2020-26106. Qualifying Facility Rates and Requirements Implementation Issues Under the Public Utility Regulatory Policies Act of 1978

AGENCY:

Federal Energy Regulatory Commission.

ACTION:

Final rule; Order addressing arguments raised on rehearing and clarifying prior order in part.

SUMMARY:

In this Order, the Federal Energy Regulatory Commission addresses arguments raised on rehearing and clarifies, in part, its final rule adopting 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 February 16, 2021.

FOR FURTHER INFORMATION CONTACT:

Lawrence R. Greenfield (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, [phone], [e-mail]

Helen Shepherd (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, [phone], [e-mail]

Thomas Dautel (Technical Information), Office of Energy Policy and Innovation, Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, [phone], [e-mail]

SUPPLEMENTARY INFORMATION:

 

Table of Contents

	Paragraph
I. Background	4
A. Statutory Background	4
B. Final Rule's Updating of the PURPA Regulations	10
C. Summary of Changes to the PURPA Regulations Implemented by the Final Rule	11
II. Discussion	23
A. Threshold Issues	24
1. Whether the Commission Appropriately Consulted With Representatives of Relevant State and Federal Agencies	24
a. Requests for Rehearing	24
b. Commission Determination	25
2. Whether the PURPA Regulations Continue To Encourage QFs	27
a. Requests for Rehearing	27
b. Commission Determination	39
B. QF Rates	46
1. Overview	46
2. LMP as a Permissible Rate for Certain As-Available Avoided Cost Rates	53
a. Requests for Rehearing	60
b. Commission Determination	63
3. Tiered Avoided Cost Rates	66
a. Request for Clarification	66
b. Commission Determination	72
4. Providing for Variable Energy Rates in QF Contracts Is Consistent With PURPA	74
a. Whether the Current Approach Has Resulted in Payments to QFs in Excess of Avoided Costs	84
i. Requests for Rehearing	95
ii. Commission Determination	104
b. Whether the Proposed Change Would Violate the Statutory Requirement That the PURPA Regulations Encourage QFs and Do Not Discriminate Against QFs	114
i. Requests for Rehearing	118
ii. Commission Determination	134
c. Effect of Variable Energy Rates on Financing	145
i. Requests for Rehearing	159
ii. Commission Determination	172
d. Requested Clarification of the Final Rule	178
i. Commission Determination	179
5. Consideration of Competitive Solicitations To Determine Avoided Costs	181
i. Requests for Rehearing	203
ii. Commission Determination	214
C. Rebuttable Presumption of Separate Sites	232
1. Need for Reform	235
a. Requests for Rehearing	236
b. Commission Determination	238
2. Distance Between Facilities	246
a. Requests for Rehearing	250
b. Commission Determination	255
3. Factors	261
a. Requests for Rehearing	265
b. Commission Determination	273
D. QF Certification Process	280
1. Requests for Rehearing	290
2. Commission Determination	306
E. Corresponding Changes to the FERC Form No. 556	327
1. Requests for Rehearing	330
2. Commission Determination	331
F. PURPA Section 210(m) Rebuttable Presumption of Nondiscriminatory Access to Markets	334
1. Requests for Rehearing and Clarification	354
2. Commission Determination	360
G. Legally Enforceable Obligation	374
1. Requests for Rehearing	381
2. Commission Determination	384
III. Information Collection Statement	389
A. Request for Rehearing	392
B. Commission Determination	393
1. QFs Submitting Self-Certifications	403
a. Small Power Production Facility Greater Than 1 MW, and Less Than One Mile From an Affiliated Small Power Production QF	404
b. Small Power Production Facility Greater Than 1 MW, and More Than One Mile but Less Than 10 Miles From an Affiliated Small Power Production QF	405
c. Small Power Production Facility Greater Than 1 MW and 10 Miles or More From an Affiliated Small Power Production QF	406
2. QFs Submitting Applications for Commission Certification	407
a. Small Power Production Facility Greater Than 1 MW, and Less Than One Mile From an Affiliated Small Power Production QF	408
b. Small Power Production Facility Greater Than 1 MW, and More Than One Mile but Less Than 10 Miles From an Affiliated Small Power Production QF	409
c. Small Power Production Facility Greater Than 1 MW and 10 Miles or More From an Affiliated Small Power Production QF	410
3. Calculations for Additional Burden and Cost	411
IV. Environmental Analysis	412
A. No EIS or EA Is Required	412
1. NEPA Analysis Is Not Required Where Environmental Impacts Are Not Reasonably Foreseeable	414
a. Requests for Rehearing	420
b. Commission Determination	425
2. A Categorical Exclusion Applies	436
a. Exception to Categorical Exclusion	443
i. Requests for Rehearing	443
ii. Commission Determination	444
b. Applying a Categorical Exclusion for Clarifying and Corrective Actions Is Appropriate	445
i. Requests for Rehearing	445
ii. Commission Determination	449
3. That the Commission Prepared NEPA Analyses for the Promulgation of the Original PURPA Rule and Other Prior Rulemakings Does Not Mean That Such Analysis Was Possible or Required Here	455
a. Requests for Rehearing	462
b. Commission Determination	465
V. Regulatory Flexibility Act Certification	469
VI. Document Availability	471
VII. Effective Dates and Congressional Notification	474

1. On July 16, 2020, the Federal Energy Regulatory Commission (Commission) issued its final rule (final rule or Order No. 872) ^[1] adopting revisions to its regulations (PURPA Regulations) ^[2] implementing sections 201 and 210 of the Public Utility Regulatory Policies Act of 1978 (PURPA).^[3] Those regulations were promulgated in 1980 and have been modified in only specific respects since then. On August 17, 2020, the Commission received requests for rehearing and/or clarification of the final rule from the following entities and individuals: (1) California Utilities; ^[4] (2) Electric Power Supply Association (EPSA); (3) Northwest Coalition; ^[5] (4) One Energy Enterprises; (5) Public Interest Organizations; ^[6] (6) Solar Energy Industries Association (Solar Energy Industries); and (7) Thomas Mattson. On September 1, 2020, California Public Utilities Commission (California Commission) filed a response to California Utilities' request for clarification.

2. Pursuant to Allegheny Defense Project v. FERC,^[7] the rehearing requests filed in this proceeding may be deemed denied by operation of law. As permitted by section 313(a) of the Federal Power Act (FPA),^[8] however, we modify the discussion in the final rule and continue to reach the same result in this proceeding, as discussed below.^[9]

3. Specifically, we either dismiss or disagree with most arguments raised on rehearing. We also provide further clarification on (1) states' use of tiered avoided cost pricing; (2) states' use of variable energy rates in QF contracts and availability of utility avoided cost data; (3) the role of independent entities overseeing competitive solicitations; (4) the circumstances under which a small power production qualifying facility (QF) needs to recertify; (5) application of the rebuttable presumption of separate sites for the purpose of determining the power production capacity of small power production facilities; and (6) the PURPA section 210(m) rebuttable presumption of nondiscriminatory access to markets and accompanying regulatory text, as further discussed below.

I. Background

A. Statutory Background

4. 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 (together, QFs).^[10] PURPA section 210(b) sets out the standards governing the rates purchasing utilities must pay to QFs.^[11] 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.” ^[12]

5. After establishing these standards, Congress then imposed statutory limits on the extent to which the PURPA Regulations may encourage the development of QFs pursuant to PURPA section 210(a), and also placed bounds on how the PURPA Regulations may implement the statutory provisions in PURPA section 210(b) governing QF rates.

6. The first such statutory limit appears in the final sentence of PURPA section 210(b). There, Congress established 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.” ^[13] As the Conference Report for PURPA (PURPA Conference Report) explains:

[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.^[14]

7. 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 is to be encouraged under the statute. This statutory 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.” ^[15] In order to comply with this statutory requirement that the capacity of all small power production facilities “located at the same site” not exceed 80 MW, the Commission is required to define what constitutes a “site.” In 1980, the Commission determined 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 qualification is sought.” ^[16] This approach, known as the “one-mile rule,” interpreted Congress's limitation of 80 MW located at the same site to apply to those affiliated small power production qualifying facilities located within one mile of each other that use the same energy resource.

8. Finally, Congress amended PURPA in 2005 to place further limits on the extent to which the PURPA Regulations may encourage QFs. Congress amended PURPA section 210 to, among other things, 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 (frequently described as the “mandatory purchase obligation”) if the QF has nondiscriminatory access to certain defined types of markets.^[17] This amendment reflected Congress's judgment that non-discriminatory access to these markets provided adequate encouragement for those QFs, such that the mandatory purchase obligation could be lifted.

9. Congress directed the Commission to amend the PURPA Regulations to implement this new requirement, which the Commission did in Order No. 688. In that order, pursuant to PURPA section 210(m), the Commission identified markets in which utilities would no longer be subject to the PURPA mandatory purchase obligation because QFs have nondiscriminatory access to such markets.^[18] Although not required by PURPA section 210(m), the Commission also established a rebuttable presumption for small QFs, which the Commission determined at that time were QFs at or below 20 MW, because they may not have nondiscriminatory access to such markets.^[19] In creating this rebuttable presumption, the Commission made clear that “we are not making a finding that all QFs smaller than a certain size lack nondiscriminatory access to markets.” ^[20]

B. Final Rule's Updating of the PURPA Regulations

10. In the final rule, the Commission amended the PURPA Regulations, principally with regard to the three statutory provisions described above: (1) The avoided cost cap on QF rates; (2) the 80 MW limitation applicable to the combined capacity of affiliated small power production QFs that use the same energy resource located at the same site; and (3) the termination of the mandatory purchase obligation for QFs with nondiscriminatory access to markets. The Commission stated that it was modifying the PURPA Regulations, based on demonstrated changes in circumstances that took place after the PURPA Regulations were first adopted, to ensure that the regulations continue to comply with PURPA's statutory requirements established by Congress.^[21]

C. Summary of Changes to the PURPA Regulations Implemented by the Final Rule

11. In the final rule, the Commission revised the PURPA Regulations based on the record of this proceeding, including comments submitted in the technical conference in Docket No. AD16-16-000 (Technical Conference),^[22] the record evidence cited in the Notice of Proposed Rulemaking (NOPR),^[23] and the comments submitted in response to the NOPR.^[24] These changes, including modifications to the proposals made in the NOPR, are summarized below.

