interconnection protocol which requires the QF to demonstrate
site control.\1022\ sPower argues that option contracts should be
sufficient to demonstrate site control.\1023\
---------------------------------------------------------------------------
\1022\ North Carolina Commission Staff Comments at 6.
\1023\ sPower Comments at 15.
---------------------------------------------------------------------------
iii. Financial Viability
681. Portland General and sPower suggest requiring developers to
pay a deposit to state commissions to demonstrate financial viability
with the amount based on the capacity of the QF and released upon
project completion.\1024\ Portland General asserts that having to post
a deposit encourages developers to perform sufficient due diligence
prior to claiming a LEO.\1025\
---------------------------------------------------------------------------
\1024\ Portland General Comments at 15-16; sPower Comments at
14-15.
\1025\ Portland General Comments at 20-21.
---------------------------------------------------------------------------
682. North Carolina Commission Staff argues that, in order to
protect ratepayers from QFs gaming the process, any project that backs
out of its notice of commitment should only receive as-available rates
for two years.\1026\
---------------------------------------------------------------------------
\1026\ North Carolina Commission Staff Comments at 6.
---------------------------------------------------------------------------
iv. Rejecting QF Purchases and Expanded Curtailment Rights
683. North Carolina Commission Staff suggests that the Commission
update its regulations to allow curtailing QFs when it would be
uneconomic for the utility to make such purchases.\1027\ The Institute
for Energy Research argues that the Commission should allow a utility
to reject purchases from QFs if the utility has no need for additional
capacity. The Institute for Energy Research states that such need could
be determined separately, on an annual basis, a stand-alone basis, or
as part of an IRP process.\1028\
---------------------------------------------------------------------------
\1027\ Id. at 8.
\1028\ Institute for Energy Research Comments at 2-3.
---------------------------------------------------------------------------
3. Commission Determination
684. In this final rule, we adopt the NOPR proposal to require QFs
to demonstrate that a proposed project is commercially viable and that
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.\1029\ We also affirm that the states have
flexibility as to what constitutes an acceptable showing of commercial
viability and financial commitment, albeit subject to the criteria
being objective and reasonable. We find that requiring a showing of
commercial viability and financial commitment, based on objective and
reasonable criteria, will 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. At the same time,
the criteria ensure that the purchasing utility does not unilaterally
and unreasonably decide when its obligation arises. We believe this
strikes the right balance for QF developers and purchasing utilities
and should encourage development of QFs.
---------------------------------------------------------------------------
\1029\ NOPR, 168 FERC ] 61,184 at P 140.
---------------------------------------------------------------------------
685. Examples of factors a state could reasonably require are that
a QF demonstrate that it is in the process of at least some of the
following prerequisites: (1) Taking meaningful steps to obtain site
control adequate to commence construction of the project at the
proposed location and (2) filing an interconnection application with
the appropriate entity. The state could also require that the QF show
that it has submitted all applications, including filing fees, to
obtain all necessary local permitting and zoning approvals. We note
that the factors that the state requires must be factors that are
within the control of the QF. Thus, we clarify that it is appropriate
for states to require a QF to demonstrate that it is in the process of
obtaining site control or has applied for all local permitting and
zoning approvals, rather than requiring a QF to show that it has
obtained site control or secured local permitting and zoning.
686. We agree with Southeast Public Interest Organizations'
concerns regarding requiring QFs to obtain permits in order to
determine commercial viability. In some regions the permitting and
zoning process can be lengthy and expensive, making obtaining the
permits and zoning changes a condition to a LEO unreasonable.
Therefore, instead of requiring a QF to have secured local permitting
and zoning, states can require QFs to have applied for all of the
necessary permits and zoning variances, including the payment of all
necessary fees, as a factor in demonstrating the QF's commercial
viability. States may require a showing that such applications have
been submitted to the relevant regulatory bodies (including payment of
the application fees).
687. Several commenters argue that requiring QFs to demonstrate
financial viability prior to obtaining a LEO is problematic because QFs
need a LEO to obtain financing.\1030\ However, demonstrating the
required financial commitment does not require a demonstration of
having obtained financing. Requiring QFs to, for example, apply for all
relevant permits, take meaningful steps to seek site control, or meet
other objective and reasonable milestones in the QF's development can
sufficiently demonstrate QF developers' financial commitment in the QF
development and allows utilities to reasonably rely on the LEO in
planning for system resource adequacy. Obtaining a PPA or financing
cannot be required to show proof of financial commitment.
---------------------------------------------------------------------------
\1030\ NIPPC, CREA, REC, and OSEIA Comments at 81; Western
Resource Council Comments at 144.
---------------------------------------------------------------------------
688. The intent of these factors is to provide a reasonable balance
between providing QFs with objective and transparent milestones up
front that are needed to obtain a LEO, allowing states the flexibility
to establish factors that address the individual circumstances of each
state, and increasing utilities' ability to accurately plan their
systems.\1031\ Establishing objective and reasonable factors is
intended to limit the number of unviable QFs obtaining LEOs and
unnecessarily burdening utilities that currently have to plan for QFs
that obtain a LEO very early in the process but ultimately are never
developed.\1032\ In adopting this provision, the Commission is raising
the bar to prevent speculative QFs from obtaining LEOs, and the
associated burden on purchasing utilities, but is
[[Page 54722]]
not establishing a barrier for financially committed developers seeking
to develop commercially viable QFs.
---------------------------------------------------------------------------
\1031\ Alliant Energy Comments at 21; Industrial Energy
Consumers Comments at 14-16.
\1032\ Duke Energy Comments at 19; EEI Comments at 37.
---------------------------------------------------------------------------
689. We disagree that establishing reasonable, transparent factors
is an onerous barrier or will cause a substantial reduction of QFs. The
objective and reasonable criteria we have established will protect QFs
against onerous requirements for a LEO that hinder financing, such as a
requirement for a utility's execution of an interconnection agreement
\1033\ or power purchase agreement,\1034\ or requiring that QFs file a
formal complaint with the state commission,\1035\ or limiting LEOs to
only those QFs capable of supplying firm power,\1036\ or requiring the
QF to be able to deliver power in 90 days.\1037\ We find that, by
making clear that such conditions are not permitted, and by providing
objective criteria to clarify when a LEO commences, the LEO provisions
we have adopted will encourage the development of QFs.
---------------------------------------------------------------------------
\1033\ See, e.g., FLS Energy, Inc., 157 FERC ] 61,211, at P 26
(2016) (FLS) (stating that requiring signed interconnection
agreement as prerequisite to LEO is inconsistent with PURPA
Regulations).
\1034\ See, e.g., 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 LEO is inconsistent
with PURPA Regulations.
\1035\ See, e.g., Grouse Creek Wind Park, LLC, 142 FERC ]
61,187, at P 40 (2013).
\1036\ Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380, 400 (5th
Cir. 2014).
\1037\ Power Resource Group, Inc. v. Public Utility Com'n of
Texas, 422 F.3d 231, (5th Cir. 2005).
---------------------------------------------------------------------------
690. For those commenters that requested that the Commission
establish specific factors for the states to apply, or to establish a
baseline for eligible factors, or to otherwise limit states'
flexibility, we decline to do so. Since its inception, the Commission's
PURPA Regulations have established rules and defined boundaries
allowing states flexibility within those boundaries in implementing
PURPA as appropriate for each state. As commenters noted, this allows
states to address their unique circumstances and best address each
states' needs. Furthermore, existing precedent establishes a baseline
\1038\ and this final rule's requirement that states adopt objective
and reasonable criteria for determining when a QF has obtained a LEO
provides additional safeguards (in addition to that baseline)
applicable to both QFs and utilities. Similarly, regarding Solar Energy
Industries' proposed pre-requisites and factors, for the reasons stated
above, we find that states are in the best position to determine what
specific factors would best suit the specific circumstances of that
state, so long as they are objective and reasonable, and we provide the
suggested prerequisites above as examples of objective and reasonable
factors.\1039\ While Solar Energy Industries' proposed criteria may be
reasonable, we decline to mandate specific terms for the entire
country.
---------------------------------------------------------------------------
\1038\ For example, 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.
See FLS, 157 FERC ] 61,211 at P 26; Cedar Creek Wind LLC, 137 FERC ]
61,006 at P 35.
\1039\ See supra P 685.
---------------------------------------------------------------------------
691. Contrary to Solar Energy Industries' assertions, nothing in
this final rule limits a QF developer's or utility's ability to
negotiate rates, terms or conditions.\1040\
---------------------------------------------------------------------------
\1040\ See 18 CFR 292.301(b).
---------------------------------------------------------------------------
692. With regard to the argument that the NOPR's LEO proposal is
unreasonable in states that do not disclose their avoided cost rate
because it would require QFs to incur substantial expense to establish
commercial viability without a reasonable understanding of the purchase
rate, we find that such state-specific implementation issues can be
addressed case-by-case. To the extent that entities believe that a
particular state's avoided cost rates or rate setting methodologies do
not provide sufficient transparency to support a QF's ability to make
reasonable commercial viability investment decisions, such entities
could file a petition for enforcement against the state at the
Commission and, if the Commission declines to act, later file a
petition against the state in U.S. district court (pursuant to PURPA
section 210(h)(2)(B)).
693. NIPPC, CREA, REC, and OSEIA request that we further define the
terms commercial viability and financial commitment. We decline. As
discussed above, we believe the best course is to allow states the
flexibility (employing objective and reasonable factors) to determine
what constitutes commercial viability and financial commitment relative
to the unique conditions or circumstances in each state but also
recognizing that existing Commission precedent establishes boundaries
of what would be considered reasonable and not discriminatory limits
for requirements in establishing a LEO.\1041\
---------------------------------------------------------------------------
\1041\ See FLS, 157 FERC ] 61,211 at P 26; Cedar Creek Wind LLC,
137 FERC ] 61,006 at P 35.
---------------------------------------------------------------------------
694. Additionally, we clarify that any changes to the LEO rules
adopted herein do not affect the viability of any executed contract or
LEO between a QF developer and utility in place as of the effective
date of this final rule, regardless of the facility's development
status. Further we clarify that nothing in the LEO rules adopted herein
precludes any utility from choosing to execute a PPA before a QF has
demonstrated compliance with the LEO rules adopted here.
Several commenters requested that the Commission require QFs to do
more than just file an interconnection application; instead, for
example, suggesting requiring completion of system impact study,
interconnection or transmission feasibility study.\1042\ We disagree.
The approach taken here recognizes the need for a QF to demonstrate
that its project is more than mere speculation, such that it is
reasonable for a utility to consider the resource in its planning
projections. A QF that has submitted an application for
interconnection, as well as having taken meaningful steps to obtain
site control and has applied for all relevant permits, while not a
guarantee that the project will be completed, are all objective and
reasonable indicators that the QF developer is seriously pursuing the
project and has spent time and resources in developing the project to
show a financial commitment. As numerous commenters have explained, QFs
need a LEO in order to obtain financing to complete the project, and we
find that, as an illustrative example, requiring the submission of an
interconnection request (as opposed to the completion of a system
impact study or transmission feasibility study) as one criteria strikes
an appropriate balance between the competing needs.
---------------------------------------------------------------------------
\1042\ NorthWestern Comments at 15-16, Portland General Comments
at 20, South Dakota Commission Comments at 2.
---------------------------------------------------------------------------
695. Moreover, it bears remembering that the concept of a LEO was
specifically adopted to prevent utilities from circumventing the
mandatory purchase requirement under PURPA by refusing to enter into
contracts.\1043\ The Commission thus has found that requiring a QF to
have a utility-executed contract or interconnection agreement, or
requiring the completion of a utility-controlled study places too much
control over the LEO in the hands of the utility and defeats the
purpose of a LEO and is inconsistent with PURPA.\1044\ When reviewing
factors to demonstrate commercial viability and financial commitment,
states thus should place emphasis on those factors that show that the
QF has taken meaningful steps to
[[Page 54723]]
develop the QF that are within the QF's control to complete, and not on
those factors that a utility controls. For example, requiring a QF to
make a deposit as Portland General and sPower proposed or whether the
QF has applied for system impact, interconnection or other needed
studies are the types of factors that may show that the QF has taken
meaningful steps to develop the QF that are within the QF's control and
the type of objective and reasonable standards that states can consider
in their implementation.\1045\
---------------------------------------------------------------------------
\1043\ JD Wind 1, LLC, 129 FERC ] 61,148 at P 25, reh'g denied,
130 FERC ] 61,127 (citing Order No. 69 FERC Stats. & Regs. ] 30,128
at 30,880; see also Midwest Renewable Energy Projects, LLC, 116 FERC
] 61,017 (2006).
\1044\ FLS, 157 FERC ] 61,211 at P 23 (finding such requirements
``allows a utility to control whether and when a legally enforceable
obligation exists--e.g. by delaying the facilities study.'').
\1045\ Portland General Comments at 15-16; sPower Comments at
14-15.
---------------------------------------------------------------------------
696. Requests by parties to expand utilities' rights to curtail QF
sales are outside the scope of this proceeding. Additionally, requests
to allow a utility to reject purchases from QFs if a utility has no
need for additional capacity are outside the scope of this proceeding.
V. Information Collection Statement
697. The Paperwork Reduction Act \1046\ 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 10 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).\1047\ 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.
---------------------------------------------------------------------------
\1046\ 44 U.S.C. 3501-21.
\1047\ See 5 CFR 1320.11.
---------------------------------------------------------------------------
Public Reporting Burden: The Commission is revising its regulations
implementing PURPA. At the Notice of Proposed Rulemaking (NOPR) stage,
the Commission stated the principal changes that affect information
collection involved the FERC Form No. 556.\1048\ In response to
comments arguing that the NOPR proposals would cause additional
reporting burdens, in this final rule we have analyzed whether there
are additional incremental reporting burdens that result from other
aspects of this final rule. As described further below, we find that
there is one additional potential reporting burden arising from this
final rule. It relates to reducing the PURPA section 210(m) rebuttable
presumption regarding small power production QFs' nondiscriminatory
access to certain markets from 20 MW to 5 MW. Specifically, this
reporting burden would arise from electric utilities located in markets
who choose to submit to the Commission a PURPA section 210(m) petition
for termination of the PURPA mandatory purchase obligation (affecting
information collection FERC-912) for small power production QFs between
20 MW and 5 MW.
---------------------------------------------------------------------------
\1048\ The change to the FERC-556 described by the NOPR was
submitted under a temporary interim information collection no.,
FERC-556A (OMB Control No. 1902-0316) because another item for FERC-
556 was pending OMB review at the time and only one item per OMB
Control No. can be pending OMB review at a time. The final rule is
being submitted to OMB under FERC-556.
