Document ID: FERC-2020-1145-0001
Agency: ferc
Document Type: Rule
Title: Qualifying Facility Rates and Requirements Implementation Issues Under the Public Utility Regulatory Policies Act of 1978
Posted Date: 2020-09-02T04:00Z

[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

[[Page 54640]]

 
                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).
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \37\ NOPR, 168 FERC ] 61,184, at PP 15-27.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \38\ Harvard Electricity Law Comments at 1.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \53\ See NOPR, 168 FERC ] 61,184 at P 66.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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'').
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.'').
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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).
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    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.
---------------------------------------------------------------------------

    \69\ 16 U.S.C. 824a-3(a).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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'').
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \95\ 16 U.S.C. 824a-3(a), (b).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \103\ Conf. Rep. at 98 (emphasis added).
    \104\ Id. (emphasis added).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \105\ 16 U.S.C. 824a-3(b)(1).
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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].'').
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \110\ See 16 U.S.C. 824a-3(a) (emphasis added).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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)).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

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

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

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

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

[[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\
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

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

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

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

[[Page 54656]]

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

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

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

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

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

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

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

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

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

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

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

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

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

[[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\
---------------------------------------------------------------------------

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

    128. The Commission understood that some states already use LMP to 
establish avoided cost energy rates under the existing PURPA 
Regulations.\196\ The Commission thus proposed also to clarify that, 
while a state in the past may have been able to conclude that LMP was 
an appropriate measure of the energy component of avoided costs,\197\ a 
state would, under the proposal in the NOPR, be able to adopt LMP as a 
per se appropriate measure of the as-available energy component of 
avoided costs.\198\
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

[[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.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

[[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\
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

[[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.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

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

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

[[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.
---------------------------------------------------------------------------

    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.

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

[[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.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

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

[[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\
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    \328\ El Paso Electric Comments at 3-4.
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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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \333\ See new 18 CFR 292.304(b)(7)(ii).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \334\ NOPR, 168 FERC ] 61,184 at P 61.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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))).
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \344\ Arizona Public Service Comments at 2-3.
    \345\ NRECA Comments at 8.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \346\ Id. at 9.
    \347\ Connecticut Authority Comments at 14.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \348\ Id. at 13.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \351\ Allco Comments at 8.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \352\ APPA Comments at 14.
    \353\ Distributed Sun Comments at 2.
    \354\ NorthWestern Comments at 6.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \355\ Windham Solar, 157 FERC ] 61,134 at P 4 (citing 18 CFR 
292.304(d)(2)).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.'').
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \365\ NOPR, 168 FERC ] 61,184 at P 67.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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)).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \368\ Id. P 69.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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)).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \374\ Id. P 73.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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.'').
---------------------------------------------------------------------------

    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.'').
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \570\ NIPPC, CREA, REC, and OSEIA Comments at 51.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

(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.
---------------------------------------------------------------------------

    \692\ Allegheny, 108 FERC ] 61,082 at P 18.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \693\ Public Interest Organizations Comments at 73.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \696\ 16 U.S.C. 2621(a), (d)(7) (requiring states to consider 
whether to employ integrated resource planning).
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \704\ Biogas Comments at 2; Covanta Comments at 9.
    \705\ Covanta Comments at 9.
    \706\ Biogas Comments at 2; Covanta Comments at 9-10.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \707\ Ohio Commission Energy Advocate Comments at 5.
    \708\ Id. at 6.
    \709\ Id. at 6-7.
    \710\ Id.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \711\ ELCON Comments at 19.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \712\ California Utilities Comments at 5.
    \713\ Id. at 7.
    \714\ Chamber of Commerce Comments at 5.
    \715\ Michigan Commission Comments at 5-6.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \716\ Connecticut Authority Comments at 16.
    \717\ Id. at 17.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \719\ Id. at 18.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \720\ California Utilities at 9.
    \721\ Id. at 9-10.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \725\ Id. at 14.
    \726\ Id. at 15.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \727\ 18 CFR 292.304(e)(3).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.''
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \838\ DC Commission Comments at 9.
    \839\ Id.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
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    \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\
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    \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\
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    \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\
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    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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)).
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    \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.'').
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \1088\ See infra VI.B.2.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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).

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

[[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.
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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)].
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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\
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    \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\
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    \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.'').
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    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.
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    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.
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    \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/.
---------------------------------------------------------------------------

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.'').
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.'').
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \51\ Id. P 630.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \57\ 16 U.S.C. Sec.  824a-3(m).
    \58\ See Order No. 688, 117 FERC ] 61,078 at P 8.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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