12. First, the Commission granted states ^[25] the flexibility to require that energy rates (but not capacity rates) in QF power sales contracts and other LEOs ^[26] vary in accordance with changes in the purchasing electric utility's as-available avoided costs at the time the energy is delivered. 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.^[27]

13. Second, the Commission granted states additional flexibility to allow QFs to have a fixed energy rate and provided 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.^[28]

14. Third, the Commission implemented a number of revisions intended to grant states flexibility to set “as-available” QF energy rates based on market forces. The Commission established a rebuttable presumption that the locational marginal price (LMP) established in the organized electric markets defined in 18 CFR 292.309(e), (f), or (g) represents the as-available avoided costs of energy for electric utilities located in these markets.^[29] 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), the Commission permitted states 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' energy avoided costs.^[30]

15. The Commission granted states 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.^[31]

16. Fourth, the Commission provided states the flexibility to set energy and capacity rates pursuant to a competitive solicitation process conducted under transparent and non-discriminatory procedures consistent with the Commission's Allegheny standard.^[32]

17. Fifth, the Commission modified its “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, the Commission allowed 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). The Commission also allowed 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. The Commission added a definition of the term “electrical generating equipment” to the PURPA Regulations to clarify how the distance between facilities is to be calculated.^[33]

18. Sixth, the Commission allowed 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, the Commission clarified that such protests may be made to new certifications (both self-certifications and applications for Commission certification) but only to self-recertifications and applications for Commission recertifications making substantive changes to the existing certification.^[34]

19. Seventh, the Commission revised its regulations implementing PURPA section 210(m), which provide for the termination of an electric utility's obligation to purchase from a QF with nondiscriminatory access to certain markets. Under the PURPA Regulations before the final rule becomes effective, there is a rebuttable presumption that certain small QFs (i.e., those below 20 MW) may not have nondiscriminatory access to such markets. The Commission updated the rebuttable presumption threshold for small power production facilities (but not cogeneration facilities) from 20 MW to 5 MW and revised the PURPA Regulations to provide a nonexclusive list of examples of factors that QFs may cite to support an argument that they lack nondiscriminatory access to such markets.^[35]

20. Finally, the Commission clarified 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. The Commission prohibited states from imposing any requirements for a LEO other than a showing of commercial viability and a financial commitment to construct the facility.^[36]

21. The Commission explained that these changes will enable the Commission to continue to fulfill its statutory obligations under PURPA sections 201 and 210. The Commission emphasized 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 the final rule; the Commission stated that it does not by the final rule permit disturbance of existing contracts or LEOs or existing facility certifications.^[37]

22. On August 17, 2020, (1) EPSA, California Utilities, Northwest Coalition, One Energy Enterprises, and Thomas Mattson filed timely requests for rehearing of the final rule; (2) One Energy Enterprises, Public Interest Organizations, and Solar Energy Industries filed timely requests for rehearing and clarification of the final rule; and (3) California Utilities filed a timely request for clarification of the Final Rule. On September 1, 2020, California Public Utilities Commission (California Commission) filed an answer to California Utilities' request for clarification of the final rule.^[38]

II. Discussion

23. In this order, we sustain the final rule. Specifically, we either dismiss or disagree with most arguments raised on rehearing. We also provide further clarification on (1) states' use of tiered avoided cost pricing; (2) states' use of variable energy rates in QF contracts and availability of utility avoided cost data; (3) the role of independent entities overseeing competitive solicitations; (4) the circumstances under which a small power production QF needs to recertify; (5) application of the rebuttable presumption of separate sites in PURPA 210(m) proceedings; and (6) the PURPA section 210(m) rebuttable presumption of nondiscriminatory access to markets and accompanying regulatory text, as further discussed below.

A. Threshold Issues

1. Whether the Commission Appropriately Consulted With Representatives of Relevant State and Federal Agencies

a. Requests for Rehearing

24. Public Interest Organizations state that the final rule is flawed because the Commission failed to consult with state and federal officials as required by PURPA section 210(a).^[39] Public Interest Organizations argue that the Commission's actions to hold a technical conference and invite public comments, both of which involved participation from state and federal entities, are insufficient to meet this statutory requirement.^[40] Public Interest Organizations aver that these actions satisfy the statutory requirement to provide “notice and reasonable opportunity for interested persons (including State and Federal agencies) to submit oral as well as written data, views, and arguments” but that the Commission failed to satisfy what Public Interest Organizations claim is a separate and distinct requirement: To “consult[ ]” with representatives of state and federal officials.^[41] Public Interest Organizations argue that Congress included the word “consultation” in the statute to connote deliberations more formal and focused than the general notice and comment process and further assert that statutes and regulations routinely distinguish between the two.^[42] Public Interest Organizations contend that this lack of consultation has hamstrung the Commission and prevents the Commission from crafting informed policy.^[43]

b. Commission Determination

25. Public Interest Organizations' argument that the Commission failed to fulfill the consultation provision has no merit. First, we reemphasize the participation by state entities at the Commission's 2016 Technical Conference. Upon the Commission's open invitation,^[44] several state entities participated in that conference and filed post-conference comments, including members of state regulatory authorities and the president of the national association representing state commissions (NARUC).^[45] Second, several federal and state entities availed themselves of the opportunity to be heard via the NOPR's notice and comment process. More than 20 state entities, including state commissions, state consumer advocates, state attorneys general, governors, and others, submitted comments in response to the NOPR.^[46] In addition, NARUC submitted several filings throughout this process, and a group calling themselves State Entities—a diverse group including eight attorneys general and two state commissions—filed a combined comment on the PURPA NOPR; the NOPR was published in the Federal Register.^[47] Third, no state or federal entity has sought rehearing on this (or any other) basis.

26. In sum, throughout this process, the Commission repeatedly sought information and input from state and federal entities. As explained above, numerous state entities submitted comments or otherwise participated in the process and other state and federal entities had the opportunity to participate in the process. The Commission fully satisfied its consultation obligations.

2. Whether the PURPA Regulations Continue To Encourage QFs

a. Requests for Rehearing

27. Solar Energy Industries and Public Interest Organizations state that the Commission is required under PURPA section 210 to apply its regulations in a manner that encourages QFs and that it has failed to do so.^[48]

28. Solar Energy Industries argue that, in the final rule, the Commission failed to meet this statutory requirement in the following ways:

(1) Terminating a Qualifying Facility's right to elect a long-term energy rate when delivering energy under a long-term contract; (2) revising the long-standing regulations providing that a Qualifying Facility is not “at the same site” so long as the facilities are located more than one mile apart; and (3) allowing utilities within the boundaries of [Regional Transmission Organization or an Independent System Operator (RTO/ISO)] to seek a waiver of the [obligation] to purchase from small power production Qualifying Facilities larger than 5 MW despite the fact that few, if any, of such facilities have meaningful access to organized wholesale markets.^[49]

29. Solar Energy Industries claim that the Commission's assertion that the final rule “continue[s] to encourage the development of QFs consistent with PURPA” is unsupported by the record and erroneous.^[50] Solar Energy Industries argue that requiring utilities to interconnect with QFs and allowing QFs to purchase station power services is not new and is part and parcel of a utility's obligation to provide open access service today.^[51] Solar Energy Industries add that maintaining existing exemptions from the FPA and similar state and federal regulations is not helpful because other rule changes serve as severe obstructions to QF development in the first place.