---------------------------------------------------------------------------
698. With respect to the FERC Form No. 556, the Commission affirms
that the relevant burdens derive from the change from the Commission's
current ``one-mile rule'' for determining whether generation facilities
should be considered to be at the same site for purposes of determining
qualification as a qualifying small power production facility, to
allowing an interested person or other entity challenging a QF
certification the opportunity to file a protest, without a fee, to
rebut the presumption that affiliated small power production QFs using
the same energy resource and located more than one mile and less than
10 miles from the applicant facility are considered to be at separate
sites.
Specifically, as more fully explained in section IV.F above, and as
demonstrated by the revised Form No. 556 attached to this final rule
(but not published in the Federal Register or Code of Federal
Regulations),\1049\ the Commission makes the following changes to the
FERC Form No. 556 which affect the burden of the information
collection:
---------------------------------------------------------------------------
\1049\ The Form 556 and instructions will be available in the
Commission's eLibrary.
---------------------------------------------------------------------------
Allow an interested person or other entity challenging a
QF certification the opportunity to file a protest, without a fee, to
an initial certification (both self-certification and application for
Commission certification) filed on or after the effective date of this
final rule, or to a recertification (self-recertification or
application for Commission recertification) that makes substantive
changes to the existing certification that is filed on or after the
effective date of this final rule.
Require all applicants to report the applicant facility's
geographic coordinates, rather than only for applications where there
is no street address.
Change the current requirement to identify any affiliated
facilities with electrical generating equipment within one mile of the
applicant facility's electrical generating equipment to instead require
applicants to list only affiliated small power production QFs using the
same energy resource one mile or less from the applicant facility.
Additionally require applicants to list affiliated small
power production QFs using the same energy resource whose nearest
electrical generating equipment is greater than one mile and less than
10 miles from the electrical generating equipment of the applicant
facility.
Require the applicant to list the geographic coordinates
of the nearest ``electrical generating equipment'' of both its own
facility and the affiliated small power production QF in question based
on the definitions adopted in this final rule.
Provide space for the applicant to explain, if it chooses
to do so, why the affiliated small power production QFs using the same
energy resource, that are more than one mile and less than 10 miles
from the electrical generating equipment of the applicant facility,
should be considered to be at separate sites from the applicant's
facility, considering the relevant physical and ownership factors
identified in this final rule.
As explained in the body of this final rule, these changes in
burden are appropriate because they are necessary to meet the statutory
requirements contained in PURPA.
699. In this final rule, the Commission is revising its regulations
implementing PURPA, which will affect the information collections for
the FERC Form No. 556 and FERC-912. Below, the first table includes
estimated changes to the burden and cost of the FERC Form No. 556 due
to the final rule. As demonstrated by the table, we believe that QFs
will spend more time to identify any affiliated small power production
QFs that are less than one mile, between one and 10 miles, and more
than 10 miles, apart. The Commission expects that there will be an
increase due to the revisions to the Commission's regulations, and that
the changes to the ``one-mile rule'' and the ability to protest without
a fee will affect self-certifications and applications for Commission
certification.
[[Page 54724]]
FERC-556, Changes Due to Final Rule in Docket Nos. RM19-15-000 and AD16-16-000 \1050\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Increased Increased total
Annual number average burden annual burden Increased
Facility type Filing type Number of of responses Total number of hours and cost hours and total annual cost per
respondents per respondent responses per response annual cost respondent ($)
($) ($)
(1)............. (2)............. (1) * (2) = (3). (4)............ (3) * (4) = (5) (5) / (1 = (6)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cogeneration and Small Power Self- no change (692). no change (1.25) no change (865). no change (1.5 no change 0
Production Facility <= 1 MW certification. hrs.); $0. (1,297.5
\1051\. hrs.); $0.
Cogeneration Facility > 1 MW. Self- no change (63).. no change (1.25) no change no change (1.5 no change 0
certification. (78.75). hrs.); $0. (118.125
hrs.); $0.
Cogeneration Facility > 1 MW. Application for no change (1)... no change (1.25) no change (1.25) no change (50 no change (62.5 0
FERC hrs.); $0. hrs.); $0.
certification.
Small Power Production Self- no change (899) no change (1.25) no change 2 hrs.; $166... 2,247.5 hrs.; 207.5
Facility > 1 MW, <= 1 Mile certification. \1052\. (1,123.75). 186,542.5.
from Affiliated Small Power
Production QF.
Small Power Production Application for no change (0)... no change (1.25) no change (0)... 6 hrs.; $498... no change (0 0
Facility > 1 MW, <= 1 Mile FERC hrs.); $0.
from Affiliated Small Power certification.
Production QF.
Small Power Production Self- no change (900). no change (1.25) no change 8 hrs.; $664... 9,000 hrs.; 830
Facility > 1 MW, > 1 Mile, < certification. (1,125). $747,000.
10 Miles from Affiliated
Small Power Production QF.
Small Power Production Application for no change (0)... no change (1.25) no change (0)... 12 hrs.; $996.. no change (0 0
Facility > 1 MW, > 1 Mile, < FERC hrs.); $0.
10 Miles from Affiliated certification.
Small Power Production QF.
Small Power Production Self- no change (899). no change (1.25) no change 2 hrs.; $166... 2,247.5 hrs.; 207.5
Facility > 1 MW, >= 10 Miles certification. (1,123.75). $186,542.5.
from Affiliated Small Power
Production QF.
Small Power Production Application for no change (0)... no change (1.25) no change (0)... 6 hrs.; $498... no change (0 0
Facility > 1 MW, >= 10 Miles FERC hrs.); $0.
from Affiliated Small Power certification.
Production QF.
--------------------------------------------------------------------------------------------------------------------------
FERC-556, Total ................ no change ................ no change ............... 13,495 hrs.; ...............
Additional Burden and (3,454). (4,317.5). $1,120,085.
Cost Due to Final Rule.
--------------------------------------------------------------------------------------------------------------------------------------------------------
700. The table below reflects the additional estimated public
reporting burdens associated with reducing the PURPA section 210(m)
rebuttable presumption regarding small power production QFs'
nondiscriminatory access to certain markets from 20 MW to 5 MW, which
affects the FERC-912.\1053\ The FERC-912 is optional, but if electric
utilities located in relevant markets choose to submit to the
[[Page 54725]]
Commission a PURPA section 210(m) petition for termination of the PURPA
mandatory purchase obligation for small power production QFs between 20
MW and 5 MW, then we would expect the following burdens and cost
estimates to apply.
---------------------------------------------------------------------------
\1050\ The figures in this table reflect estimated changes to
the current OMB-approved inventory for the FERC Form No. 556
(approved by the Office of Management and Budget (OMB) on November
18, 2019).
Where ``no change'' is indicated, the current figure is included
parenthetically for information only. Those parenthetical figures
are not included in the final total for column 5.
Commission staff believes that the industry is similarly
situated in terms of wages and benefits. Therefore, cost estimates
are based on FERC's 2020 average hourly wage (and benefits) of
$83.00/hour. (The submittal to and approval of OMB in 2019 for FERC
Form No. 556 was based on FERC's 2018 average annual wage hourly
rate of $79.00/hour. Because the change from the $79.00 hourly rate
to the current $83.00 hourly rate was not due to the final rule,
this chart does not depict this increase.)
\1051\ Not required to file.
\1052\ In the FERC Form No. 556 approved by OMB in 2019, for the
category ``Small Power Production Facility > 1 MW, Self-
certification,'' we estimated the number of respondents at 2,698. We
have now divided that category into three categories: ``Small Power
Production Facility > 1 MW, <= 1 Mile from Affiliated Small Power
Production QF,'' ``Small Power Production Facility > 1 MW, > 1 Mile,
< 10 Miles from Affiliated Small Power Production QF,'' ``Small
Power Production Facility > 1 MW, >= 10 Miles from Affiliated Small
Power Production QF.'' In this column, the numbers 899, 900, and 899
are a distribution of those same estimated 2,698 respondents across
the three categories.
\1053\ This information was not included in the burden estimates
in the NOPR.
FERC-912, Changes Due to Final Rule in Docket Nos. RM19-15-000 and AD16-16-000
--------------------------------------------------------------------------------------------------------------------------------------------------------
Increased
Annual number Increased average hours Increased total annual annual cost
(Termination of obligation to Number of of responses Total number and cost per response burden hours and total per
purchase) respondents per respondent of responses ($) annual cost ($) respondent
(at $83/hr.)
(1) (2) (1) x (2) = (4).................... (3) * (4) = (5)........ (5)/(1) = (6)
(3)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Electric utility burden of reducing 30 1 30 12 hrs.; $996.......... 360 hrs.; $29,880...... $996
210(m) rebuttable presumption from
20 MW to 5 MW \1054\.
------------------------------------------------------------------------------------------------------------------
Total............................ 30 1 30 12 hrs.; $996.......... 360 hrs.; $29,880...... 996
--------------------------------------------------------------------------------------------------------------------------------------------------------
Title: FERC-556 (Certification of Qualifying Facility (QF) Status
for a Small Power Production or Cogeneration Facility), and FERC-912
(PURPA Section 210(m) Notification Requirements Applicable to
Cogeneration and Small Power Production Facilities).
---------------------------------------------------------------------------
\1054\ The staff estimates a total of 90 discretionary responses
may be submitted in Years 1-3, with an annual average of 30.
---------------------------------------------------------------------------
Action: Revisions to existing information collections FERC-556 and
FERC-912.
OMB Control No.: 1902-0075 (FERC-556) and 1902-0237 (FERC-912).
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; electric utilities filing to
terminate their obligation to purchase, at avoided cost rates, the
output of small power production QFs between 5 MW and 20 MW.
Frequency of Information: Ongoing.
Necessity of Information: The Commission directs the changes in
this final rule revising its implementation of PURPA in order to
continue to meet PURPA's statutory requirements.
Internal Review: The Commission has reviewed the 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.
701. 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
or by phone (202) 502-8663].
Please send comments concerning the collection of information and
the associated burden estimates to: Office of Information and
Regulatory Affairs, Office of Management and Budget [Attention: Federal
Energy Regulatory Commission Desk Officer]. Due to security concerns,
comments should be sent directly to www.reginfo.gov/public/do/PRAMain.
Comments submitted to OMB should be sent within 30 days of publication
of this notice in the Federal Register and should refer to FERC-556
(OMB Control No. 1902-0075) and FERC-912 (OMB Control No. 1902-0237).
VI. Environmental Analysis
702. The Commission in the NOPR explained that it was not possible
to determine the environmental effects of the changes proposed, given
the numerous uncertainties regarding the potential effects of the
changes proposed. The Commission in the NOPR stated that, given these
uncertainties, the National Environmental Policy Act of 1969 (NEPA)
\1055\ does not require that the Commission conduct an environmental
review of the proposed revised PURPA Regulations.\1056\
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\1055\ 42 U.S.C. 4321 et seq.
\1056\ NOPR, 169 FERC ] 61,184 at PP 154-55.
---------------------------------------------------------------------------
A. Comments
703. Several commenters argue that the Commission erred in failing
to conduct such a review.\1057\
---------------------------------------------------------------------------
\1057\ Allco Comments at 21-22; Biological Diversity Comments at
14; NIPPC, CREA, REC, and OSEIA Comments at 83; Public Interest
Organizations Comments at 21.
---------------------------------------------------------------------------
704. Biological Diversity asserts an urgent need to take measures
to reduce greenhouse gas emissions to address climate change.\1058\
Biological Diversity states that the Commission's rationale for
revising the PURPA Regulations, namely the increased availability of
``fossil gas,'' requires the Commission to consider the reasonably
foreseeable impacts on climate and the environment, including on
threatened and endangered species, in order to fulfill its
responsibilities under NEPA and the Endangered Species Act (ESA).\1059\
Biological Diversity includes a list of what it alleges are reasonably
foreseeable impacts from increased use of ``fossil gas.'' \1060\
Biological Diversity maintains that the proposed revised PURPA
Regulations would prevent renewable energy development and lock in
``fossil gas'' development and supply, thereby requiring the Commission
to prepare an environmental impact statement and to obtain a biological
opinion before proceeding to a final rule.\1061\
---------------------------------------------------------------------------
\1058\ Biological Diversity Comments at 2-7.
\1059\ Id. at 14.
\1060\ Id. at 15-17.
\1061\ Id. at 17.
---------------------------------------------------------------------------
705. NIPPC, CREA, REC, and OSEIA state that ``the Commission must,
at a minimum, complete the requisite scoping and other process
associated with an EA and then revise and reissue, or abandon, the NOPR
after considering the issues developed in the EA.'' \1062\ NIPPC, CREA,
REC, and OSEIA argue that it would not be too speculative for the
Commission to undertake a NEPA analysis.\1063\ NIPPC, CREA, REC, and
OSEIA state that it is possible to study the environmental effects of
the NOPR proposals because the Commission undertook a NEPA analysis
when it first implemented PURPA, imposing a moratorium on certifying
cogeneration facilities as QFs until it completed an
[[Page 54726]]
Environmental Impact Statement (EIS) and recognizing the environmental
benefits from encouraging the development of QFs, and also studied the
environmental impacts for Order No. 888.\1064\
---------------------------------------------------------------------------
\1062\ NIPPC, CREA, REC, and OSEIA Comments at 83-85 (citing,
e.g., 42 U.S.C. 4332(A); 18 CFR 380.5, 380.4, 380.11; 40 CFR 1500.1,
1502.5; LaFlamme v. FERC, 852 F.2d 389, 397 (9th Cir. 1988); Am.
Bird Conservancy, Inc. v. FCC, 516 F.3d 1027, 1033-34 (D.C. Cir.