30. Public Interest Organizations assert that the Commission incorrectly framed this issue as a set of false choices between encouraging QFs or violating statutory limits and encouraging QFs or never modifying its 1980 regulations.^[52] Public Interest Organizations argue that the Commission has inappropriately focused on whether the final rule eliminates all encouragement, rather than whether the final rule advances the goal of encouraging QFs in comparison to a suite of alternatives that could be more favorable to QFs. Public Interest Organizations add that the Commission must give effect to every relevant clause and use the significant space between encouraging and exceeding other statutory mandates, rather than following the conclusion in the final rule that PURPA itself limits the extent to which PURPA Regulations can encourage QFs, which would create a false dichotomy between meeting the mandate that QFs be encouraged and violating Congressionally defined limits.^[53]

31. Public Interest Organizations contend that the Commission is acting arbitrarily and capriciously because the record fails to support the Commission's claim that the changes in the final rule encourage QFs.^[54] Public Interest Organizations point to the Commission's statements in the final rule that these revisions will “lower payments from certain electric utilities to certain QFs,” will result in additional filing burdens, and may result in more protests being filed in opposition to QF filings.^[55] Public Interest Organizations argue that the Commission implicitly admitted that the majority of the changes do not encourage QF development when the Commission stated that “several of the changes” in the final rule provide encouragement.^[56]

32. Public Interest Organizations argue that the final rule is not the product of reasoned decision-making because the Commission's assertions that these revisions encourage QFs are insufficient, even if true.^[57] Public Interest Organizations state that in Order No. 69 the Commission identified three major obstacles and crafted its rules to address these barriers. Public Interest Organizations aver that, in contrast, the Commission conducted no such inquiry here to identify whether those barriers persist or new ones exist.^[58]

33. Public Interest Organizations claim that the Commission ignored evidence in the record.^[59] Public Interest Organizations state that the Commission dismissed as beyond the scope of the rulemaking evidence that the PURPA Regulations in place since 1980 fail to encourage QFs, yet at the same time rely on the strength of those rules to support its claim that the PURPA Regulations continue to encourage QFs.^[60] Public Interest Organizations argue that the Commission avoided consideration of this evidence by making the following three claims: (1) Relaxing some standards may actually induce some states to more robustly implement the rules; (2) evidence claiming that existing rules fail to encourage QF development should be dismissed as overstated; and (3) any lack of implementation of PURPA speaks to states' failures to implement, rather than gaps in the PURPA Regulations themselves.^[61]

34. Public Interest Organizations argue that examples of the Commission's failure to fully consider the record were that one of the commenters described the amendments to the Public Utility Holding Company Act of 1935 (PUHCA) in 2005 that effectively repealed that statute and that interconnection procedures stymie QF development. Public Interest Organizations argue that the Commission did not sufficiently consider this information in the record and, if it had, it would not have mistakenly asserted that related regulatory exemptions provided in the 1980 rules are sufficient to encourage QF development.^[62]

35. Public Interest Organizations contend that, because the Commission explicitly considered broad changes from Order No. 69 and addressed a broad range of topics in the final rule, the Commission improperly excluded consideration of evidence of barriers faced by QFs when it found that such evidence is outside the scope of this proceeding.^[63]

36. Public Interest Organizations argue that the Commission was misguided in its reliance on U.S. Energy Information Administration (EIA) data showing that some states with the highest rates of QF penetration are located in non-RTO regions to support the claim that evidence of barriers to QFs in such regions are overblown.^[64] Public Interest Organizations aver that three states (North Carolina, Idaho, and Utah) skew the data with successful outcomes for QFs, while PURPA remains largely irrelevant in the 47 other states. Public Interest Organizations add that reliance even on these three states is in error because these states saw significant QF penetration due to long-term fixed energy rates, which the Commission is now no longer requiring, claiming that, even in Idaho, barriers have since been erected with a subsequent cessation in QF development.^[65]

37. Public Interest Organizations assert that the Commission inappropriately dismissed barriers to QF development as matters only relevant to state implementation or PURPA enforcement dockets.^[66] Public Interest Organizations add that the Commission's claim that more relaxed standards will lead to more robust state implementation is speculative, internally contradictory, and ignores relevant evidence.^[67]

38. Public Interest Organizations argue that, even if the Commission properly considered the full record, the Commission's finding that the revised rules encourage QFs is arbitrary and capricious.^[68] Public Interest Organizations restate their concern that providing more flexibility will not lead to more robust PURPA implementation by states. Public Interest Organizations contend that the changes adopted in the final rule overwhelmingly cut in favor of utilities and against encouraging QFs and that none of the revisions require regulators to strengthen incentives or eliminate burdens on QF development.^[69] Public Interest Organizations aver that these changes amount to lowering the federal floor, therefore reducing QF bargaining power, even if state regulators implement the rules in good faith. Public Interest Organizations add that, contrary to the Commission's assertions in the final rule, leaving intact the requirement for full avoided costs is insufficient to continue to encourage QFs, especially in the face of new barriers erected by the final rule.^[70]

b. Commission Determination

39. Contrary to claims that the PURPA Regulations as revised do not encourage QFs, the PURPA Regulations as revised in the final rule continue as a whole to encourage the development of QFs consistent with the statutory limits on such encouragement, as explained below.^[71]

40. Public Interest Organizations improperly frame the encouragement analysis. In Public Interest Organizations' view, the encouragement standard should be analyzed on the basis that a revision is inadequate in encouraging QFs if there exist alternative revisions that are more favorable to QFs.^[72] We reject this premise. PURPA requires the Commission's regulations to encourage QFs, but that is not all that PURPA says. PURPA also requires that the Commission prescribe no rule requiring that states set payments to QFs that exceed avoided costs and PURPA requires that qualifying small power production facilities do not exceed 80 MW. Furthermore, in the final rule, the Commission strikes a balance among the interests of all relevant stakeholders, including not just the selling QFs, but also the purchasing electric utilities and, moreover, consumers, consistent with PURPA.

41. Regarding QF rates, the final rule provides states further flexibility to better enable states to implement PURPA's statutory obligation that QF rates not exceed the purchasing electric utility's avoided costs. We acknowledge that different states have implemented PURPA differently, but such differences are not prohibited by the statute. If parties believe that a state has failed to implement the PURPA Regulations consistent with their terms, then these parties may bring an enforcement petition before the Commission or other fora.^[73] But just because parties are unsatisfied with some states' implementation of PURPA to date ^[74] does not preclude the Commission from making the revisions to its PURPA Regulations adopted in the final rule.

42. In the final rule, the Commission complied with PURPA's requirement that rates not exceed avoided costs by, for example, allowing states to implement variable avoided cost energy rates if they so choose.^[75] The Commission also continued to fulfill its obligation under PURPA to encourage the development of QFs. Specifically, with the additions from the final rule, the PURPA Regulations continue to encourage QFs by combining elements that include, among other things: (1) Providing the potential for increased transparency of avoided cost determinations under competitive solicitations or competitive market prices; (2) continuing to provide the ability for QFs to be exempt from most of the provisions of the FPA and PUHCA and certain state laws and regulations; (3) continuing to grant QFs special rights to supplementary and backup power; (4) providing extra benefits and rights for QFs 5 MW or smaller and especially those smaller than 100 kW; and (5) clarifying that states may only impose objective and reasonable criteria, limited to demonstrating commercial viability and financial commitment, as prerequisites to QF LEO formation that states may impose, which ensures that the purchasing utility does not unilaterally and unreasonably decide when its obligation arises.^[76] These elements of the PURPA Regulations, among others, will continue to provide rules that, as a whole, encourage QF development.

43. We disagree with Public Interest Organizations' assertion that there is insufficient evidence to support the Commission's conclusion that providing more flexibility to states may better enable states to encourage QF development. As one example, Idaho State Commissioner, Kristine Raper, stated during the 2016 Technical Conference that “[s]tate Commissions do not have enough tools in the toolbox” and that this lack of flexibility caused Idaho to amend its regulations to award only two-year standard contracts for QFs, rather than twenty-year standard contracts with periodic updates to the avoided cost rate.^[77] Therefore, it was reasonable for the Commission to conclude that the new flexibility granted by the final rule may lead states to lengthen the contract period, which could encourage QF development. Additionally, the new competitive market price options should be less burdensome for all involved, compared to the administrative determination of avoided cost rates, because the new options rely on transparent, publicly available competitive prices or transparent and non-discriminatory competitive solicitations.^[78] QFs may spend less time and money pursuing their interests in a competitive market price environment than they previously did in the administrative determination process. Finally, to the extent energy prices rise at some point in the future, QFs with variable rates would necessarily benefit.

44. We disagree with Public Interest Organizations' claim that the Commission has failed to adequately consider the evidence that states have achieved various levels of PURPA implementation. Public Interest Organizations have overly relied on the examples of North Carolina, Idaho, and Utah, which they contend have unusually high levels of QF development. We are committed to promoting PURPA's central feature of cooperative federalism.^[79] In the final rule, the Commission provided states further flexibility to implement this statutory obligation as most appropriate and consistent with the terms of the statute.

45. We disagree with Public Interest Organizations that retaining the exemption from PUHCA is unimportant or that PUHCA has been repealed. While now more focused on record-keeping obligations,^[80] PUHCA remains a regulatory obligation for entities, including entities that seek QF status retroactively. By granting QFs retroactive status when they had not yet certified but should have done so previously, the Commission has relieved those entities of PUHCA's record-keeping obligations (similar to other federal and state exemptions), thereby further encouraging the development of QFs.^[81] Similarly, contrary to Public Interest Organizations' request for rehearing, alleged deficiencies in state-administered QF interconnection procedures are not within the scope of this rulemaking.

B. QF Rates

1. Overview

46. PURPA requires the Commission to promulgate rules to be implemented by the states that “shall insure” that the rates electric utilities pay for purchases of electric energy from QFs meet the statutory criteria, including that “[n]o such rule . . . shall provide for a rate which exceeds” the purchasing utility's “incremental cost . . . of alternative electric energy.” ^[82] 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; ^[83] and, as noted above, (3) not exceed “the incremental cost to the electric utility of alternative electric energy,” ^[84] 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.” ^[85] 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,” ^[86] although the term “avoided cost” itself does not appear in PURPA.

47. In addition, the PURPA Regulations in effect before the final rule provide a QF two options for how to sell its power to an electric utility. The QF could 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).^[87] Alternatively, the QF could choose to sell pursuant to a LEO (such as a contract) over a specified term.^[88]

48. If the QF chooses to sell under the second option, the PURPA Regulations in effect before the final rule 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; ^[89] or (2) the purchasing electric utility's avoided cost calculated and fixed at the time the LEO is incurred.^[90]

49. 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. The Commission reasoned, however, 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.” ^[91] 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.” ^[92]

50. 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 a request for proposals (RFP), with processes designed to ensure that the competitive solicitation is performed in a transparent, non-discriminatory fashion.^[93]

51. 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.^[94]

52. In the final rule, the Commission adopted these proposals, with certain modifications.

2. LMP as a Permissible Rate for Certain As-Available Avoided Cost Rates

53. In the final rule, the Commission revised 18 CFR 292.304 to add subsections (b)(6) and (e)(1). In combination, these subsections 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.^[95]

54. The Commission adopted 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.^[96]

55. The Commission found 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.^[97]

56. The Commission recognized 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, the Commission found 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.^[98]

57. The Commission disagreed with the arguments made by Union of Concerned Scientists,^[99] NIPPC, CREA, REC, and OSEIA,^[100] and Public Interest Organizations ^[101] 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. The Commission recognized that, all other things being equal, self-scheduling of resources may impact market clearing prices. The Commission found that this potential price effect, however, does not mean that the LMP is not an accurate measure of avoided energy costs. The Commission stated that, 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, the Commission found that 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.^[102]

58. The Commission rejected the related request for clarification made by Solar Energy Industries,^[103] 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. The Commission found that, 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.^[104]

59. The Commission rejected 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.^[105] The Commission stated that it only addressed as-available energy and as-available energy prices by definition are short term.^[106]

a. Requests for Rehearing

60. Public Interest Organizations argue that it was erroneous for the Commission to make a “rebuttable presumption” that the state or nonregulated utility can use the LMP as “a rate for as-available qualifying facility energy sales to electric utilities located in a market defined in [18 CFR] 292.309(e), (f), or (g).” ^[107] Public Interest Organizations claim that the Commission acted contrary to precedent that limits an administrative agency's authority to establish presumptions by creating a rebuttable presumption that LMP is the avoided cost price “for as-available qualifying facility energy sales to electric utilities located in” an organized market.^[108] Public Interest Organizations claim that the presumption unlawfully shifts the burden under the statute and is not based on record evidence showing that avoided cost energy prices are necessarily the same as the LMP, adding that there are no alternative explanations for a utility ever to incur energy prices that exceed the LMP.^[109]

61. Public Interest Organizations argue that, because the final rule stated 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,” the Commission cannot make the necessary finding under the statute that the LMP is, per se, the full avoided energy cost.^[110] Public Interest Organizations contend that, to create the LMP presumption lawfully, the Commission must have substantial record evidence showing that “a sound and rational connection between” the LMP and the full avoided cost of each utility (as necessary to ensure full encouragement and nondiscrimination) is “so probable that it is sensible and timesaving to assume” it unless disproven, arguing that there are no alternative explanations for a conclusion contrary to the presumption.^[111] Public Interest Organizations maintain that the record contains numerous examples of instances in which a utility in an organized market incurs costs greater than the LMP.^[112]

62. Public Interest Organizations claim that the Commission relies on an implicit and absolute connection between price and cost by repeatedly conflating the cost to buy in the day ahead market with the cost of energy to the utility.^[113] Public Interest Organizations maintain that, even when a utility is simultaneously selling into and buying energy from the day ahead market, the utility's costs for energy are the higher of the market price or the cost to produce or procure the power it sells into the market. Public Interest Organizations refer for example to a utility that dispatches its own generation at $35/MWh, sells into the market at $20/MWh, and then buys back at $20/MWh to meet load; the LMP price is $20, but the cost to the utility for energy is $35.^[114]

b. Commission Determination

63. We reject the arguments against establishing the rebuttable presumption that LMP reflects avoided costs for as-available energy. We disagree with Public Interest Organizations that the relevant precedent prohibits establishing a rebuttable presumption. Indeed, the courts have made clear that “[u]nder the APA, agencies may adopt evidentiary presumptions provided that the presumptions (1) shift the burden of production and not the burden of persuasion . . . and (2) are rational.” ^[115] The final rule did not shift the burden of persuasion, only the burden of production. We emphasize that LMP typically reflects a purchasing utility's actual avoided energy costs.^[116]

64. However, we also acknowledged in the final rule that there may be instances when LMP does not reflect a purchasing utility's avoided cost and that is why the Commission allowed the presumption to be challenged. Requiring an entity challenging the state's use of the presumption in the first instance to show why the state was wrong does not negate the legal requirement that, unless the parties agree to another rate, the rates for purchases in a QF contract must equal a purchasing utility's avoided costs. If so challenged, a state would need to address the challenging entity's arguments in order to demonstrate that LMP represents the purchasing utility's avoided costs. Therefore, the Commission did not change the burden of persuasion.^[117] Moreover, in the final rule, the Commission appropriately established a rebuttable presumption to frame how it (and, potentially, reviewing courts) would evaluate challenges to states setting avoided costs at LMP.^[118]

65. We also disagree with Public Interest Organizations' assertion that the Commission failed to provide adequate support for why the presumption is rational in organized markets. As explained in the final rule, the Commission relied on a variety of supporting facts, including the fact that LMP definitionally reflects the true marginal cost of production of energy, taking into account physical system constraints, and other listed benefits of LMP.^[119] Because LMP is likely to reflect the true marginal cost of energy in the vast majority of cases for the reasons discussed in the final rule, it is “so probable that it is sensible and timesaving to assume” ^[120] that LMP for a particular utility is an appropriate measure of the utility's avoided costs for as-available energy, unless disproven in a particular case. We leave open for specific cases to determine the appropriateness of using a particular LMP such that a QF could rebut the presumption that LMP is appropriate.^[121] Regarding Public Interest Organizations' claims that numerous examples in the record support their argument that utilities often incur costs greater than the LMP, we disagree. Public Interest Organizations' assertion is based on the evidence of self-scheduling they supplied in NOPR comments, and their assertion that this self-scheduling behavior is enabled by out-of-market subsidization through retail rate cost recovery.^[122] However, Public Interest Organizations have provided no proof that such out-of-market subsidization takes place and there are legitimate reasons for self-scheduling that are consistent with rational market participant behavior. For example, generation units with start-up and shut-down sequences longer than a single market commitment period may decide to self-schedule at a loss in one period in order to earn profits in other periods that they expect to exceed the temporary loss. Absent proof that retail rate subsidization is the dominant driver for self-scheduling behavior, there is little evidence in the record that purchasing utilities often incur costs greater than the LMP. Nevertheless, entities may seek to rebut the presumption if, for example, the RTO/ISO market is affected by persistent price distortions that are not the result of legitimate market participant behavior (such as persistent self-scheduling at a loss that is proven to be the result of out-of-market subsidization, and thus demonstrates that the utility regularly incurs costs that exceed LMP).

3. Tiered Avoided Cost Rates

a. Request for Clarification

66. California Utilities request that the Commission clarify that it is no longer the Commission's policy or intent to permit states to subsidize QFs by the use of “tiered” avoided costs.^[123] California Utilities request that the Commission find that avoided cost rates may not be based only on the costs of a subset of facilities from which a state has mandated purchases or only on facilities that meet state-determined characteristics such as the facilities' use of a renewable fuel. As such, California Utilities further request that the Commission find that the United States Court of Appeals for the Ninth Circuit decision in CARE v. CPUC ^[124] as well as certain aspects of the Commission's orders ^[125] are no longer valid precedent.

67. According to California Utilities, Commission precedent on avoided costs for tiered resources is as follows for the following periods:^[126]

1978-2010: All resources must be used to set avoided costs.^[127]

2010-2019: States were permitted to adopt tiered avoided costs based on the costs of specific types of QFs, if the state had an unmet purchase mandate.^[128]

April 2019-2020: Tiered avoided costs mandated within the Ninth Circuit if state procurement mandates are unmet.^[129]

2020: The Commission returns to an all-resource approach and rejects using PURPA to subsidize QFs that are not otherwise financeable.^[130]

68. California Utilities request clarification for the following reasons: (1) The Commission's failure to state in the final rule that it is overruling the CPUC cases or CARE v. CPUC; (2) the need for the Commission to defend a change in policy before an appellate court that will ask why the Commission no longer supports the policy it espoused in CPUC 2010; (3) the regulation that lists the factors a state may consider in determining avoided cost (18 CFR 292.304, which have been moved to 18 CFR 292.304(e)(2)) have not changed, which leaves them open to misinterpretation; and (4) the words “taking into account the operating characteristics of the needed capacity” ^[131] regarding competitive solicitations, although clarified by Paragraph 433 of the final rule, could be misread as allowing avoided costs for QFs with “operating characteristics” such as renewable fuel, cogeneration technology, under a certain size, or at specific locations (i.e., located on the distribution system).^[132]

69. California Utilities maintain that adding the following language after 18 CFR 292.304(b)(5) will ensure that states will not use tiered avoided cost rates under PURPA as a vehicle to subsidize certain state-favored resources: “(6) Rates for purchases may not be based on an avoided cost set by determining the cost of procuring energy and/or capacity to fulfill a State regulatory authority or non-regulated electric utility mandate to procure energy and/or capacity from resources using a specific fuel type, using a specific technology, of a particular size, and/or located only on local distribution systems.” ^[133]

70. California Commission disagrees that the final rule overrules CPUC 2011 and the Commission's earlier precedent. California Commission contends that the Commission's 1995 precedent prohibits assuming that “the utility can provide the capacity and generate the energy itself (i.e., through the establishment of the utility benchmark price), only to exclude the utility, cogenerators, and other resources from ultimately being able to supply the capacity and energy, by segmenting the portfolio and permitting only certain QFs to bid in certain segments against the benchmark and ultimately produce a higher-than-avoided-cost rate.” ^[134] California Commission interprets Commission precedent as permitting a state to determine what capacity a utility would be avoiding, to decide from which generators a utility could purchase to satisfy state programs, and to set tiered avoided cost rates based on those qualifying resources.^[135]