2008); N. Plains Res. Council, Inc. v. Surface Transp. Bd., 668 F.3d
1067, 1075 (9th Cir. 2011) (N. Plains Res. Council)).
\1063\ NIPPC, CREA, REC, and OSEIA Comments at 92-94 (citing,
e.g., Am. Bird Conservancy, Inc. v. FCC, 516 F.3d 1033); N. Plains
Res. Council, 668 F.3d at 1076, 1078-79.
\1064\ Id. at 94-96.
---------------------------------------------------------------------------
706. Public Interest Organizations state that the Commission must
prepare an Environmental Assessment (EA) in order to support its
position that this rulemaking may not have any significant foreseeable
environmental impacts.\1065\ Public Interest Organizations describe the
NOPR's ``cursory treatment of the Commission's environmental review
obligations'' as undermining NEPA's purposes ``that agencies give due
consideration to environmental impacts when making major environmental
decisions, and guaranteeing that the public is informed of such
impacts.'' \1066\ Public Interest Organizations argue that states'
exercise of new flexibility granted by the proposed revised PURPA
Regulations are reasonably foreseeable indirect and cumulative impacts
that the Commission must study. Public Interest Organizations assert
that the Commission likely will ``need to prepare a full EIS to
evaluate the serious environmental impacts that will result from
dismantling regulations that continue to play an important role in
development of renewable generation resources across the country.''
\1067\
---------------------------------------------------------------------------
\1065\ Public Interest Organizations Comments at 21.
\1066\ Id.
\1067\ Id. at 26.
---------------------------------------------------------------------------
707. NIPPC, CREA, REC, and OSEIA argue that the Commission has
failed to explain how eliminating the market for at least 10% to 20% of
renewable energy facilities would have no impact on the human
environment.\1068\ NIPPC, CREA, REC, and OSEIA contend that the
Commission has failed to analyze how the proposals would impact regions
like the Northwest that lack robust implementation of PURPA, the 21
states without renewable power standards (such as the Idaho, whose
Legislature affirmatively refused to adopt a renewable power standard),
or the one third of the country that is not located in an RTO or
ISO.\1069\
---------------------------------------------------------------------------
\1068\ NIPPC, CREA, REC, and OSEIA Comments at 86-87.
\1069\ Id. at 87-88.
---------------------------------------------------------------------------
708. Allco argues that it is reasonably foreseeable that the
proposed revisions to the PURPA Regulations and resulting increased
fossil fuels use could add significant levels of greenhouse gas
emissions to the atmosphere and endanger the climate.\1070\ The effects
of such endangerment to the climate from fossil fuel use and reduced
renewable energy QF generation, according to Allco, include mass
extinction of species, in violation of the ESA.\1071\ Allco contends
that the Commission's failure to consult with the U.S. Fish and
Wildlife Service and the National Marine Fisheries Service
(collectively, the Services) prior to issuing the NOPR constituted a
violation of its obligations under the ESA, ``to insure that its
actions are not likely to jeopardize the continued existence of
endangered or threatened species, or result in the destruction or
adverse modification of critical habitat.'' \1072\
---------------------------------------------------------------------------
\1070\ Allco Comments at 31.
\1071\ Id.
\1072\ Id. at 34 (quoting 16 U.S.C. 1536(a)(2)) (internal
quotations omitted).
---------------------------------------------------------------------------
709. According to Allco, the PURPA NOPR triggered the ESA's
consultation requirement because the proposed changes will increase
fossil fuel generation that will, in turn, displace ``over 2 [terawatts
(TWs)] of solar generation over the next 20 years as compared to the
baseline scenario of application and faithful adherence to existing
PURPA rules.'' \1073\ Allco alleges that increased fossil-fuel
generation will ``increase land and ocean temperatures above what they
would have been, . . . resulting in increased pollution to the waters
of the United States, and harming federally endangered and threatened
species, including, without limitation, the Piping plover and the Right
whale.'' \1074\
---------------------------------------------------------------------------
\1073\ Id.
\1074\ Id. at 34-35.
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B. Commission Determination
710. We find that no EA or EIS of the final rule is required. NEPA
requires federal agencies to prepare a detailed statement on the
environmental impact of ``major Federal actions significantly affecting
the quality of the human environment.'' \1075\ The Council on
Environmental Quality's (CEQ) regulations implementing NEPA provide
that federal agencies can comply with NEPA by preparing: (a) An
Environmental Impact Statement (EIS); or (b) an Environmental
Assessment (EA) to determine whether the proposed action significantly
affects the quality of the human environment and requires the
preparation of an EIS.\1076\ CEQ regulations also state that federal
agencies are not obligated to prepare either an EIS or an EA if they
find that a categorical exclusion applies.\1077\ Additionally, courts
have held that an EIS or EA is not required under NEPA ``unless there
is a particular project that `define[s] fairly precisely the scope and
limits of the proposed development.' '' \1078\
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\1075\ 42 U.S.C. 4332(C) (2018); see also Regulations
Implementing the National Environmental Policy Act, Order No. 486,
FERC Stats. & Regs. ] 30,783 (1987) (cross-referenced at 41 FERC ]
61,284).
\1076\ 40 CFR 1501.4 (2019).
\1077\ CEQ regulations state that a categorical exclusion
``means a category of actions which do not individually or
cumulatively have a significant effect on the human environment and
which have been found to have no such effect in procedures adopted
by a federal agency in implementation of these regulations and for
which, therefore, neither an environmental assessment nor an
environmental impact statement is required.'' 40 CFR 1508.4 (2019).
\1078\ Center for Biological Diversity v. Ilano, 928 F.3d 774,
780 (9th Cir. 2019) (Center for Biological Diversity) (quoting
Kleppe v. Sierra Club, 427 U.S. 390, 402 (1976)).
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711. No EA or EIS of the final rule is required because, as
discussed below, the final rule does not propose or authorize, much
less define, the scope and limits of any potential energy
infrastructure and, as a result, there is no way to determine whether
issuance of the rule will significantly affect the quality of the human
environment. In the alternative, a categorical exclusion applies so
that an EA or EIS need not be prepared. For similar reasons, there is
no requirement that the Commission engage in consultation pursuant to
the ESA with respect to this action.
1. No EIS or EA Is Required
a. There Is No Project That Defines the Scope and Limits of QF
Development
712. In Center for Biological Diversity, the court held that no
NEPA review was required with respect to actions taken by the United
States Forest Service that were similar in all relevant respects to the
action taken here by the Commission in promulgating the final rule.
That case involved the designation by the Forest Service, pursuant to
the Healthy Forests Restoration Act (HFRA), of certain forests as
``landscape-scale areas.'' Such designation meant that specific
treatments could be proposed to address insect infestation in those
designated ``landscape-scale areas.'' \1079\ The court held that no
NEPA review was required for the designations, noting that no specific
projects were proposed for any of the landscape-scale areas and stating
that ``[i]n such circumstances, `any attempt to produce an [EIS] would
be little more than a study . . . containing estimates of potential
development and attendant environmental consequences.' '' \1080\ The
court concluded that ``unless there is a particular project that
`define[s] fairly
[[Page 54727]]
precisely the scope and limits of the proposed development of the
region,' there can be `no factual predicate for the production of an
[EIS] of the type envisioned by NEPA.' '' \1081\
---------------------------------------------------------------------------
\1079\ Center for Biological Diversity, 928 F.3d at 778.
\1080\ Id. at 780 (quoting Kleppe v. Sierra Club, 427 U.S. 390,
402 (1976)).
\1081\ Id. (quoting Kleppe, 427 U.S. at 402); see also
Northcoast Environmental Center v. Glickman, 136 F.3d 660, 668 (9th
Cir. 1998) (citing Kleppe in support of its holding that NEPA does
not require agency to complete environmental analysis where
environmental effects are speculative or hypothetical).
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713. Similarly, here, the final rule does not authorize the
development or construction of any facilities, but simply addresses the
rates that QFs can charge and certain requirements under which proposed
facilities may qualify as a QF.\1082\ The final rule does not fund any
particular QFs, or issue permits for their construction or operation
(neither of which the Commission has jurisdiction to do). The
Commission does not, in its regulations or in this final rule,
authorize or prohibit the use of any particular technology or fuel, nor
does it mandate or prohibit where QFs should be or are built. This
final rule does not exempt QFs from any Federal, state, or local
environmental, siting, or similar laws or regulatory requirements,
(again something the Commission has no authority to do).
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\1082\ See Sugarloaf Citizens Ass'n v. FERC, 959 F.2d 508, 514
n.29 (4th Cir. 1992) (finding that in the QF certification context
``FERC does little more than regulate the rates paid by utilities to
the qualifying facility and does not control the financing,
construction or operation of the project. Although the Facility
receives an economic benefit, no direct federal funding or other
substantial federal assistance is provided, and no licensing action
is involved.'').
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714. Even with respect to rates, while the Commission has
established and here revises the factors and approaches that states can
take into account when they set QF rates, it is ultimately the states
and not the Commission that set those rates. The final rule continues
to give states wide discretion and it is impossible to know what the
states may choose to do in response to this final rule, whether they
will make changes in their current practices or not, and how those
state choices would impact QF development and the environment in any
particular state, let along any particular locale.
715. Moreover, the scope of this final rule is even less defined
than the landscape-scale area designations at issue in the Center for
Biological Diversity case. PURPA applies throughout the entire United
States, and the revisions implemented by the final rule theoretically
could affect future QF development anywhere in the country.
716. While courts have held that NEPA requires ``reasonable
forecasting,'' ``NEPA does not require a `crystal ball' inquiry.''
\1083\ Further, 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'' \1084\ or to ``foresee
the unforeseeable.'' \1085\ In that vein, ``[i]n determining what
effects are `reasonably foreseeable,' an agency must engage in
`reasonable forecasting and speculation,' . . . with reasonable being
the operative word.'' \1086\ Environmental impacts are not reasonably
foreseeable if the impacts would result only through a lengthy causal
chain of highly uncertain or unknowable events.\1087\
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\1083\ Vt. Yankee Nuclear Power Corp. v. Nat. Res. Def. Council,
Inc., 435 U.S. 519, 534 (1978) (quoting Nat. Res. Def. Council, Inc.
v. Morton, 458 F.2d 827, 837 (D.C. Cir. 1972)).
\1084\ N. Plains Res. Council v. Surface Transp. Board, 668 F.3d
1067, 1078-79 (9th Cir. 2011) (citation omitted).
\1085\ Concerned About Trident v. Rumsfeld, 555 F.2d 817, 830
(D.C. Cir. 1976) (citation omitted).
\1086\ Sierra Club v. U.S. Dep't of Energy, 867 F.3d 189, 198
(D.C. Cir. 2017) (emphasis in original) (citation omitted).
\1087\ See Dep't of Transp. v. Pub. Citizen, 541 U.S. 752, 767
(2004) (``NEPA requires a `reasonably close causal relationship'
between the environmental effect and the alleged cause.''); Metro.
Edison Co. v. People Against Nuclear Energy, 460 U.S. 766, 774
(1983) (noting effects may not fall within section 102 of NEPA
because ``the causal chain is too attenuated'').
---------------------------------------------------------------------------
717. Commenters' allegations regarding potentially reduced QF
development hinge on the claim that the NOPR proposed to ``repeal'' or
``eliminate'' critical PURPA Regulations, which is not true. The
Commission proposed in the NOPR, which this final rule generally
affirms, to clarify some existing PURPA regulations and modify other
PURPA Regulations to make them consistent with the statute, based on
changed circumstances since the time those regulations originally were
promulgated. Any consideration of whether the revised rules could
potentially result in significant new environmental impacts due to less
QF development and increased development of coal, nuclear, and combined
cycle natural gas plants, would be highly speculative, based on the
difficulty in determining which additional flexibilities the final rule
provides to the states that each state will adopt, if any; how such
state rules would impact QF development going forward; and whether any
reduction in QF renewables would be replaced by the much greater amount
of non-QF renewable resources with similar environmental
characteristics.\1088\
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\1088\ See infra VI.B.2.
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718. As was the case in Center for Biological Diversity, any
attempt to evaluate the environmental effects of the final rule by
necessity would involve nothing less than hypothesizing the potential
development of QFs and the resultant environmental consequences.
Indeed, any attempt by the Commission to estimate the potential
environmental effects of the final rule would be considerably more
speculative than the estimates of potential development and attendant
environmental consequences that the court in Center for Biological
Diversity held are not required under NEPA. That case involved limited
zones in which some projects to treat insect infestation almost
certainly would be proposed. Here, it simply is not possible to provide
any reasonable forecast of the effects of the final rule on future QF
development, whether any affected potential QF would be a renewable
resource (such as solar or wind) or employ carbon-emitting technology
(e.g., a fossil-fuel-burning cogenerator or a waste-coal-burning small
power production facility). Moreover, environmental effects on land
use, vegetation, water quality, etc. are all dependent on location,
which are unknown and could be anywhere in the United States.
719. Because, even more so than in Center for Biological Diversity,
the final rule does not authorize, or define any limit on the scope of,
any potential QF or other infrastructure development, any attempt to
prepare an analysis of the potential effects of the final rule on
future QF development would be so speculative as to render meaningless
any environmental analysis of these impacts. Therefore, no such
analysis is required by NEPA.
b. A Categorical Exclusion Applies
720. There is a separate and independent alternative reason why no
environmental analysis is warranted: the final rule falls within a
categorical exclusion promulgated by the Commission pursuant to the
CEQ's NEPA regulations.\1089\ Specifically, the final rule falls within
the categorical exclusion for rules that: (1) Are clarifying in nature,
(2) are corrective in nature, (3) are procedural in nature, or (4) do
not substantially change the effect of the regulation being
amended.\1090\ Here, each of the revisions to the PURPA Regulations
implemented by the
[[Page 54728]]
final rule fits into one of these categories:
---------------------------------------------------------------------------
\1089\ CEQ regulations provide that agencies shall issue
procedures that provide specific criteria for classes of action
which ``normally do not require either an environmental impact
statement or an environmental assessment (categorical exclusion)''.
40 CFR 1507.3 (2019).
\1090\ See 18 CFR 380.4(a)(2)(ii) (categorical exclusion applies
to ``promulgation of rules that are clarifying, corrective, or
procedural, or that do not substantially change the effect of . . .
regulations being amended.'').
---------------------------------------------------------------------------
i. Changes That Are Clarifying in Nature
721. Several of the changes to the PURPA Regulations are clarifying
in nature. These include the changes clarifying how market prices can
be used to set as-available energy rates,\1091\ the changes clarifying
how fixed energy rates in contracts or LEOs may be determined,\1092\
and the changes clarifying how competitive solicitations can be used to
set avoided cost rates.\1093\ Other non-rate related clarifying
revisions in the final rule include a clarification regarding the
relationship between avoided costs and decreases in a purchasing
utility's load as a consequence of retail competition,\1094\ a
clarification as to how electric generating equipment should be defined
for purposes of determining whether small power production facilities
are located at the same site,\1095\ and a clarification as to when a
LEO is established.\1096\
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\1091\ See Sections IV.B.2-5.
\1092\ See Section IV.B.6.
\1093\ See Section IV.B.8.
\1094\ See Section IV.C.
\1095\ See Section IV.D.2.
\1096\ See Section IV.H.
---------------------------------------------------------------------------
ii. Changes That Are Corrective in Nature
722. The Commission interprets the categorical exclusion for
changes to its regulations that are corrective in nature as including
changes needed in order to ensure that a regulation conforms to the
requirements of the statutory provisions being implemented by the
regulation.\1097\ To be clear, the Commission does not find that its
existing PURPA Regulations were inconsistent with the statutory
requirements of PURPA when promulgated. Rather, the Commission finds
that the changes adopted in this final rule are required to ensure
continued future compliance of the PURPA Regulations with PURPA, based
on the changed circumstances found by the Commission in this final
rule.
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\1097\ For example, the Commission relied on this categorical
exclusion when it revised the PURPA Regulations in 2006 to comply
with the amendments to PURPA enacted as part of EPAct 2005. See
Revised Regulations Governing Small Power Production and
Cogeneration Facilities, Order No. 671, 114 FERC ] 61,102 at P 118.
Further, this interpretation is also consistent with the Supreme
Court's holding that NEPA review is not required when an agency's
action is required by statute. See Dep't of Transp. v. Pub. Citizen,
541 U.S. 752, 770 (2004) (``where an agency has no ability to
prevent a certain effect due to its limited statutory authority over
the relevant actions, the agency cannot be considered a legally
relevant ``cause'' of the effect [and] . . . under NEPA and the
implementing CEQ regulations, the agency need not consider these
effects in its EA.''); see also Safari Club Intern. v. Jewell, 960
F.Supp.2d 17, 79-80 (D.D.C. 2013) (relying on Dep't of Transp. v.
Pub. Citizen to hold that NEPA review is not required for an agency
rule issued to comply with a statutory requirement).
---------------------------------------------------------------------------
723. Three aspects of the final rule are corrective in nature. The
first is the change allowing states to require variable energy rates in
QF contracts.\1098\ As the Commission explains above, this change is
required based on the Commission's finding that, contrary to the
Commission's expectation in 1980, there have been numerous instances
where overestimates and underestimates of energy avoided costs used in
fixed energy rate contracts have not balanced out, causing the contract
rate to not violate the statutory avoided cost rate cap. Giving states
the ability to require energy rates in QF contracts to vary based on
the purchasing utility's avoided cost of energy at the time of delivery
ensures that QF rates do not exceed the avoided cost rate cap imposed
by PURPA.\1099\
---------------------------------------------------------------------------
\1098\ See Section IV.B.7.
\1099\ Id.
---------------------------------------------------------------------------
724. The second corrective aspect is the change in the PURPA
Regulations regarding the determination of what facilities are located
at the same site for purposes of complying with the statutory 80 MW
limit on small power production facilities located at the same
site.\1100\ As explained above, the Commission found, based on changed
circumstances, that the current one-mile rule is inadequate to
determine which facilities are located at the same site. Based on this
finding, the Commission was obligated by PURPA to revise its definition
of when facilities are located at the same site.\1101\
---------------------------------------------------------------------------
\1100\ See Section IV.D.
\1101\ See Section IV.D.1.c.
---------------------------------------------------------------------------
725. The third corrective aspect of the final rule relates to the
implementation of PURPA section 210(m). That statutory provision allows
purchasing utilities to terminate their obligation to purchase from QFs
that have nondiscriminatory access to certain statutorily-defined
markets, which the Commission has determined to be the RTO/ISO markets.
The final rule revises the presumption in the PURPA Regulations that
QFs with a capacity of 20 MW or less do not have non-discriminatory
access to such markets, reducing the threshold for such presumption to
5 MW.\1102\
---------------------------------------------------------------------------
\1102\ See Section IV.G.1.
---------------------------------------------------------------------------
726. The Commission has determined in the final rule that, since
the 20 MW threshold was established in 2005, the RTO/ISO markets have
matured and the industry has developed a better understanding of the
mechanics of market participation. This determination has rendered
inaccurate the presumption currently reflected in the PURPA Regulations
that QFs 20 MW and below do not have non-discriminatory access to the
relevant markets. Once the Commission made this determination, it was
appropriate for the Commission to update the 20 MW threshold to comply
with the requirements of PURPA section 210(m).\1103\
---------------------------------------------------------------------------
\1103\ Id.
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i. Changes That Are Procedural in Nature
727. The remaining two revisions implemented by the final rule are
procedural in nature. The first is a revision to the procedures that
apply to QF certification.\1104\ The second is a revision to the
Commission's Form 556, used by QFs seeking certification.\1105\
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\1104\ See Section IV.E.
\1105\ See Section IV.F
---------------------------------------------------------------------------
2. The NEPA Analysis for Promulgation of the Original PURPA Regulations
in 1980 Cannot Be Replicated Here
728. As commenters note, in 1980 the Commission conducted an EA and
later an EIS for its initial rules implementing PURPA. Initially, the
Commission found (and the Final EIS also found) that new diesel
cogeneration, and dual-fuel cogeneration particularly, in New York
City, could cause significant environmental effects on air
quality.\1106\ In Order No. 70-E, however, the Commission ultimately
opted to treat such cogeneration the same as all other cogeneration
given, among other things, that the PURPA Regulations were not the
driving force behind the development of such cogeneration in New York
City.\1107\ In doing so, the Commission emphasized that QF status was
not a license nor a permit to operate but instead only entitled the QF
to a rate for purchases and to certain exemptions from regulation.
Moreover, QFs were not exempted from any Federal, state, or local
environmental, siting or other similar requirements.\1108\
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\1106\ Final EIS at I-7a.
\1107\ See Order No. 70-E, 46 FR 33025, 33026 (June 18, 1981).
\1108\ Id. The Commission stated in its EA that:
The rules provide encouragement to the development of certain
types of facilities. They do not prevent any facility which does not
qualify from using cogeneration or small power production, or from
using any type of fuel. The rules merely grant or deny certain
benefits to certain facilities.
In this environmental assessment, the environmental effects of
these rules are limited to the effects resulting from the
construction and/or operation of facilities which occur as a result
of the granting of these benefits, or from changes in the operating
characteristics of existing facilities which results from the
granting of these benefits. If a cogeneration or small power
production facility would be constructed or operated without the
incentives of these rules, the environmental effects resulting
therefrom cannot properly be described as environmental effects of
these rules. However, a technical and environmental discussion of
each technology is provided whether or not its use is expected to be
encouraged by these rules.
Small Power Production and Cogeneration Facilities--
Environmental Findings; No Significant Impact and Notice of Intent
To Prepare Environmental Impact Statement, 45 FR 23661, 23664 (Apr.
8, 1980) (Original PURPA EA).
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[[Page 54729]]
729. The original PURPA EA for the pre-existing PURPA Regulations
was based on a market penetration study of PURPA-induced facilities. In
order to carry out that market penetration study, the original PURPA EA
had to make the simplifying assumption that the mere implementation of
PURPA would necessarily result in the development and operation of
certain types of generation facilities that would not otherwise be
developed.\1109\ Based on these types of facilities, that EA identified
specific resource conflicts related to each type of facility, which
were nothing more than a generalized listing of potential
impacts.\1110\ That EA found that, because the various types of
facilities operate differently, there would be no cumulative impacts
and this finding, coupled with the geographic distribution of facility
development from the market penetration study, resulted in a finding of
no significant impact for all types of facilities except diesel and
dual-fueled cogeneration facilities in the Mid-Atlantic, which that EA
found could cause significant environmental impacts on air
quality.\1111\
---------------------------------------------------------------------------
\1109\ Id. at 23,665.
\1110\ Id. at 23,675-82.
\1111\ Id. at 23,679, 23,682-83.
---------------------------------------------------------------------------
730. Subsequently, an EIS was prepared that addressed only air
quality in New York City and the broader Mid-Atlantic region. The bulk
of the EIS focused on how national, state, and local air pollution
regimes would address air quality surrounding the construction and
operation of such facilities.\1112\
---------------------------------------------------------------------------
\1112\ Order No. 70-E, 46 FR at 33026.
---------------------------------------------------------------------------
731. Several commenters cite to this previous NEPA analysis
conducted in connection with the original PURPA Regulations to support
their assertion that a NEPA analysis similarly should be possible for
this rulemaking. However, those assertions are undermined by the fact
that circumstances have changed significantly since the promulgation of
the original PURPA Regulations in 1980. Prior to 1980, essentially no
QF generation technologies or other independent generation facilities
(other than those used to supply the loads of the owners rather than to
sell at wholesale) had been constructed. By contrast, today QF
generation technologies and other independent generation facilities are
common, and they are predominantly built and operated outside of
PURPA.\1113\
---------------------------------------------------------------------------
\1113\ See supra P 240.
---------------------------------------------------------------------------
732. Because there was virtually no QF or independent power
development in 1980, the original PURPA EA could reasonably project
that the incentives created by PURPA and the original PURPA Regulations
would lead to increased development of power generated by QF
technologies. The market penetration study conducted by the Commission,
and the Commission's conclusion that the PURPA Regulations could lead
to an increase in diesel-fired cogeneration in New York City, were
based on these projections.
733. By contrast, it is not possible here to make simplifying
assumptions that the mere implementation of the revised regulations
necessarily would result in specific changes in the development of
particular generation technologies compared to the status quo. First,
the revisions to the PURPA regulations are premised on a finding that,
even after the revisions, the PURPA regulations will continue to
encourage QFs. Consequently, there is no way to estimate whether any
reduction in QF development, as opposed to the status quo, will be
focused on one or more of the many different types of QF technologies,
some of which are renewable resources and some of which are fueled by
fossil fuels \1114\ and have emissions comparable to non-QF fossil
fueled generators. Moreover, because the rule primarily increases state
flexibility in setting QF rates, including giving states the option of
not changing their current rate-setting approaches, there is no way to
develop any estimate of the location or size of any hypothetical
reduction in QF development.
---------------------------------------------------------------------------
\1114\ This would include both cogeneration, which typically is
fossil fueled, and those small power production facilities that are
fueled by waste, which would include a range of fossil fuel-based
waste. See 18 CFR 292.202(b), 292.204(b)(1).
---------------------------------------------------------------------------
734. In addition, as mentioned above, renewable generation
technologies today are commonly, and even predominantly, built and
operated outside of PURPA. Current projections show that most new
generation construction will be of renewable resources.\1115\ Indeed,
the cost of renewables has declined so much that in some regions
renewables are the most cost effective new generation technology
available.\1116\ Thus, even if the final rule was to result in reduced
renewable QF development, there is little likelihood today that
hypothetical, unbuilt QFs necessarily would be replaced by new
conventional fossil fuel generation.
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\1115\ EIA, Annual Energy Outlook 2020, at tbl. 9 (Jan. 29,
2020) (in table see rows labeled Cumulative Planned Additions and
Cumulative Unplanned Additions in the reference case) (Annual Energy
Outlook 2020), https://www.eia.gov/outlooks/aeo/.
\1116\ See supra P 240.
---------------------------------------------------------------------------
735. Alternatively, in the absence of these hypothetical, unbuilt
QFs, existing generation units--whose current emissions, if any, would
already be part of the baseline for any environmental analysis of the
impacts of the final rule--might continue to operate without any change
in their emissions; in sum, in the absence of these hypothetical,
unbuilt QFs, emissions would remain at the baseline and might not
increase at all. Indeed, in the current environment where stagnant load
growth has prevailed in recent years, this would seem to be a more
likely scenario than an alternative where these hypothetical, unbuilt
QFs are replaced by brand new fossil fuel generation that would
increase emissions over the baseline.
736. Given these facts, it would not be possible to perform a
market penetration study of the effects of the final rule that would
not be wholly speculative. Without such a study, there could be no
analysis defining the types and geographic location of facilities that
could serve as the basis for any NEPA analysis similar to that
performed in 1980.
3. This Proceeding Does Not Trigger Any ESA Consultation Requirement
737. Similar to our finding that it would be nearly impossible to
conduct a meaningful NEPA review, we disagree with Biological Diversity
and Allco that either the PURPA NOPR or this final rule trigger any
consultation requirement under the ESA.
The ESA requires that agencies consult with the Secretary of the
Interior or the Secretary of Commerce to ``insure that any action
authorized, funded, or carried out by such agency . . . is not likely
to jeopardize the continued existence of any endangered species or
threatened species or result in the destruction or adverse modification
of [critical] habitat of such species.'' \1117\
---------------------------------------------------------------------------
\1117\ 16 U.S.C. 1536(a)(2).
---------------------------------------------------------------------------
738. The ESA regulations require consultation only if the
Commission determines that a proposed action may affect listed species
or critical habitat.\1118\ We find that there are no
[[Page 54730]]
effects from the final rule for which the Commission could consult with
the Services. Under the ESA regulations, as recently revised, the
effects of an agency's action are
---------------------------------------------------------------------------
\1118\ 50 CFR 402.14(a).
all consequences to listed species and critical habitat that are
caused by the proposed action. A consequence is caused by the
proposed action if it would not occur but for the proposed action
and it is reasonably certain to occur.\1119\
---------------------------------------------------------------------------
\1119\ 50 CFR 402.2 (emphasis added).