71. California Commission asserts that the final rule's requirement that competitive solicitations be open to all sources was intended to prevent discrimination against QFs and did not preclude states from using tiered avoided cost rates.^[136] California Commission argues that, contrary to California Utilities' assertion, the final rule does not treat tiered rates as impermissible subsidies to QFs. California Commission contends, instead, that the final rule permits states to continue recognizing non-energy benefits outside the context of PURPA payments.^[137] California Commission requests that, with respect to CARE v. CPUC' s holding that a state that uses QFs to meet a renewable portfolio standard (RPS) must set avoided cost only on resources that could satisfy that RPS, the Commission clarify that “operating characteristics that qualify a QF to meet a state's [RPS] are energy-related benefits that can be the basis for determining avoided costs and multi-tier pricing, as opposed to benefits unrelated to their production of energy—akin to renewable energy credits—that may not be compensated by rates under PURPA.” ^[138]

b. Commission Determination

72. We deny California Utilities' request for clarification. Although Commission precedent does not allow the use of non-operational externalities, such as environmental benefits, in setting avoided cost rates, PURPA neither requires nor prohibits states from establishing tiered procurement (and thus tiered pricing), such as California does. California's tiered supply procurement requirements reflect decisions regarding utility generation procurement (e.g., by specific fuel type or technology) that are within the boundaries of a state's traditional authority. Once such tiered generation procurement requirements have been established by a state, if a QF qualifies for a particular generation procurement tier, it is reasonable to assume that the mandatory QF purchase will displace resources otherwise in that tier; therefore, the rates for that tier are in fact the cost avoided by the purchasing utility when it instead purchases from that QF.

73. We cannot overrule a Court of Appeals decision, as California Utilities suggest. In addition, California Utilities have not adequately supported that there is any conflict between the final rule and the precedent they cite.^[139] Therefore, we decline to add additional regulatory language to address the issues they raise.

4. Providing for Variable Energy Rates in QF Contracts Is Consistent With PURPA

74. As explained above, if a QF chooses to sell energy and/or capacity pursuant to a contract, the PURPA Regulations in effect before the final rule provide the QF the option of receiving the purchasing electric utility's avoided cost calculated and fixed at the time the LEO is incurred.^[140] 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 “with regard to return on investment in new technologies necessary for the QF to obtain financing” ^[141] 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.” ^[142] Further, the Commission agreed with the “need for certainty with regard to return on investment in new technologies,” and stated its belief that any overestimations or underestimations “will balance out.” ^[143]

75. 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 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 cost rates (assuming there are 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.^[144]

76. In the final rule, the Commission adopted without modification the NOPR variable rate proposal. The Commission found that setting QF avoided energy cost contract and 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. The Commission explained that a variable avoided cost energy rate approach is a superior way to ensure that payments to QFs equal, but do not exceed, avoided costs.^[145] The Commission stated that it is inevitable that, over the life of a QF contract or other LEO, a fixed avoided cost energy rate, such as that used in past years, will deviate from actual avoided costs.^[146]

77. The Commission found that the record justifies its conclusions that long-term forecasts of avoided energy costs are inherently imperfect and that states should be given the flexibility to rely on a more reliable variable avoided cost energy rate approach. Further, the Commission pointed to instances where overestimates and underestimates have not balanced out.^[147] The Commission found that, 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. Given that PURPA section 210(b) prohibits the Commission from requiring QF rates in excess of avoided costs, the Commission explained that record evidence supports its 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.^[148]

78. The Commission found that the variable avoided cost energy rate provision is not based on any determination that the Commission's rules no longer should encourage QF development. The Commission found, instead, that it was 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 with Congress's clear requirement in PURPA that the Commission may not require QF rates in excess of a purchasing utility's avoided costs.^[149]

79. Opponents of variable avoided cost energy rates urged the Commission to continue placing this risk on the customers of electric utilities, as in the past, by retaining the option for QFs to fix their avoided cost energy rates in their contracts or LEOs notwithstanding record evidence that fixed energy rates compared to actual avoided costs have not balanced out over time. But, after consideration of the record, the Commission decided instead to allow states the flexibility to require variable avoided cost energy rates in QF contracts and LEOs and thereby reduce the risk to customers. The Commission found that its 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 PURPA Conference Report that customers of utilities not be required to subsidize QFs.^[150]

80. The Commission found that 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 Commission found that, while Congress recognized that the better measure of avoided cost in certain scenarios might be the cost of the alternative fossil fuel unit that would not be run at that later date,^[151] nothing in the section of the PURPA Conference Report quoted by opponents of the variable energy rate proposal 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. The Commission further found that nothing in the revision being implemented in the 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.^[152]

81. The Commission described the variable avoided cost energy rate provision as not running afoul of the Freehold Cogeneration and Smith Cogeneration cases cited by Harvard Electricity Law.^[153] The Commission described those decisions, which overturned state avoided cost determinations allowing for changes in QF rates, as based on the provision in the original PURPA Regulations giving QFs the option to select contracts with long-term fixed avoided cost rates.^[154] The Commission explained that 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.

82. The Commission found that it was 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).^[155] Indeed, the Commission found that the regulation it adopted does not subject QF rates to any examination whatsoever of the costs incurred by QFs in producing and selling power. Rather, the Commission stated that the variable avoided cost energy rate provision applicable to QF contracts and other LEOs that the Commission adopted in the final rule sets QF rates based on the avoided costs of the purchasing utility. The Commission stated that this variable avoided cost energy rate provision cannot be characterized as imposing utility-style regulation on the QFs themselves.^[156]

83. Finally, the Commission determined that state regulators may not change rates in existing QF contracts or other existing LEOs.^[157] The Commission explained that, by its terms, the variable avoided cost energy rate provision applies only prospectively to new contracts and new LEOs entered into after the effective date of the final rule. The Commission emphasized that nothing in the final rule should be read as sanctioning the modification of existing fixed-rate QF contracts and LEOs.^[158]

a. Whether the Current Approach Has Resulted in Payments to QFs in Excess of Avoided Costs

84. In the final rule, the Commission gave 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, 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 and that this was a result prohibited by PURPA section 210(b). The Commission found that the record evidence demonstrates 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, the Commission noted that commenters have provided additional examples of such overpayments.^[159] The Commission explained that such evidence persuaded it 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.^[160]

85. In the final rule, the Commission found, as acknowledged in Harvard Electricity Law's NOPR comments, that 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.” ^[161] The Commission explained that it was this “manifest record of failure” including evidence in the record that the failure has been at the expense of consumers that motivated the Commission to make the change adopted in the final rule.^[162]

86. The Commission also found that challenges to the idea that fixed avoided cost energy rates in QF contracts and other LEOs have exceeded actual avoided costs largely either conceded that overestimations have occurred while arguing that such overestimations impacted purchasing electric utilities just as much as QFs or attempted to argue that such overestimations were temporary or unusual.^[163]

87. First, the Commission determined that the record evidence demonstrates that, contrary to the Commission's finding in 1980, overestimations and underestimations of future avoided costs may not even out.^[164] Consequently, the Commission found that its determination in 1980, based on the record at that time, does not preclude the Commission from relying on new record evidence showing a change in circumstances since 1980 to revise the 1980 rule.

88. The Commission agreed 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.^[165] But the Commission explained that these overestimations are 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 avoided energy costs but this decline was not reflected in the QFs' fixed contract rates that remained at their previous levels.^[166]

89. Similarly, the Commission found that arguments that electric utilities also based resource acquisitions on incorrect forecasts of natural gas prices ^[167] ignore a key distinction between utility rates and fixed QF rates. As the Commission explained, electric utilities may have relied on incorrect natural gas price forecasts to justify the timing and type of their resource acquisitions, as commenters assert. However, the Commission found that, once an electric utility resource decision was made, electric utilities' cost-based rate regimes typically obligated them 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. The Commission found that, 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, the Commission determined that cost-based electric utility energy rates declined as the cost of natural gas and other fuels and purchased power declined.^[168]

90. The Commission also disagreed 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.^[169] The Commission recognized 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, the Commission found that competitive market prices in general should reflect the marginal avoided energy costs of utilities with access to such markets and that those markets generally reflect the marginal cost of energy in the region.^[170] The Commission further found that the 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.^[171]

91. The Commission acknowledged that energy prices may increase in the future but explained that 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. The Commission also noted that, if energy prices do in fact increase, variable avoided cost energy pricing would protect and even benefit the QF itself because 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.^[172]

92. The Commission noted that, 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.^[173]

93. The Commission found that the expert testimony cited by the SC Solar Alliance, that the witness “wouldn't put a whole lot of weight in [Duke's estimate],” ^[174] does not address Duke's calculation of past overpayments. Rather, the Commission described the witness as 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.^[175] The Commission noted that 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.” ^[176] The Commission explained that it was these overpayments due to unforeseen declines in natural gas prices that formed an important basis for the Commission's determination in the final rule to now give states the flexibility to require variable avoided cost energy rates in QF contracts and LEOs.^[177]