The ESA regulations also state that a consequence is not considered
to be caused by a proposed action if ``[t]he consequence is only
reached through a lengthy causal chain that involves so many steps as
to make the consequence not reasonably certain to occur.'' \1120\ This
determination must be made ``based on clear and substantial
information,'' \1121\ and ``should not be based on speculation or
conjecture.'' \1122\ In addition to the above, the same ESA regulation
states that factors for the agency to consider when determining whether
a consequence is not caused by the proposed agency action include:
``(1) The consequence is so remote in time from the action under
consultation that it is not reasonably certain to occur; or (2) [t]he
consequence is so geographically remote from the immediate area
involved in the action that it is not reasonably certain to occur[.]''
\1123\
---------------------------------------------------------------------------
\1120\ 50 CFR 402.17(b)(3) (emphasis added).
\1121\ Id.
\1122\ Endangered and Threatened Wildlife and Plants;
Regulations for Interagency Cooperation, 84 FR 44976, 44993 (Aug.
27, 2019).
\1123\ 50 CFR 402.17(b).
---------------------------------------------------------------------------
739. Because the NOPR was a proposed rule that in and of itself had
no legal effect, the NOPR is not an agency ``action'' under the
regulations implementing the ESA, which define agency action as the
``the promulgation of regulations.'' \1124\ Because the NOPR did not
constitute agency action, the Commission was not required to engage in
consultation under the ESA prior to the NOPR's issuance.
---------------------------------------------------------------------------
\1124\ 50 CFR 402.2 (emphasis added).
---------------------------------------------------------------------------
740. In this final rule, we are promulgating regulations, which
does constitute agency action. Nevertheless, for the same reasons that
an environmental review of the impacts of this final rule under NEPA
would be impossible to conduct, there is similarly no basis to conclude
that harm to endangered species is reasonably certain to occur as a
result of this final rule.
741. We find that the effects on endangered and threatened species
alleged by Allco are not reasonably certain to occur, not only because
any such harm is completely speculative, but also because it could
result only through a lengthy causal chain of highly uncertain or
unknowable events, none of which are within the Commission's authority
to authorize or preclude: (1) That the final rule causes a reduction in
the aggregate amount of QF capacity constructed in the future; (2) that
any reduction in renewable resource QFs would not be offset by
increased construction of renewable resources outside of PURPA,
resulting from either other incentive programs or simply the increased
cost-competitiveness of such resources; (3) that construction of such
non-QF renewable resources would yield an increase in carbon emissions
resulting from the reduction in renewable resource QFs that is not
offset by other renewable resources; and (4) that such increase in
carbon emissions would have an adverse effect on endangered and
threatened species. Furthermore, the consequences of this rule would be
remote in time and geographically remote because it would require
action by individual generators, QF or non-QF, to propose, site,
permit, construct, and operate a facility, in underdetermined locations
potentially anywhere in the United States. In addition, many of these
generators, QF and non-QF, would be subject to state approval and
permitting requirements over which the Commission has no control.
742. Further, there is no support in the record for Allco's claim
that the changes proposed in the PURPA NOPR would displace over 2 TWs
of solar generation over the next 20 years.\1125\ Allco provides no
citation or other support whatsoever for this assertion but simply
makes the claim with no elaboration. We find that such speculation or
conjecture provides no basis upon which to either initiate or conduct
any meaningful consultation with the Services on the impacts to
endangered species from this final rule.
---------------------------------------------------------------------------
\1125\ Allco Comments at 34.
---------------------------------------------------------------------------
VII. Regulatory Flexibility Act Certification
743. The Regulatory Flexibility Act of 1980 (RFA) \1126\ generally
requires a description and analysis of 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 rule will not have a significant economic impact on a substantial
number of small entities.\1127\ The Commission in the NOPR stated that
the proposed rule would not significantly impact a substantial number
of small entities. Some commenters argue otherwise.\1128\
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\1126\ 5 U.S.C. 601-12.
\1127\ 5 U.S.C. 605(b).
\1128\ See Allco Comments at 33.
---------------------------------------------------------------------------
744. The Small Business Administration's (SBA) Office of Size
Standards develops the numerical definition of a small business.\1129\
The SBA size standard for electric utilities is based on the number of
employees, including affiliates.\1130\ 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 \1131\ categories:
---------------------------------------------------------------------------
\1129\ 13 CFR 121.101.
\1130\ SBA final rule on ``Small Business Size Standards:
Utilities,'' 78 FR 77343 (Dec. 23, 2013).
\1131\ 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.
745. This rule directly affects qualifying small power production
facilities and cogeneration facilities, the majority of which the
Commission estimates are small businesses. With respect to the changes
related to the Form No. 556 and new protests allowed pursuant to this
rule, 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. Those revisions may result in
additional information being submitted by some small power production
QF applicants (especially those with affiliated small power production
qualifying facilities using the same energy resource located over one
and less than 10 miles away). The Commission estimates that less than
10 percent of QF applications and self-certifications meet these
criteria.
[[Page 54731]]
746. In the final analysis, the other changes in this final rule
\1132\ largely impact payments to QFs by electric utilities. More
accurate avoided cost rates may result in lower payments from certain
electric utilities to certain QFs. In this regard, the final rule
provides states greater flexibility than they have today to set the
rate that electric utilities will pay QFs, but there is no way to know
in advance which new flexibility state regulatory authorities and
nonregulated electric utilities will exercise, or what impact that new
flexibility might have given the different circumstances likely to
apply to each determination of avoided cost. Under the final rule,
additionally, states also have the discretion to continue setting the
rate as they do today and not to adopt the Commission' proposed greater
rate flexibilities. Therefore, it is not possible to estimate what the
dollar impact might be. However, because of the way PURPA is
structured, whatever the potential dollar impacts of these changes on
small QFs may be, to the extent that they reduce the amounts paid to
certain QFs, such reductions could be matched dollar-for-dollar by
savings experienced by purchasing electric utilities, which should be
flowed through to their retail ratepayers, some of whom would also tend
to qualify as small entities.\1133\
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\1132\ I.e., use of locational marginal prices, competitive
market price, and use of forecasted stream of market revenues for
energy rate component of QF contracts or legally enforceable
obligations; use of variable energy rates in QF contracts or legally
enforceable obligations; use of competitive solicitations to set
avoided energy and capacity rates; reducing the PURPA section 210(m)
rebuttable presumption regarding access to markets from 20 MW to 5
MW; and the commercial viability and financial commitment to
construct demonstration necessary to obtaining a legally enforceable
obligation.
\1133\ While this potential beneficial impact on retail
ratepayers would be an indirect impact of this final rule, the Small
Business Administration Office of Advocacy encourages such indirect
costs to be analyzed as well: ``Although it is not required by the
RFA, the Office of Advocacy believes that it is good public policy
for the agency to perform a regulatory flexibility analysis even
when the impacts of its regulation are indirect.'' SBA, Office of
Advocacy, A Guide for Government Agencies: How to Comply with the
Regulatory Flexibility Act at 23 (Aug. 2017), https://www.sba.gov/sites/default/files/advocacy/How-to-Comply-with-the-RFA-WEB.pdf. But
see Mid-Tex Elec. Co-op., Inc. v. FERC, 773 F.2d 327, 343 (D.C. Cir.
1985) (``Congress did not intend to require that every agency
consider every indirect effect that any regulation might have on
small businesses in any stratum of the national economy.'').
---------------------------------------------------------------------------
747. While Allco argues that the Commission should have attempted
to minimize the impacts on small renewable energy producers and
consider alternative structures, the fact is that these offsetting
impacts result from changes that are necessary to ensure the
Commission's regulations continue to meet PURPA's statutory
requirements. For example, allowing states to use competitive prices
may benefit small QFs inasmuch as the rate-setting process for
purchases of energy from these entities would be more straightforward
and efficient than the administrative processes currently in use.
Furthermore, providing flexibility in setting energy rates may result
in state entities approving longer duration contracts for capacity (at
fixed rates) and energy. The impacts of these changes, therefore, are
reasonable alternatives to the status quo while adhering to the
requirements of PURPA.
748. This final rule establishes a rebuttable presumption that a
qualifying small power production facility whose electrical generating
equipment is more than one but less than 10 miles from affiliated
electrical generating equipment using the same energy resource is at a
separate site. The Commission finds that this rebuttable presumption
imposes a lower burden than imposing a rule that any affiliated
electrical generating equipment less than 10 miles apart is presumed to
be at the same site. Similarly, the Commission, while removing the
rebuttable presumption that qualifying small power production
facilities more than 5 MW but under 20 MW lack nondiscriminatory
access, has provided factors that such facilities could use to
demonstrate lack of such access--allowing them to retain the mandatory
purchase obligation. The Commission estimates that annual additional
compliance costs on industry (detailed above) will be approximately
$1,149,965 (or an average additional burden and cost per response, of
3.187 hrs. and the corresponding $264.51) to comply with these
requirements.\1134\
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\1134\ Annual additional cost of $1,149,965 [($1,120,085 for
FERC-556) + (29,880 for FERC-912)] and average additional burden of
13,855 hours [(13,495 hrs. for FERC-556) + (360 hrs. for FERC-912)]
divided by the number of affected responses of 4,347.5 [(4,317.5 for
FERC-556) + (30 responses for FERC-912)].
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749. Accordingly, pursuant to section 605(b) of the RFA, the
Commission certifies that this rule will not have a significant
economic impact on a substantial number of small entities.
VIII. Document Availability
750. 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 (http://www.ferc.gov). At
this time, the Commission has suspended access to the Commission's
Public Reference Room due to the President's March 13, 2020
proclamation declaring a National Emergency concerning the Novel
Coronavirus Disease (COVID-19).
751. 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.
752. 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.
IX. Effective Dates and Congressional Notification
753. These regulations are effective December 31, 2020. The
Commission has determined, with the concurrence of the Administrator of
the Office of Information and Regulatory Affairs of OMB, that this rule
is not a ``major rule'' as defined in section 351 of the Small Business
Regulatory Enforcement Fairness Act of 1996. This final rule is being
submitted to the Senate, House, Government Accountability Office, and
Small Business Administration.
List of Subjects in 18 CFR Part 292
Electric power plants; Electric utilities, Reporting and
recordkeeping requirements.
List of Subjects in 18 CFR Part 375
Authority delegations (Government agencies); Seals and insignia;
Sunshine Act.
By the Commission. Commissioner Glick is dissenting in part with a
separate statement attached.
Issued: July 16, 2020.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
In consideration of the foregoing, the Commission amends parts 292
and 375, chapter I, title 18, Code of Federal Regulations, as follows.
SUBCHAPTER K--REGULATIONS UNDER THE PUBLIC UTILITY REGULATORY
POLICIES ACT OF 1978
* * * * *
[[Page 54732]]
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.
* * * * *
(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, 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 qualifying
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), there is an irrebuttable presumption that affiliated small
power production qualifying facilities that use the same energy
resource and are located one mile or less from the facility for which
qualification or recertification is sought are located at the same site
as the facility for which qualification or recertification is sought.
(B) For purposes of this paragraph (a)(2), for facilities for which
qualification or recertification is filed on or after December 31, 2020
there is an irrebuttable presumption that affiliated small power
production qualifying facilities that use the same energy resource and
are located 10 miles or more from the facility for which qualification
or recertification is sought are located at separate sites from the
facility for which qualification or recertification is sought.
(C) For purposes of this paragraph (a)(2), for facilities for which
qualification or recertification is filed on or after December 31,
2020, there is a rebuttable presumption that affiliated small power
production qualifying facilities that use the same energy resource and
are located more than one mile and less than 10 miles from the facility
for which qualification or recertification is sought are located at
separate sites from the facility for which qualification or
recertification is sought.
(D) For hydroelectric facilities, facilities are considered to be
located at the same site as the facility for which qualification or
recertification is sought if they are located within one mile of the
facility for which qualification or recertification is sought and use
water from the same impoundment for power generation.
(ii) For purposes of making the determinations in paragraph
(a)(2)(i), the distance between two facilities shall be measured from
the edge of the closest electrical generating equipment for which
qualification or recertification is sought to the edge of the nearest
electrical generating equipment of the other affiliated small power
production qualifying facility using the same energy resource.
(3) Waiver. The Commission may modify the application of paragraph
(a)(2) of this section, for good cause.
(4) 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 size of other small power
production facilities less than 10 miles from such facilities.
* * * * *
0
5. Amend Sec. 292.207 by:
0
a. Revising paragraphs (a), (b) intructory text, (b)(2), (c), and (d);
0
b. Adding paragraphs (e) and (f).
The revisions and additions read as follows:
Sec. 292.207 Procedures for obtaining qualifying status.
(a) Self-certification. (1) FERC 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
FERC Form No. 556 and filing that form with the Commission, pursuant to
Sec. 131.80 of this chapter, and complying with paragraph (e) 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 FERC Form No. 556, provide
information asserting factors showing that the facility for which
qualification or recertification 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) Commission action. Self-certification and self-recertification
are effective upon filing. If no protests to a self-certification or
self-recertification are timely filed pursuant to paragraph (c) of this
section, no further action by the Commission is required for a self-
certification or self-recertification to be effective. If protests to a
self-certification or self-recertification are timely filed pursuant to
paragraph (c) of this section, a self-certification or self-
recertification 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 qualification or recertification, 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.
Absent Commission action before the expiration of the tolling period, a
protest will be deemed denied, and the self-certification or self-
recertification will remain effective.
[[Page 54733]]
(b) Optional procedure--Commission certification. * * *
(2) General contents of application. The application must include a
properly completed FERC 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 FERC 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.
* * * * *
(c) Protests and Interventions. (1) Filing a Protest. Any person,
as defined in Sec. 385.102(d) of this chapter, who opposes either a
self-certification or self-recertification making substantive changes
to the existing certification filed pursuant to paragraph (a) of this
section or an application for Commission certification or Commission
recertification making substantive changes to the existing
certification filed pursuant to paragraph (b) of this section for which
qualification or recertification is filed on or after December 31,
2020, may file a protest with the Commission. Any protest to and any
intervention in a self-certification or self-recertification 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 or
self-recertification is filed. Any protestor must concurrently serve a
copy of such filing pursuant to Sec. 385.211 of this chapter. Any
protest must be adequately supported, and provide any supporting
documents, contracts, or affidavits to substantiate the claims in the
protest.