94. The Commission also emphasized that it did not rely on the Concentric Report to support the variable energy avoided cost provision adopted in the final rule. The Commission determined that 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.^[178]

i. Requests for Rehearing

95. EPSA argues that the Commission erred in relying on the idea that overestimates and underestimates have not balanced out because the Commission has neither validated these allegations, nor assessed whether the overestimations of avoided cost have, in fact, balanced out.^[179] Public Interest Organizations argue that the Commission's determination to permit variable energy rates to mitigate the risk of alleged overpayments to QFs is arbitrary and capricious and unsupported by substantial evidence.^[180] Likewise, Solar Energy Industries assert that there is a lack of evidence to conclude that protecting electric consumers warrants terminating the QF's right to elect long-term fixed energy rates.^[181] EPSA argues that over- and under-estimations over time is irrelevant absent evidence that avoided cost forecasts are inherently less accurate than the cost estimates used to set the purchasing utilities' own rates.^[182]

96. Public Interest Organizations contend that the Commission incorrectly defined avoided costs and incorrectly defined avoided costs with short run prices.^[183] Public Interest Organizations assert that the Commission did not respond to arguments that historic avoided cost rates “have likely underestimated utilities' actual `but for' avoided costs, resulting in underpayment rather than overpayment to QFs.” ^[184] They also assert that “there is no evidence in the record showing that utilities would have—as the Commission assumed—relied on short term energy markets rather than entering into long-term contracts based on similarly speculative avoided cost estimates or building new generating resources,” and that “utilities often build and operate generating resources at costs well above their purported avoided cost rate.” ^[185] Public Interest Organizations argue that the Commission incorrectly assumed that the cost for energy that a utility would incur “but for” a QF is the short run cost and that utilities never lock in energy costs by constructing their own energy resources, executing long term fuel contracts or executing long term energy supply contracts. Public Interest Organizations claim that, if a utility ever locks in energy costs instead of relying on the short run energy or fuel markets for supply, a QF can displace those long-run costs rather than the short run cost, adding that, contrary to the Commission's assertions, avoided energy rates paid to QFs are significantly lower than utilities' true generation costs.^[186]

97. Public Interest Organizations argue that the overestimations upon which the Commission relied “were incorrectly calculated based on long-run contract prices and short-run costs, rather than the long-term QF price and the cost of the resource that the utility would have acquired but for the QFs.” ^[187] Public Interest Organizations contend that the Commission assumed without any evidence that those utilities would have built their own energy resources, executed long term fuel contracts, or executed non-QF power purchase agreements without the QF purchases. Public Interest Organizations assert that, while QF contracts entered into before 2007-2009 might not have accounted for declining natural gas prices, which caused these contracts to be higher than short term market prices, alternative long-term commitments those utility might have made without QF purchases might also not have accounted for those natural gas price declines. Public Interest Organizations reason that avoided costs therefore should be based on those alternative sources that a utility would have purchased but for QF purchases rather than short run market prices and the Commission lacked evidence to assert that “utilities' actual incremental cost of generating energy `but for' QF generation exceeds rates QFs have received through long-term fixed energy rate contracts.” ^[188]

98. Public Interest Organizations maintain that the Commission lacked evidence to assert that natural gas price declines would have decreased the prices of utility power purchase agreements, energy supply investments, fuel contracts and other long-term energy supply commitments. Public Interest Organizations contend that the failure to predict natural gas price declines did not entail any energy cost savings, yielded energy price increases passed along to customers, and rendered uneconomic utilities' long-term coal plant investments, coal contracts, and power supply contracts to ensure long term energy supply. Public Interest Organizations assert that the Commission's conflating short-run market prices with utility supply costs excludes supply beyond the day-ahead market and costs above market price. Public Interest Organizations claim that the Commission did not address concerns that vertically integrated utilities' monopoly status ensures that utilities operate their own plants at above-market prices and would have added their own new generation but for QF purchases. Public Interest Organizations assert that, even though QF prices may have been higher than market prices, that simply reflects foregone utility windfall profits and not costs that customers would otherwise have paid.^[189]

99. Public Interest Organizations argue that the Commission was internally inconsistent in defending its decision to presumptively consider competitive market prices like LMP equal to full avoided cost in conjunction with its determination to allow states to eliminate fixed energy rate contracts.^[190] Public Interest Organizations contend that, in permitting competitive market prices like LMP to set avoided costs, the Commission also inconsistently acknowledged that utilities incur long term energy costs that exceed those prices and that the competitive market prices are only being used to set the as-available short term avoided cost rates instead of long-run energy costs that can be avoided with long-term QF contracts.^[191] Public Interest Organizations claim that the Commission permitted a price determined at the time of delivery to set the price for long-term contracts, even though the Commission acknowledged that long term QF energy supply avoids alternative long term energy supply commitments and costs that are not reflected in the short run LMP or market hub price.^[192]

100. EPSA argues that the Commission's regulations and precedent contradict reliance on the idea that overestimates and underestimates have not balanced out.^[193] EPSA points out that 18 CFR 292.304(b)(5) expressly provides that, “[i]n 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.” ^[194]

101. EPSA asserts that, because the final rule did not modify, much less eliminate, 18 CFR 292.304(b)(5), which allows states to retain the fixed energy rate contract option, it is impossible to claim that the fixed energy rate contract option conflicts with the avoided cost cap and that the Commission cannot take a position that is at odds with the terms of its own regulations.^[195]

102. According to Solar Energy Industries, there is no indication in the record that any retail rates paid by electric consumers fluctuate based on the purchasing utility's obligation to purchase from QFs. Solar Energy Industries also argue that, for utilities with stated retail rates, there is no evidence to suggest that these rates will be reduced in any manner in the event the state utilizes the “flexibility” provided by revised Section 292.304(d), unless the Commission mandates otherwise.^[196] Solar Energy Industries add that the evidence in the record of alleged overpayments was both flawed and not adequately supported and thus does not support the contention that overpayments and underpayments did not balance out for an extended period of time.^[197]

103. Solar Energy Industries argue that, to the extent that existing methodologies in some states have produced inaccurate forecasts of long-run avoided costs, the solution is better methodologies—not an abandonment of long-run marginal costs.^[198]

ii. Commission Determination

104. As an initial matter, it is beyond any reasonable question that the Commission's determination to give the states the flexibility to require variable energy rates in QF contracts is within the Commission's authority under PURPA. By definition, such a rate compensates the QF at a rate reflecting the energy costs avoided by the purchasing utility as a result of its purchase of energy from the QF. Moreover, a utility's avoided purchased energy costs constantly change over the term of a contract as the utility's marginal resource changes due to changes in load, changes in the availability of alternative resources, and changes in the availability of the marginal resource. The avoided energy cost also changes with fluctuations in fuel use at different loading levels and with changes in fuel costs. Consequently, a variable energy contract rate by definition would more accurately reflect the utility's avoided energy costs than a fixed contract that does not vary over the length of a multi-year contract.

105. As a result, there is no question but that the Commission could have imposed a variable energy contract requirement when it promulgated the PURPA Regulations in 1980 instead of requiring fixed energy contract rates. The only question in this proceeding is whether the Commission has adequately supported its holding in the final rule to change the determination made in 1980 and instead give the states the flexibility to require variable energy contract rates.^[199] In addition, because the Commission's revision to the fixed energy rate requirement is based on changed circumstances since the issuance of the PURPA Regulations in 1980, we must provide “a reasoned explanation . . . for disregarding facts and circumstances that underlay or were engendered by the prior policy.” ^[200] As we explain below, we disagree with assertions that we have not provided such an explanation.

106. We disagree with the arguments raised on rehearing that there was insufficient evidence of overestimations. The Commission explained in the final rule why overestimations and underestimations of avoided costs had not balanced out.^[201] Broad price declines over time throughout the energy industry show that long-term fixed price QF contracts likely exceeded the avoided energy costs at the time of delivery for extended periods of time; thus, it is not necessary to confirm every allegation of a lack of balance in the past or every estimation of prices and costs.^[202] But even had there been less evidence of lack of balance over time,^[203] there was sufficient evidence for the Commission to conclude that the Commission's assumption in 1980 may not be the best way to ensure compliance with PURPA. Allowing a state to set a variable avoided cost energy rate could better avoid that outcome. In the context of long-term fixed QF rates, given evidence of overestimations, the statutory avoided cost cap may be better met if the rates may be varied over time to ensure they stay within the requirements of PURPA. Moreover, as stated in the final rule, to the extent energy prices increase over time, QFs could benefit from that variability.^[204] Therefore, it was well within the Commission's authority under PURPA, and the Commission had sufficient evidence, to provide a tool states can use to ensure that the avoided cost rates stay within the requirements of the statute and not be based on an assumption that over-recoveries balance out with under-recoveries.

107. States previously had little ability to address the potential for overestimations over the term of a QF contract, which caused some states to respond by adopting shorter contract terms. In the final rule, the Commission did not determine that any particular QF contracts violated the avoided cost cap and did not change its prior determination that PURPA does not “require a minute-by-minute evaluation of costs which would be checked against rates established in long term contracts between qualifying facilities and electric utilities.” ^[205] Instead, the Commission acted reasonably to better ensure that, over the term of a contract, QF rates do not exceed a utility's avoided costs. The Commission achieved this goal by providing the states with a tool that allows them to address the potential that, over the term of a contract, contract rates may exceed a purchasing utility's avoided costs determined at the time of delivery. Providing this tool to the states ensures that they are not required to set rates that exceed avoided costs. Moreover, this tool gives effect to PURPA's requirement that rates paid to QFs be just and reasonable to the consumers of the electric utility and in the public interest.^[206]

108. The Commission emphasized that the final rule is prospective, thereby protecting existing contracts. We find no merit in EPSA's argument that the grant of flexibility to states in the final rule to set variable avoided cost energy rates is inconsistent with 18 CFR 292.304(b)(5), which provides: “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.” ^[207]

109. Nothing in the final rule is inconsistent with this regulatory provision. The final rule gives states the flexibility to continue to require fixed energy rates for the term of a QF's contract, and this regulatory provision continues to be necessary to make clear that such rates are permitted. The provision does not apply to QF contracts where the energy rate is not fixed based on estimates of avoided costs but instead varies with estimates of avoided costs at the time of delivery.

110. We also disagree with Public Interest Organizations that, in permitting states to set a variable avoided cost energy rate, the Commission ignored utilities' long-run avoided costs.^[208] The Commission has not assumed that utilities procure energy only through short-term contracts or never lock in their costs by constructing their own energy resources, executing long term fuel contracts, or executing long term energy supply contracts. In Order No. 69, the Commission defined “energy” costs as “the variable costs associated with the production of electric energy (kilowatt-hours)” and “represent[ing] the cost of fuel, and some operating and maintenance expenses.” ^[209] By contrast, in Order No. 69, the Commission defined “capacity” costs as “the costs associated with providing the capability to deliver energy; they consist primarily of the capital costs of facilities.” ^[210] The Commission has not changed these definitions; they still apply to both “short-run” (energy or non-firm power) and long-run (capacity or firm power) avoided costs.

111. While the final rule changed how states may calculate avoided energy costs (both pursuant to competitive market prices and variable rates), the Commission did not change the factors states must take into account, to the extent practicable, for setting fixed, avoided capacity costs; among these factors states must take into account, to the extent practicable, are the utility's own avoided cost data and the utility's deferral of capacity additions.^[211] Under this existing and unchanged framework, states already should take into account the long-run (capacity) and short-run (energy) incremental costs that utilities would incur but for their purchase from QFs.

112. As stated in the final rule, the difficulty in predicting prices necessarily also applies to predicting which costs a utility would incur from generating power itself or purchasing such power from another source over the term of a QF contract. Therefore, while there may be open questions over which costs a utility would incur from generating power itself or purchasing such power from another source in lieu of QF purchases, continuing to prohibit a state from allowing an energy rate to fluctuate would prevent states from choosing not to use unreliable price forecasts in setting avoided cost energy rates in QF contracts.

113. Public Interest Organizations' characterization of overestimated energy costs as “foregone windfall profits” due to utilities' monopoly status not only is inapt,^[212] but it ignores that utility customers ultimately bore the cost of avoided cost estimates that ultimately exceeded avoided costs in a way that is inconsistent with PURPA's avoided cost cap. Likewise, Solar Energy Industries' assertion that there is no evidence that states will lower retail rates if states require variable energy rates in QF contracts is irrelevant to whether the Commission may provide that flexibility under PURPA. The requirement found in PURPA is that the Commission cannot require that a rate paid to the QF exceed a certain amount.

b. Whether the Proposed Change Would Violate the Statutory Requirement That the PURPA Regulations Encourage QFs and Do Not Discriminate Against QFs

114. In the final rule, the Commission determined, based on the record evidence, that it is not necessarily the case that overestimations and underestimations of avoided energy costs will balance out over time. The Commission concluded that a fixed energy rate in a QF contract or LEO potentially could violate the statutory avoided cost cap on QF rates.^[213]

115. The Commission found that the 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, over time, 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, the Commission explained that allowing the use of variable energy rates may promote longer contract terms, which would help encourage and support QFs.^[214] The Commission concluded that it is consistent with PURPA section 210(b), as well as the obligation imposed by PURPA section 210(a), to revise the 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. The Commission noted that 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 above avoided costs would provide greater encouragement to QFs than a variable avoided cost energy rate.^[215]

116. The Commission described the discrimination claims as based on the incorrect assumption that electric utilities have not been required to lower their energy rates as prices have declined. The Commission found, to the contrary, that 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. The Commission explained that 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.^[216]

117. The Commission explained that it was not changing the requirement that QF avoided cost energy rates be set at the purchasing utility's full avoided energy costs. Rather, the Commission allowed 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 energy rates that are fixed for the life of the QF's contract or LEO, to ensure the rates comply with PURPA.^[217]

i. Requests for Rehearing

118. Solar Energy Industries argue that, by revoking the long-standing regulations that provide a QF with the right to elect to be paid a long-term energy rate in a contract for long-term energy delivery, the Commission is actively discouraging the development of QFs in contravention of the statutory direction to encourage the development of such facilities.^[218] Solar Energy Industries describe as inaccurate the Commission's claim that this revocation is necessary to protect the consumers of electric utilities because inaccurate administratively-determined avoided costs can be fully mitigated when a state adopts the Commission's new competitive bidding framework.^[219]

119. Solar Energy Industries request that the Commission clarify several portions of the final rule. First, Solar Energy Industries request that the Commission clarify that the circumstances that do not allow QFs to have nondiscriminatory access to buyers other than the host utility are largely the same today as in 1980 when the Commission first implemented its PURPA Regulations.^[220] Second, Solar Energy Industries request that the Commission clarify that states must ensure that QFs receive comparable avoided cost calculations and rates, terms, and conditions.^[221] Solar Energy Industries contend, for example, that utilizing a 20-year depreciation schedule for an avoided unit to calculate the long-run marginal cost rate and then offering a QF a two-year contract fails to ensure compatibility. Third, Solar Energy Industries request that the Commission clarify that it supports and renews its commitment to pursue enforcement actions when states discriminate against QFs.^[222]

120. Northwest Coalition asserts that the final rule's change of the requirement that QFs be offered fixed prices for energy is arbitrary, capricious, and not in accordance with law. Northwest Coalition argues that, in a “reversal” of 40 years of precedent since enactment of PURPA, the final rule unlawfully “guts” the bedrock requirement that QFs be offered fixed energy rates, which have long been recognized as necessary for the development of QFs.^[223] Northwest Coalition adds that the right to secure fixed energy prices supports the continued operation of existing QFs upon the expiration of their existing contracts when substantial interconnection and other capital upgrades must typically be undertaken and that elimination of fixed prices is likely to result in loss of substantial existing QF capacity.^[224]

121. Northwest Coalition claims that, despite the final rule's assertion that nothing in PURPA requires the Commission to ensure financeability of individual QFs, PURPA “does require the Commission to encourage their development, which we have previously equated with financeability.” ^[225] Northwest Coalition argues that, under the final rule, QFs could face a world in which there is no minimum contract term, a payment of zero for their capacity, and an avoided cost energy price based on highly volatile and unpredictable short-term markets. Northwest Coalition contends that rendering many QFs not financeable or financeable only at extreme interest rates discourages QFs, which is contrary to what PURPA requires.^[226]

122. EPSA argues that, although the Commission cannot, in the name of remedying discrimination, require QF rates that exceed avoided cost, allowing states to eliminate the fixed rate energy contract option does not result in QF rates that are non-discriminatory to the maximum extent permitted by the avoided cost cap.^[227] EPSA reiterates 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.^[228] EPSA asserts that this more restrictive requirement does not leave room for avoided cost rates that discriminate against QFs relative to purchasing electric utilities, even if the Commission finds the discrimination to be justified (i.e., not undue).^[229] EPSA argues that, subject to compliance with the avoided cost cap, the Commission cannot allow states to set discriminatory QF rates, even if the Commission determines those discriminatory rates are justified by differences between QFs and utilities or other policy goals, such as minimizing the burden of forecasting error on consumers.^[230]

123. EPSA claims that, in the final rule, the Commission does not adequately address these arguments, which it had raised in its NOPR comments.^[231] EPSA contends that the Commission erred in relying on the idea that variable energy rate/fixed capacity rate contracts are standard in the electric industry because PURPA requires that avoided cost rates not discriminate against QFs relative to purchasing electric utilities, not that such rates conform to standard industry practices.^[232] EPSA describes the Commission's argument that eliminating fixed energy price contracts is not discriminatory as unsupported because of its assumptions about how fuel and purchased power adjustment clauses operate. EPSA reasons that a franchised utility's rates will be set based on costs they actually incur to produce electricity for their customers and that such costs 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.^[233] In particular, EPSA claims that the Commission appears to assume that fuel and purchase power adjustment clauses will necessarily reflect short-term fluctuations in fuel and other energy-based costs, while, in a number of jurisdictions, these clauses also cover costs incurred under long-term contracts, including long-term fuel supply contracts, long-term power purchase agreements, and equivalent financial instruments.^[234] EPSA argues that remedying alleged discrimination requires providing QFs with a degree of insulation from market volatility comparable to that afforded to utility investments with effectively guaranteed cost recovery in retail rates, which EPSA argues the fixed energy rate contract option accomplishes.^[235]

124. EPSA asserts that it was legally incorrect to claim that a QF rate equal to the purchasing utility's avoided cost at the time of delivery by definition could not be discriminatory because the Commission's regulations and precedent leave no room for claims that, for purposes of PURPA's avoided cost cap, there is a single measure of avoided cost.^[236] EPSA claims that the Commission cannot avoid ensuring that QF rates are non-discriminatory on the basis that such rates are consistent with one measure of avoided costs if setting QF rates based on another permissible measure of avoided costs would eliminate some or all of the discrimination.^[237]