(2) Limitations on protest. Protests may be filed to any initial
self-certification or application for Commission certification filed on
or after the effective date of this final rule, and to any self-
recertification or application for Commission recertification that are
filed on or after December 31, 2020 that makes substantive changes to
the existing certification. Once the Commission has certified an
applicant's qualifying facility status either in response to a protest
opposing a self-certification or self-recertification, or in response
to an application for Commission certification or Commission
recertification, any later protest to a self-recertification or
application for Commission recertification making substantive changes
to a qualifying facility's certification must demonstrate changed
circumstances that call into question the continued validity of the
certification.
(d) Response to protests. Any response to a protest must be filed
on or before 30 days from the date of filing of that protest and will
be allowed under Sec. 385.213(a)(2) of this chapter.
(e) Notice requirements. (1) General. An applicant filing a self-
certification, self-recertification, application for Commission
certification or application for Commission recertification of the
qualifying status of its facility must concurrently serve a copy of
such filing on each electric utility with which it expects to
interconnect, transmit or sell electric energy to, or purchase
supplementary, standby, back-up or maintenance power from, and the
State regulatory authority of each state where the facility and each
affected electric utility is located. The Commission will publish a
notice in the Federal Register for each application for Commission
certification and for each self-certification of a cogeneration
facility that is subject to the requirements of Sec. 292.205(d).
(2) Facilities of 500 kW or more. An electric utility is not
required to purchase electric energy from a facility with a net power
production capacity of 500 kW or more until 90 days after the facility
notifies the facility that it is a qualifying facility or 90 days after
the utility meets the notice requirements in paragraph (c)(1) of this
section.
(f) Revocation of qualifying status. (1)(i) If a qualifying
facility fails to conform with any material facts or representations
presented by the cogenerator or small power producer in its submittals
to the Commission, the notice of self-certification or Commission order
certifying the qualifying status of the facility may no longer be
relied upon. At that point, if the facility continues to conform to the
Commission's qualifying criteria under this part, the cogenerator or
small power producer may file either a notice of self-recertification
of qualifying status pursuant to the requirements of paragraph (a) of
this section, or an application for Commission recertification pursuant
to the requirements of paragraph (b) of this section, as appropriate.
(ii) The Commission may, on its own motion or on the motion of any
person, revoke the qualifying status of a facility that has been
certified under paragraph (b) of this section, if the facility fails to
conform to any of the Commission's qualifying facility criteria under
this part.
(iii) The Commission may, on its own motion or on the motion of any
person, revoke the qualifying status of a self-certified or self-
recertified qualifying facility if it finds that the self-certified or
self-recertified qualifying facility does not meet the applicable
requirements for qualifying facilities.
(2) Prior to undertaking any substantial alteration or modification
of a qualifying facility which has been certified under paragraph (b)
of this section, a small power producer or cogenerator may apply to the
Commission for a determination that the proposed alteration or
modification will not result in a revocation of qualifying status. This
application for Commission recertification of qualifying status should
be submitted in accordance with paragraph (b) of this section.
0
6. Amend Sec. 292.304 by:
0
a. Adding paragraph (b)(6) through (8); and
0
b. Revising paragraphs (d) and (e).
The additions and revisions read as follows:
Sec. 292.304 Rates for purchases.
* * * * *
(b) Relationship to avoided costs.
* * *
(6) Locational Marginal Price. There is a rebuttable presumption
that 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 electric utilities located in a market 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 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 which a state regulatory authority or nonregulated electric utility
determines represents an appropriate measure of the electric utility's
avoided cost for as-available energy, and is a hub to which the
electric utility has reasonable access, based on an evaluation by the
state regulatory authority or nonregulated electric utility 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 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
[[Page 54734]]
(D) Whether the hub represents an appropriate market to derive an
energy price for the electric utility's purchases from the relevant
qualifying facility 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, a proxy
heat rate, and variable operations and maintenance costs 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 measure of the
purchasing electric utility's avoided cost for energy, 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 measure 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. (i) 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 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:
(A) The solicitation process is an open and transparent process
that includes, but is not limited to, providing equally to all
potential bidders substantial and meaningful information regarding
transmission constraints, levels of congestion, and interconnections,
subject to appropriate confidentiality safeguards;
(B) Solicitations are open to all sources, to satisfy that electric
utility's capacity needs, taking into account the required operating
characteristics of the needed capacity;
(C) Solicitations are conducted at regular intervals;
(D) Solicitations are subject to oversight by an independent
administrator; and
(E) Solicitations are certified as fulfilling the above criteria by
the relevant state regulatory authority or nonregulated electric
utility through a post-solicitation report.
(ii) To the extent that the electric utility procures all of its
capacity, including capacity resources constructed or otherwise
acquired by the electric utility, through a competitive solicitation
process conducted pursuant to paragraph (b)(8)(i) of this section, the
electric utility shall be presumed to have no avoided capacity costs
unless and until it determines to acquire capacity outside of such
competitive solicitation process. However, the electric utility shall
nevertheless be required to purchase energy from qualifying small power
producers and qualifying cogeneration facilities.
(iii) To the extent that the electric utility does not procure all
of its capacity through a competitive solicitation process conducted
pursuant to paragraph (b)(8)(i) of this section, then there shall be no
presumption that the electric utility has no avoided capacity costs.
* * * * *
(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 electric utility's avoided cost
for energy 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 paragraph (d)(2) of this section, 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 vary through the life of the
obligation, and be set at the electric utility's avoided cost for
energy calculated 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 set energy and/or capacity rates pursuant to
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;
[[Page 54735]]
(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
7. Amend Sec. 292.309 by revising paragraphs (c), (d), (e), and (f) to
read as follows:
Sec. 292.309 Termination of obligation to purchase from qualifying
facilities.
* * * * *
(c) For purposes of paragraphs (a)(1), (2) and (3) of this section,
with the exception of paragraph (d) of this section, there is a
rebuttable presumption that a qualifying facility has nondiscriminatory
access to the market if it is eligible for service under a Commission-
approved open access transmission tariff or Commission-filed
reciprocity tariff, and Commission-approved interconnection rules.
(1) If the Commission determines that a market meets the criteria
of paragraphs (a)(1), (2) or (3) of this section, and if a qualifying
facility in the relevant market is eligible for service under a
Commission-approved open access transmission tariff or Commission-filed
reciprocity tariff, a qualifying facility may seek to rebut the
presumption of access to the market by demonstrating, inter alia, that
it does not have access to the market because of operational
characteristics or transmission constraints.
(2) For purposes of paragraphs (a)(1), (2), and (3) of this
section, a qualifying small power production facility with a capacity
between 5 megawatts and 20 megawatts may additionally seek to rebut the
presumption of access to the market by demonstrating that it does not
have access to the market in light of consideration of other factors,
including, but not limited to:
(i) Specific barriers to connecting to the interstate transmission
grid, such as excessively high costs and pancaked delivery rates;
(ii) Unique circumstances impacting the time or length of
interconnection studies or queues to process the small power production
facility's interconnection request;
(iii) A lack of affiliation with entities that participate in the
markets in paragraphs (a)(1), (2), and (3) of this section;
(iv) The qualifying small power production facility has a
predominant purpose other than selling electricity and should be
treated similarly to qualifying cogeneration facilities;
(v) The qualifying small power production facility has certain
operational characteristics that effectively prevent the qualifying
facility's participation in a market; or
(vi) The qualifying small power production facility lacks access to
markets due to transmission constraints. The qualifying small power
production 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.
(d)(1) For purposes of paragraphs (a)(1), (2), and (3) of this
section, 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 paragraphs (a)(1), (2), and (3) of this
section, there is a rebuttable presumption that a qualifying small
power production facility with a capacity at or below 5 megawatts does
not have nondiscriminatory access to the market.
(3) Nothing in paragraphs (d)(1) through (3) of this section
affects the rights the rights or remedies of any party under any
contract or obligation, in effect or pending approval before the
appropriate State regulatory authority or non-regulated electric
utility on or before December 31, 2020, to purchase electric energy or
capacity from or to sell electric energy or capacity to a small power
production facility between 5 megawatts and 20 megawatts under this Act
(including the right to recover costs of purchasing electric energy or
capacity).
(4) For purposes of implementing paragraphs (d)(1) and (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 paragraphs (a)(1)(i) and (ii) of this section, and there
is a rebuttable presumption that small power production facilities with
a capacity greater than 5 megawatts 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 paragraph (a)(3) of this section, and there is a
rebuttable presumption that small power production facilities with a
capacity greater than five megawatts 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
[[Page 54736]]
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
8. 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
9. Amend Sec. 375.302 by revising paragraph (v) to read as follows:
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.
United States of America 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 July 16, 2020)
GLICK, Commissioner, dissenting in part:
1. I dissent in part from today's final rule (Final Rule \1\)
because it effectively guts the Commission's implementation of the
Public Utility Regulatory Policies Act (PURPA).\2\ The Commission's
basic 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, in the public interest, and do not exceed the incremental
costs to the utility of alternative energy.\3\ I do not believe that
today's Final Rule satisfies those responsibilities. Instead, the Final
Rule raises as many questions as it answers, not least of which is the
long-term legal viability of an approach that does so little to
encourage QF development.
---------------------------------------------------------------------------
\1\ Qualifying Facility Rates and Requirements Implementation
Issues Under the Public Utility Regulatory Policies Act of 1978,
Order No. 872, 172 FERC ] 61,041 (2020) (Final Rule).
\2\ Public Law 95-617, 92 Stat. 3117 (1978).
\3\ See 16 U.S.C. 824a-3(a)-(b) (2018).
---------------------------------------------------------------------------
2. Although I have concerns about many of the individual changes
imposed by the Final Rule,\4\ I remain, on a broader level, dismayed
that the Commission is attempting to accomplish via administrative fiat
what Congress has repeatedly declined to do via legislation. I am
especially disappointed because Congress expressly provided the
Commission with a different avenue for ``modernizing'' our
administration of PURPA. The Energy Policy Act of 2005 gave the
Commission the authority to excuse utilities from their obligations
under PURPA where QFs have non-discriminatory access to competitive
wholesale markets.\5\ Had we pursued reforms based on those provisions,
rather than gutting our longstanding regulations, I believe we could
have reached a durable, consensus solution that would ultimately have
done more for all interested parties, even those that may celebrate the
immediate effects of this Final Rule.
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\4\ Notwithstanding those concerns, I support certain aspects of
this Final Rule. First and foremost, I agree with the update to the
``one-mile'' rule, which prior to today provided an irrebuttable
presumption that resources located more than one mile apart are
separate QFs. In addition, I support requiring that QFs demonstrate
commercial viability before securing a legally enforceable
obligation with the relevant utility. Finally, I also support the
revision to allow stakeholders to protest a QF's self-certification.
\5\ Public Law 109-58, 1253, 119 Stat. 594 (2005).
---------------------------------------------------------------------------
I. PURPA's Continuing Relevance Is an Issue for Congress To Decide
3. This proceeding began with a bang. My colleagues championed the
proposed rule as a ``truly significant'' action that would
fundamentally overhaul the Commission's implementation of PURPA.\6\ And
so it was. The NOPR proposed to alter almost every significant aspect
of the Commission's PURPA regulations, thereby transforming the
foundation on which the Commission had carried out its statutory
responsibility to ``encourage'' the development of QFs.
---------------------------------------------------------------------------
\6\ Sept. 2019 Commission Meeting Tr. at 8.
---------------------------------------------------------------------------
4. I dissented from the NOPR in large part because I believe that
it is not the Commission's role to sit in judgment of a duly enacted
statute and determine whether it has outlived its usefulness. As I
explained, ``almost from the moment PURPA was passed, Congress began to
hear many of the arguments being used today to justify scaling the law
back.'' \7\ Congress, however, has seen fit to significantly amend
PURPA only once in its more-than-forty-year lifespan. As part of the
Energy Policy Act of 2005, Congress amended PURPA, leaving in place the
law's basic framework, while adding a series of provisions that allowed
the Commission to excuse utilities from its requirements in regions of
the country with sufficiently competitive wholesale energy markets.\8\
And while Congress considered numerous proposals to further reform the
law, it never saw fit to act on them.\9\ Against that background, I
could not support my colleagues' willingness to ``remove[ ] an
important debate from the halls of Congress and isolate[] it within the
Commission.'' \10\ Whatever your position on PURPA--and I recognize
views vary widely--``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.'' \11\
---------------------------------------------------------------------------
\7\ Qualifying Facility Rates and Requirements Implementation
Issues Under the Public Utility Regulatory Policies Act of 1978,
Notice of Proposed Rulemaking, 168 FERC ] 61,184 (2019) (NOPR)
(Glick, Comm'r, dissenting in part at P 3).
\8\ Public Law 109-58, 1253, 119 Stat. 594 (2005).
\9\ See Solar Energy Industries Association (SEIA) Comments at
11.
\10\ NOPR, 168 FERC ] 61,184 (Glick, Comm'r, dissenting in part
at P 4).
\11\ Id.
---------------------------------------------------------------------------
5. Today's Final Rule retreats from much of the original rationale
used to support the NOPR, but the effect is the same: The Commission is
administratively gutting PURPA. Make no mistake, although the
Commission has dropped much of the NOPR preamble's opening screed
against PURPA's continuing relevance, this Final Rule is a full-
throated endorsement of the conclusion that PURPA has outlived its
usefulness. And while walking back the argument that PURPA is
antiquated may reduce the risk that this Final Rule is overturned on
appeal, that does not change the fact that today's Final Rule usurps
what should be Congress's proper role.
6. Throughout this proceeding, the Commission has been quick to
point to Congress's directive to from time to time
[[Page 54737]]
amend our regulations implementing PURPA.\12\ This Final Rule, however,
is a wholesale overhaul of the Commission's PURPA regulations that
reflects a deep skepticism of the need for the law we are charged with
implementing. I doubt that is what Congress had in mind when it gave us
responsibility for periodically updating our implementing regulations.
---------------------------------------------------------------------------
\12\ Final Rule, 172 FERC ] 61,041 at PP 24, 48, 54, 67, 296,
628; NOPR, 168 FERC ] 61,184 at PP 4, 16, 29, 155.
---------------------------------------------------------------------------
II. The Commission's Proposed Reforms Are Inconsistent With Our
Statutory Mandate
7. PURPA directs the Commission to adopt such regulations as are
``necessary to encourage'' QFs,\13\ including by establishing rates for
sales by QFs that are just and reasonable and by ensuring that such
rates ``shall not discriminate'' against QFs.\14\ As explained below,
many of the changes adopted by the Commission in the Final Rule fail to
meet that standard. In addition, many of the reforms are unsupported--
or, in many cases, contradicted--by the evidence in the record.\15\
Accordingly, I believe today's Final Rule is not just poor public
policy, but also arbitrary and capricious agency action.
---------------------------------------------------------------------------
\13\ A QF is a cogeneration facility or a small power production
facility. See 18 CFR 292.101(b)(1) (2019).
\14\ 16 U.S.C. 824a-3(a)-(b).
\15\ Genuine Parts Co. v. EPA, 890 F.3d 304, 312 (D.C. Cir.
2018) (``[A]n agency cannot ignore evidence that undercuts its
judgment; and it may not minimize such evidence without adequate
explanation.'') (citations omitted); id. (``Conclusory explanations
for matters involving a central factual dispute where there is
considerable evidence in conflict do not suffice to meet the
deferential standards of our review.'' (quoting Int'l Union, United
Mine Workers v. Mine Safety & Health Admin., 626 F.3d 84, 94 (D.C.
Cir. 2010)).
---------------------------------------------------------------------------
A. Avoided Cost
8. The Final Rule adopts two fundamental changes to how QF rates
are determined. First, and most importantly, it eliminates the
requirement that a utility must afford a QF the option to enter a
contract at a rate for energy that is either fixed for the duration of
the contract or determined at the outset--e.g., based on a forward
curve reflecting estimated prices over the term of the contract.\16\
Second, it presumptively allows states to set the rate for as-available
energy at the relevant locational marginal price (LMP) or a similarly
``competitive market price.'' \17\ The record in this proceeding does
not support either of those changes.
---------------------------------------------------------------------------
\16\ Final Rule, 172 FERC ] 61,041 at P 253.
\17\ Id. PP 151, 189, 211.
---------------------------------------------------------------------------
i. Elimination of Fixed Energy Rate
9. Prior to today's Final Rule, a QF generally had two options for
selling its output to a utility. Under the first option, the QF could
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 could enter into a
fixed-duration contract at an avoided cost rate that was fixed either
at the time the QF established a legally enforceable obligation (LEO)
or at the time of delivery. This is generally known as the contract
option. The ability to choose between both types of sale options played
an important role in fostering the development of a variety of QFs. For
example, the as-available option provided a way for QFs whose principal
business was not generating electricity, such as industrial
cogeneration facilities, to monetize their excess electricity
generation. The contract option, by contrast, provided QFs who were
principally in the business of generating electricity, such as small
renewable electricity generators, a stable option that would allow them
to secure financing. Together, the presence of these two options
allowed the Commission to satisfy its statutory mandate to encourage
the development of QFs and ensured that the rates they received were
non-discriminatory.
10. The Final Rule eliminates the requirement that states provide a
contract option that includes a fixed energy rate.\18\ Prior to this
proceeding, the Commission recognized time and again that fixed-price
contracts play an essential role in the financing of QF facilities,
making them a necessary element of any effort to encourage QF
development, at least in certain regions of the country.\19\ In
addition, fixed-price contracts have helped prevent discrimination
against QFs by ensuring that they are not structurally disadvantaged
relative to vertically integrated utilities that are guaranteed to
recover the costs of their prudently incurred investments through
retail rates.\20\
---------------------------------------------------------------------------
\18\ Id. P 253.
\19\ See, e.g., 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 30,880, order on reh'g sub nom. Order No. 69-A,
FERC Stats. & Regs. ] 30,160 (1980), aff'd in part vacated in part,
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). (justifying the rule on the basis of
``the need for certainty with regard to return on investment in new
technologies''); NOPR, 168 FERC ] 61,184 at P 63 (``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.'');
Windham Solar LLC, 157 FERC ] 61,134, at P 8 (2016).
\20\ See, e.g., ELCON Comments at 21-22 (``More varible avoided
cost rates will result in unintended consequences that result in
less competitive conditions and may leave consumers worse off, as
utility self-builds do not face the same market risk exposure.
Pushing more market risk to QFs while utility assets remain
insulated from markets creates an investment risk asymmetry. This
puts QFs at a competitive disadvantage''); South Carolina Solar
Business Association Comments at 8 (``[A]s-available rates for QFs
in vertically-integrated states therefore discriminate against QFs
by requiring QFs to enter into contracts at substantially and
unjustifiably different terms than incumbent utilities.''); Southern
Environmental Law Center Supplement Comments, Docket No. AD16-16-
000, at 6-8 (Oct. 17, 2018) (explaining that vertically integrated
utilities in Indiana, Alabama, Virginia and Tennessee only offer
short-term rates to QFs); sPower Comments at 13; see also Statement
of Travis Kavulla, Docket No. AD16-16-000, at 2 (June 29, 2016).
---------------------------------------------------------------------------
11. If anything, the record before us confirms the continuing
importance of fixed-price contracts. Numerous entities with experience
financing and developing QFs explain that a fixed revenue stream of
some sort is necessary to obtain the financing needed to develop a new
QF.\21\ The fixed revenue stream is particularly important because QFs
are overwhelmingly developed outside of the organized markets, meaning
that developers cannot necessarily obtain hedging contracts to create
the revenue predictability needed to obtain financing.\22\ And that is
why the Final Rule's parade of statistics about the growth of
renewables misses the point.\23\ It is true that, primarily in
[[Page 54738]]
organized markets, independently developed renewables are able to
develop without the entitlement to a fixed-price contract for energy
from the relevant utility.\24\ But the growth of renewables and their
financeability in organized markets tells us almost nothing about what
is required to sufficiently encourage QFs outside those markets.\25\
---------------------------------------------------------------------------
\21\ See, e.g., SEIA Comments at 29; North Carolina Attorney
General's Office Comments at 5; Con Ed Development Comments at 3;
South Carolina Solar Business Association Comments at 6; sPower
Comments at 11; Resources for the Future Comments at 6-7.
\22\ See, e.g., SEIA Comments at 29-30 (``As both Mr. Shem and
Mr. McConnell explain, financial hedge products are not available
outside of ISO/RTO markets.''); Resources for the Future Comments at
6-7 (``[W]hile hedge products do support wind and solar project
financing, they would not be suited for most QF projects. To hedge
energy prices, wind projects have used three products: bank hedges,
synthetic power purchase agreements (synthetic PPAs), and proxy
revenue swaps . . . . From U.S. project data for 2017 and 2018, the
smallest wind project securing such a hedge was 78 MW, and most
projects were well over 100 MW. Additionally, as hedges rely on
wholesale market access and liquid electricity trading, all of the
projects were in ISO regions.'') (emphasis added).
\23\ Harvard Electricity Law Comments at 22 (referring to a
similar statistical parade in the NOPR and observing that ``[a]ll
[the Commission] can actually conclude from this loosely connected
array of facts, data, and speculation is that some non-QF generators
are developed with variable-rate energy contracts. That unremarkable
conclusion has no bearing on whether repeal will discourage QF
development by `materially affect[ing] the ability of QFs to obtain
financing.' '' (citing NOPR, 168 FERC ] 61,184 at P 69)); SEIA
Comments at 30.
\24\ See Final Rule, 172 FERC ] 61,041 at P 340 (``EIA data
demonstrates that net generation of energy by non-utility owned
renewable resources in the United States grew by almost 700% between
2005 and 2018.''). Although independent power producers, renewable
or otherwise, within the RTO/ISO markets are not entitled to fixed
price contracts for energy as a matter of law, they generally do
rely on alternative tools, such as commodity hedges, to lock-in
energy revenue streams. See, e.g., EEI Comments at 36; sPower
Comments at 12.
\25\ In the logical leap of the year, the Commission notes that
in some areas of the country, unspecified resources are developed
with a fixed-price contract for capacity and a variable price for
energy and, separately, that renewables have grown nationwide more
than seven-fold between 2005 and 2018. Final Rule, 172 FERC ] 61,041
at P 340. From those disparate observations, the Commission
concludes that ``renewable resources are able to acquire financing
even without the right to require long-term fixed energy rates.''
Id. But nothing in the record suggests that that phenomenal growth
in renewables was at all the result of that bifurcated contract
structure. That, it should be clear, is not reasoned decisionmaking.
Cf. Nat'l Ass'n of Recycling Indus., Inc. v. Fed. Mar. Comm'n, 658
F.2d 816, 820 n.10 (D.C. Cir. 1980) (``We do not want, after all,
blithely to compare apples and oranges. Likewise, an agency should
also avoid unavailing comparisons of nonsubstitutes.''); see also
Commissioner Slaughter Comments at 4 (noting the ``widespread
geographic differentiation'' in renewable energy progress and
``barriers to independent renewable energy-based power producers'').
---------------------------------------------------------------------------
12. It would be one thing to eliminate the requirement to provide a
fixed-price option for energy rates for QFs that are entitled to a
fixed price for capacity. Although reasonable minds might disagree
about whether a fixed price for capacity alone is sufficient
encouragement, combining one with a variable price for energy would
provide at least some guaranteed revenue stream with which to finance
new development.\26\ Indeed, much of the Commission's justification for
eliminating the fixed-price contract option for energy rests on the
availability of a fixed-price contract option for capacity.\27\
Commission precedent, however, permits utilities to offer a capacity
rate of zero to QFs when the utility does not need incremental
capacity.\28\ That means that, as a result of this Final Rule, QF
developers will face the very real prospect of not receiving any fixed
revenue stream, whether for energy or capacity, in areas where they
also cannot secure hedging products or other mechanisms needed to
finance a new QF.\29\ It is hard for me to understand how the
Commission can, with a straight face, claim to be encouraging QF
development while at the same time eliminating the conditions necessary
to develop QFs in the regions where they are being built.\30\
---------------------------------------------------------------------------
\26\ See, e.g., SEIA Comments at 29 (``While securing financing
based on an As-Available Energy rate and a fixed capacity rate may
be a rare possibility in a few sub-markets across the country, as
Mr. Shem explains, it certainly is not the case in any state that
does not participate in an ISO/RTO market.'').
\27\ See Final Rule, 172 FERC ] 61,041 at P 36 (``This assertion
that the Commission has eliminated fixed rates for QFs is not
correct . . . . The NOPR thus made clear: 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.'') (internal quotation marks omitted); id.
P 237 (``The Commission stated that these fixed capacity and
variable energy payments have been sufficient to permit the
financing of significant amounts of new capacity in the RTOs and
ISOs.'').
\28\ See, e.g., id. P 422 (citing to City of Ketchikan, Alaska,
94 FERC ] 61,293, at 62,061 (2001)).
\29\ See, e.g., Resources for the Future Comments at 6; SEIA
Comments at 30; Southeast Public Interest Organizations Comments at
12.
\30\ See Public Interest Organizations Comments at 10-11
(``Obviously, rules that have an effect of discouraging QFs cannot
be 'necessary to' encouraging them.''); see also Massachusetts
Attorney General Maura Healey Comments at 6 (``This action may
reduce investor confidence and discourage future development. That
outcome is a negative one for the Commonwealth and its
ratepayers.'').
---------------------------------------------------------------------------
13. The Commission sidesteps this point in responding that PURPA
does not require that QFs be financeable. That is true in a literal
sense; nothing in PURPA directs the Commission to ensure that at least
some QFs be financeable. But it does require the Commission to
encourage their development, which we have previously equated with
financeability.\31\ If the Commission is going to abandon that
standard, it must then explain why what is left of its regulations
provides the requisite encouragement--an explanation that is lacking
from this Final Rule, notwithstanding the Commission's repeated
assertions to the contrary.
---------------------------------------------------------------------------
\31\ See, e.g., 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''); NOPR,
168 FERC ] 61,184 at P 63 (``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.'').
---------------------------------------------------------------------------
14. The Commission also does not sufficiently explain how
eliminating the fixed-price contract requirement is consistent with
PURPA's requirement that rates ``shall not discriminate against''
QFs.\32\ Vertically integrated utilities effectively receive guaranteed
fixed-price contracts through their rights to recover prudently
incurred investments. The equivalent right to receive fixed-price
contracts has to date proved an integral element of the Commission's
ability to satisfy PURPA's prohibition on discriminatory rates.\33\
---------------------------------------------------------------------------
\32\ 16 U.S. Code Sec. 824a-3(b)(2). Unlike provisions of the
Federal Power Act, PURPA prohibits any discrimination against QFs,
not just undue discrimination. See ELCON Comments at 21-22; South
Carolina Solar Business Alliance Comments at 7-8; sPower Comments at
13.
\33\ See supra n.20; Commissioner Slaughter Comments at 4.
---------------------------------------------------------------------------
15. And yet this Final Rule fails to explain how eliminating the
fixed-price option is consistent with that prohibition or, moreover,
how permitting QFs to receive variable contract rates while vertically
integrated utilities receive fixed ones is consistent with the
Commission's obligation to promote QFs.\34\ Instead, the Commission
notes that, through so-called fuel adjustment clauses, vertically
integrated utilities' rates change as the price of fuel changes.\35\
The idea that those clauses, which ensure that utilities recover a
specific variable cost (i.e., their cost of fuel), is the same thing as
having your entire revenue exposed to variations in prevailing market
conditions is hogwash. The presence of fuel adjustment clauses in no
way suggests that vertically integrated utilities are subject to
anything remotely close to the level of revenue variation contemplated
in this Final Rule.
---------------------------------------------------------------------------
\34\ Public Interest Organizations Comments at 51 (``[L]imiting
QFs to contracts providing no price certainty for energy values,
while non-QF generation regularly obtains fixed price contracts and
utility-owned generation receives guaranteed cost recovery from
captive ratepayers, constitutes discrimination.'').
\35\ Final Rule, 172 FERC ] 61,041 at P 122.
---------------------------------------------------------------------------
16. Finally, the Commission fails to explain why allegations of QF
rates exceeding a utility's actual avoided cost requires us to abandon
the Commission's long-held principles regarding certainty and
financing.\36\ As an initial matter, the Commission has recognized that
QF rates may exceed actual avoided costs, but, at the same time,
recognized that avoided cost rates might also turn out to be lower than
the electric utility's avoided costs over the course of the contract.
The Commission has reasoned that, ``in the long run, `overestimations'
and `underestimations' of avoided costs will balance out.'' \37\
However, when presented with a couple allegations that avoided costs
were overestimated,\38\ the Commission now concludes that that
possibility suggests it must abandon the fixed-energy rate
[[Page 54739]]
contract altogether. The Commission, however, makes no effort to
validate these allegations,\39\ or assess whether the overestimations
of avoided cost were, in fact, balanced out.\40\ It is arbitrary and
capricious to point to only half the picture in abandoning a forty-
year-old principle.
---------------------------------------------------------------------------
\36\ See supra n.19.
\37\ Order No. 69, FERC Stats. & Regs. ] 30,128 at 30,880.
\38\ Final Rule, 172 FERC ] 61,041 at PP 265, 268.
\39\ Id. PP 291, 293.
\40\ The Commission is quick to point to ``the precipitous
decline in natural gas prices'' starting in 2008 that may have
caused QF contracts fixed prior to that period to underestimate the
actual cost of energy. See, e.g., Final Rule, 172 FERC ] 61,041 at P
287). However, PURPA has been in place for forty years, and the
Commission does not wrestle with the magnitude of potential savings
conveyed to consumers from the fixed-price energy contracts that
locked-in low rates for consumers during the decades prior when
natural gas prices were several times higher. See Energy Information
Administration Total Energy, tbl. 9.10 (last viewed July 15, 2020),
https://www.eia.gov/totalenergy/data/browser/.
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ii. Rebuttable Presumption for Setting Avoided Cost at LMP and Similar
Measures
17. I also do not support the Commission's decision to treat LMP or
other ``competitive market prices'' as a presumptively reasonable
measure of an as-available avoided cost for energy.\41\ Liquid price
signals can be useful and transparent inputs and ought to be considered
in calculating an appropriate avoided-cost figure. But considering
those price signals in setting avoided cost is not the same thing as
presuming that LMP or similar measures are alone sufficient to
establish avoided cost. Many regions of the country--often the same
regions where the debates about PURPA are most heated--have not
established sufficiently competitive markets. In these regions it is
not clear from the record that the prices in, for example, a
neighboring RTO, are a representative measure of a utility's avoided
cost. In those less competitive markets, it simply does not make sense
to presume that LMP or other ``competitive market prices'' are a
representative measure of avoided cost, rather than one of many
criteria that should go into that determination.\42\
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\41\ Final Rule, 172 FERC ] 61,041 at PP 151, 189, 211.
\42\ Congress itself seems to have contemplated that states
would not rely solely on spot market prices when establishing
avoided cost. H.R. Rep. No. 95-1750, at 7833 (1978) (``In
interpreting the term `incremental cost of alternative energy,' the
conferees expect that the Commission and the states may look beyond
the cost of alternative sources which are instantaneously available
to the utility.'').
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18. For similar reasons, I share the concern of many commenters
that short-term or spot prices, such as LMP, may not reflect the long-
term marginal energy costs avoided by purchasing utilities, especially
outside of organized markets.\43\ Although the Commission revises the
NOPR's per se rule to be a rebuttable presumption, it nevertheless
plows ahead with the conclusion that LMP, and similar measures, reflect
a utility's avoided cost of energy. Where there is good reason to
believe that those measures do not actually reflect the long-term value
of energy that they are supposed to represent, it makes no sense to put
the burden on QFs to prove the point,\44\ rather than leaving the
burden with the proponents of using such measures.
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\43\ Final Rule, 172 FERC ] 61,041 at n.163; Hydro Comments at
11; Southeast Public Interest Organizations Comments at 19; NIPPC,
CREA, REC, and OSEIA Comments at 52, 55; Union of Concerned
Scientists Comments at 6. Take, for example, the Commission's
approval of the Mid-Columbia market hub price as presumptively
reflecting a utility's avoided cost for energy. See Final Rule, 172
FERC ] 61,041 at PP 180, 189. Notwithstanding explicit support for
this approach from the regulated utility industry, the Washington
Utilities and Transportation Commission which, when addressing Puget
Sound Energy's plan to increase wholesale purchases from the Mid-
Columbia market ``liquid hub'' to 1,600 MW, expressed a concern
about the regulated utility's overreliance on such wholesale market
pricing and directed them to pursue an alternative plan to eliminate
this ``excessive risk.'' That is the exact type of tension conveyed
in the record--i.e, that such competitive market prices may not
accurately reflect a utility's avoided cost, as approved by
regulators. See Washington UTC, Acknowledgment Letter Attachment,
Puget Sound Energy's 2017 Electric and Natural Gas Integrated
Resource Plan, Wash. UTC Docket Nos. UE-160918, UG-160919 (Revised
June 19, 2018); see NIPPC, CREA, REC, and OSEIA Comments at 56.
\44\ Final Rule, 172 FERC ] 61,041 at P 152.
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19. The Commission's presumptive approval of LMP and similar
measures is even more problematic when combined with the decision to
allow utilities to eliminate the fixed-price contract option. Following
this Final Rule, QFs may be reduced to relying solely on some synthetic
and highly variable measure of what spot prices should be in a
competitive market based on gas prices and heat rates, all while the
utilities whose costs the QF is avoiding recovers an effectively
guaranteed rate potentially in excess of this representative
``competitive market price.'' I am not persuaded that this approach
will satisfy our obligation to encourage QFs and to do so using rates
that are non-discriminatory across all regions of the country.
B. Rebuttable Presumption 20 MW to 5 MW
20. Following the Energy Policy Act of 2005, the Commission
established a rebuttable presumption that QFs with a capacity greater
than 20 MW operating in RTOs and ISOs have non-discriminatory access to
competitive markets, eliminating utilities' must-purchase obligation
from those resources.\45\ The Final Rule reduces the threshold for that
presumption from 20 MW to 5 MW. \46\ That is an improvement over the
NOPR, which--without any support whatsoever--proposed to lower that
threshold to 1 MW.\47\ But, even so, the reduced 5 MW threshold is
unsupported by the record and inadequately justified in today's Final
Rule.
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\45\ New PURPA Section 210(m) Regulations Applicable to Small
Power Production and Cogeneration Facilities, Order No. 688, 117
FERC ] 61,078, at P 72 (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); see 16 U.S.C. Sec. 824a-3(m).
\46\ Final Rule, 172 FERC ] 61,041 at P 625.
\47\ NOPR, 168 FERC ] 61,184 at P 126.
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21. When it originally established the 20 MW threshold, the
Commission pointed to an array of barriers that prevented resources
below that level from having truly non-discriminatory access to RTO/ISO
markets. Those barriers included complications associated with
accessing the transmission system through the distribution system (a
common occurrence for such small resources), challenges with reaching
distant off-takers, as well as ``jurisdictional differences, pancaked
delivery rates, and additional administrative procedures'' that
complicate those resources' ability to participate in those markets on
a level playing field.\48\ In just the last few years, the Commission
has recognized the persistence of those barriers ``that gave rise to
the rebuttable presumption that smaller QFs lack nondiscriminatory
access to markets.'' \49\
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\48\ Order No. 688-A, 119 FERC ] 61,305 at PP 96, 103.
\49\ E.g., N. States Power Co., 151 FERC ] 61,110, at P 34
(2015).
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22. Nevertheless, the Final Rule abandons the 20 MW threshold based
on the conclusory assertion that ``it is reasonable to presume that
access to RTO/ISO markets has improved'' and it is, therefore,
``appropriate to update the presumption.'' \50\ No doubt markets have
improved. But a borderline-truism about maturing markets does not
explain how the barriers arrayed against small resources have
dissipated, why it is reasonable to ``presume'' that the remaining
barriers do not inhibit non-discriminatory access, or why 5 MW is
[[Page 54740]]
an appropriate new threshold for that presumption.
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\50\ Final Rule, 172 FERC ] 61,041 at P 629 (``Over the last 15
years, the RTO/ISO markets have matured, market participants have
gained a better understanding of the mechanics of such markets and,
as a result, we find that it is reasonable to presume that access to
the RTO/ISO markets has improved and that it is appropriate to
update the presumption for smaller production facilities.'').
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23. Instead of any such evidence, the Final Rule notes that the
Commission uses the 5 MW as a demarcating line for other rules applying
to small resources. Specifically, it points to the fact that resources
below 5 MW can use a ``fast-track'' interconnection process, whereas
larger ones must use the large generator interconnection
procedures.\51\ But the fact that the Commission used 5 MW as the cut
off in another context hardly shows that it is the right cut off to use
in this context.
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\51\ Id. P 630.
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24. Lacking substantial evidence to support the 5 MW threshold, the
Commission falls back on a deferential standard of review.\52\ But
while judicial review of agency policymaking is deferential, it is not
toothless. The same cases on which the Commission relies require that,
when an agency's policy reversal ``rests upon factual findings that
contradict those which underlay its prior policy,'' the agency must
``provide a more detailed justification than what would suffice for a
new policy created on a blank slate.'' \53\ That is because reasoned
decisionmaking requires that, when an agency changes course, it must
provide ``a reasoned explanation . . . for disregarding facts and
circumstances that underlay or were engendered by the prior policy.''
\54\ For the foregoing reasons, the Commission has failed to produce
any such explanation, making its change of course arbitrary and
capricious.
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\52\ Id. P 637 (citing FCC v. Fox Television, 556 U.S. 502, 515
(2009), for the proposition that an agency ``need not demonstrate to
a court's satisfaction that the reasons for the new policy are
better than the reasons for the old one; it suffices that the new
policy is permissible under the statute, that there are good reasons
for it, and that the agency believes it to be better, which the
conscious change of course adequately indicates.'').
\53\ Fox Television, 556 U.S. at 515; Advanced Energy Economy
Comments at 6.
\54\ Fox Television, 556 U.S. at 516; Advanced Energy Economy
Comments at 6-7.
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III. Environmental Review Under the National Environmental Policy Act
25. In contrast to the Commission's crowing over the significance
of its PURPA overhaul, the Final Rule describes the changes adopted as
merely corrective and clarifying in nature when it comes to conducting
an environmental review.\55\ In particular, the Commission contends
that ``the changes adopted in this final rule are required to ensure
continued future compliance of the PURPA Regulations with PURPA, based
on the changed circumstances found by the Commission in this final
rule.'' \56\ In other words, because the Commission believes that the
changes adopted are necessary to conform with the statute, they are
mere corrective changes, which, in turn, qualifies them for the
categorical exemption from any environmental review under NEPA, or so
the argument goes.
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\55\ Under the National Environmental Policy Act (NEPA), the
Commission must consider whether its action associated with
rulemakings will have a significant impact on the environment. See
42 U.S.C. 4321 et seq.
\56\ Final Rule, 172 FERC ] 61,041 at P 722.
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26. But by that logic, any Commission action needed to comply with
our various statutory mandates--whether ``just and reasonable'' or the
``public interest''--would be deemed corrective in nature and,
therefore, excluded from environmental review. The Commission, however,
fails to point to any evidence suggesting that is what the Council on
Environmental Quality contemplated when it allowed for categorical
exemptions.
IV. The Way To Revise PURPA Is To Create More Competition, Not Less
27. It didn't have to be this way. When Congress reformed PURPA in
the 2005 Energy Policy Act amendments, it indicated an unmistakable
preference for using market competition as the off-ramp for utilities
seeking relief from their PURPA obligations.\57\ Those reforms directed
the Commission to excuse utilities from those obligations where QFs had
non-discriminatory access to RTO/ISO markets or other sufficiently
competitive constructs.\58\
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\57\ 16 U.S.C. Sec. 824a-3(m).
\58\ See Order No. 688, 117 FERC ] 61,078 at P 8.
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28. This record contains numerous comments explaining how the
Commission could use those amendments as a way to ``modernize'' PURPA
in a manner that both promotes actual competition and reflects
Congress's unambiguous intent.\59\ For example, in a white paper
released prior to the NOPR, the National Association of Regulatory
Utility Commissioners (NARUC) urged the Commission to give meaning to
the 2005 amendments 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
solicitations for energy and capacity.\60\ Other groups, including
representatives of QF interests, submitted additional comments on how
an approach along those lines might work.\61\ Several parties commented
on those proposals.\62\
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\59\ See Advanced Energy Economy Comments at 13; Industrial
Energy Consumers Comments at 13-14; EPSA Comments at 16.
\60\ National Association of Regulatory Utility Commissioners
Supplemental Comments, Docket No. AD16-16-00, Attach. A, at 8 (Oct.
17, 2018); id. (proposing the Commission's Edgar-Allegheny criteria
as a basis for evaluating whether a proposal was adequately
competitive).
\61\ See, e.g., SEIA Supplemental Comments, Docket No. AD16-16-
000 (Aug. 28, 2019).
\62\ See, e.g., Advanced Energy Economy Comments at 12; APPA
Comments at 29; Colorado Independent Energy Comments at 7; ELCON
Comments at 19; Public Interest Organizations Comments at 90; SEIA
Comments at 24; Xcel Comments at 11.
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It is a shame that the Commission has elected to administratively
gut its long-standing PURPA implementation regime, rather than pursuing
reform rooted in PURPA section 210(m), such as the NARUC proposal.
Pursuing an option along those lines could have produced a durable,
consensus solution to the issues before us. I continue to believe that
the way to modernize PURPA is to promote real competition, not to gut
the provisions that the Commission has relied on for decades out of
frustration that Congress has repeatedly failed to repeal the statute
itself.
For these reasons, I respectfully dissent in part.
Richard Glick,
Commissioner.
[FR Doc. 2020-15902 Filed 9-1-20; 8:45 am]
BILLING CODE 6717-01-P