125. Public Interest Organizations argue that the Commission allowed states to set rates that discriminate against QFs in contravention of PURPA.^[238] Public Interest Organizations maintain that allowing avoided costs to be set at short-run prices discriminates against QFs and does not reflect utilities' avoided costs because utilities incur long-term energy supply costs that exceed short run costs. Public Interest Organizations assert that the Commission incorrectly defined discrimination as comparing the standard across the electric industry instead of how a specific purchasing electric utility treats similar generation. Public Interest Organizations contend that the Commission assumes without evidence that contracts whose energy prices are linked to short-term prices in a competitive market at the time of delivery is “standard” in long term contracts. Public Interest Organizations argue that, on the contrary, non-QF renewable generators are paid long-term fixed prices, including a fixed energy rate.^[239]

126. Public Interest Organizations claim that the Commission interpreted the statutory term “discriminate” incorrectly.^[240] Public Interest Organizations assert that, in the final rule, the Commission permitted states to deny QFs fixed energy pricing, “even if alternative energy the utility would acquire from its own generation or non-QF power producers would be at fixed costs, based on the industry `standard' followed by other utilities to limit the price for all alternative energy (owned and third party) to the short run market price.” ^[241] Public Interest Organizations contend that, while discrimination is generally defined as a “difference between the subject entity and a single similar entity that is more favorably treated,” ^[242] under PURPA, discrimination is not defined based on the industry standard but rather is defined “on how the specific purchasing utility treats QFs compared to how it treats one or more similarly situated non-QFs, including the utility's own generation.” ^[243]

127. Public Interest Organizations argue that the Commission lacked evidence to support its assertion that short-term rates are not discriminatory because they are the industry norm.^[244] Public Interest Organizations contend that the Commission lacks evidence to assert that the electric industry standard entails variable energy prices in long term supply contracts, given that “utilities make long-term investments for energy resources, enter long-term contracts for fuel for their own generation, [and] enter long term power purchase agreements with long-run energy prices (or blended energy and capacity prices).” ^[245] Public Interest Organizations claim that the Commission lacked evidence to assert that that utilities recovering cost-based rates must exclude long-term commitment costs such as rate-based energy resources, fuel contracts, and power purchase contracts when the long term energy portion of those costs, such as power purchase agreement prices, later exceed short run energy costs like the hourly LMP of the delivered energy.^[246] Public Interest Organizations assert that the rate-based generation of Alliant Energy, upon whose data the Commission relied, receives “advanced ratemaking principles” that fix favorable rate treatment despite intervals when the short run price is less than the energy price assumed when long-term fixed price recovery for those the energy resources were approved. Public Interest Organizations contend that a QF displacing such utility investments causes the utility to avoid the long-term fixed cost of the utility investment rather than the short-term day ahead or market hub price at the time energy is generated from it.^[247]

128. Public Interest Organizations argue that, contrary to the Commission's assertions that long-term utility energy cost commitments may be disallowed or modified due to short run energy price when the energy is delivered, rate recovery is usually required for the cost of supply contracts regardless of whether the contract price later appears too high compared to prices when the power is delivered. Public Interest Organizations therefore reason that non-QF energy supply that utilities own themselves or purchase from another source are not limited to short run energy market prices.^[248]

129. Public Interest Organizations similarly assert that the Commission selectively quoted Town of Norwood v. FERC for the proposition that long-term non-QF energy supply is limited to short-run market price at the time of delivery. Public Interest Organizations instead describe Town of Norwood as concerning a wholesale supply contract from a supplier's mix of resources to serve a retail utility instead of a power purchase agreement from a single generator comparable to a QF contract. Public Interest Organizations contend that the rate in Town of Norwood contained both energy pricing in two blocks “with the first priced at fixed embedded costs and charged based on a ratchetted demand and energy use, and the second block based on long run marginal costs.” ^[249]

130. Public Interest Organizations describe the Commission's justifications for its determination that Order No. 872 does not enable discrimination as poorly reasoned.^[250] Public Interest Organizations argue that treating QFs without discrimination does not require subjecting them to cost-of-service ratemaking in violation of PURPA but rather should be the same as how the utility determines costs for other purposes. Public Interest Organizations claim that the Commission's argument that it is not discriminating against QFs when it subjects them to short run energy prices because they still receive full avoided costs is circular.^[251]

131. Northwest Coalition asserts that the final rule authorizes a discriminatory framework by eliminating the certainty of a predictable revenue stream afforded by fixed prices. Northwest Coalition argues that electric utilities can still 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. Northwest Coalition contends that, in contrast, the final rule's new framework authorizing variable energy pricing deprives QFs of even a reasonable ability to forecast avoided cost prices from which they must recover their investment, much less guarantee such recovery provided to the typical utility. Northwest Coalition asserts that this outcome places QFs on unequal footing and ensures that utilities continue to dominate the generation market. Northwest Coalition argues that, in sum, the new regime is discriminatory because it permits utilities to make acquisition decisions based on long-term cost forecasts, which contain inherent forecast risk, but ties QFs to unpredictable future changes in markets.^[252]

132. Northwest Coalition contends that the final rule fails to address the critical point that utilities obtain virtually guaranteed cost recovery and virtually absolute certainty that they will recover their costs plus a profit, whereas QFs now do not even receive certainty as to the prices they can rely upon if they are able to perform successfully under their contracts. Northwest Coalition claims that the discrimination is the failure to put QFs on reasonably equal footing to utilities by providing QFs with the certainty of the right to beat the utility's long-term marginal cost of generation, which typically is the same long-term cost estimate used to justify the utility's own rate-base acquisitions.^[253]

133. Northwest Coalition argues that, although the discriminatory policy in Environmental Action ^[254] regarded transmission access and not price certainty, the same principle applies equally here. Northwest Coalition asserts that the Commission's “effort to place QFs on an essentially equal competitive footing with competing suppliers, . . . by giving such suppliers the access it denies to QFs would effect an administrative repeal of this congressional choice; by definition, this is not in the public interest.” ^[255] Northwest Coalition contends that, in this case, the Commission's alleged effort to place QFs on equal footing with incumbent utilities by giving such utilities the certainty of return on investment that will be denied to QFs is plainly discriminatory.^[256] Northwest Coalition adds that this interpretation of the anti-discrimination requirement is even supported by the Montana Public Service Commission in the context of price certainty and allocation of forecast risk, even though that state agency generally supported the Commission's proposed rule.^[257]

ii. Commission Determination

134. We disagree with the arguments raised on rehearing. To begin, it is incorrect to state that the final rule eliminated fixed rates for QFs. The final rule gave states the flexibility, if they choose to take advantage of this flexibility, to require that the avoided cost energy rates in QF contracts vary depending on avoided energy costs at the time of delivery. In the final rule, as described above, the Commission retained the QF's right for capacity rates to be fixed, which together with the flexibility adopted in the final rule to allow states to set avoided cost energy rates using competitive market forces should provide a more transparent way of determining avoided costs. Those capacity rates would still need to meet the standards of 18 CFR 292.304(e), which together with more transparent energy rates determined pursuant to competitive market prices and the existing PURPA Regulations, encourages the development of QFs.^[258]

135. Further, in response to EPSA's and Public Interest Organizations' arguments that the final rule does not accurately describe how merchant generators are financed and protect QFs against volatility in fuel prices, the variable energy rate/fixed capacity rate construct is common among merchant generators for power sales agreements that include the sale of capacity, thus demonstrating that other types of non-utility generation are able to raise useful financing under such an arrangement.^[259]

136. We also disagree with arguments raised on rehearing regarding discrimination. We reiterate our holding in the final rule that PURPA does not require, and indeed prohibits, subjecting QFs to the same rate structures and procedures as utilities.^[260] Congress made this point clear when it enacted PURPA. “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.” ^[261] And the Supreme Court relied on this legislative history to conclude that “The legislative history confirms, moreover, that Congress did not intend to impose traditional ratemaking concepts on sales by qualifying facilities to utilities.” ^[262]

137. Moreover, EPSA, Northwest Coalition, Public Interest Organizations, and Solar Energy Industries miss the mark when they argue that it would be discriminatory to permit states to require variable energy rates in QF contracts if the energy the utility otherwise would acquire from its own generation or non-QF power producers would be at a fixed cost. These entities assert that, to prevent such discrimination, the Commission must require fixed energy rates in order to ensure comparable terms and conditions in QF contracts. However, in the unlikely event that all of a purchasing utility's other, non-QF resources happen to be long-term purchases with fixed capacity and energy rates, such a utility's avoided capacity and energy costs would not vary significantly over time. In that case, a variable energy rate set at the utility's avoided costs at the time of delivery would be based on the utility's essentially unchanging avoided costs and thus would not change significantly over time.^[263]

138. We find that Public Interest Organizations and Solar Energy Industries conflate the variable rate issue with the contract length issue in asserting that the final rule discriminates against QFs. Although the Commission changed the extent to which a QF is entitled to a fixed avoided cost energy rate, the Commission did not change the requirement that a capacity rate should account for longer-term costs (i.e., longer than as-available) associated with providing the capability to delivery energy.^[264] A QF contract or LEO with a variable energy rate should reflect a purchasing electric utility's avoided energy costs estimated at the time of delivery. It is irrelevant for calculating a purchasing electric utility's avoided energy costs whether a purchasing electric utility makes purchases of long-term capacity in non-QF bilateral agreements because a QF remains entitled to a fixed capacity rate. In the final rule, as described above, states must take into account the existing factors for setting fixed avoided cost capacity rates, QFs are able to require that avoided cost capacity rates in their contracts and LEOs be fixed, and QFs may continue to bring enforcement petitions before the Commission if states are failing to take into account those factors when setting avoided cost capacity rates. In response to Solar Energy Industries' request that the Commission clarify its intent to pursue enforcement against states in setting avoided cost rates, if a QF believes that its fixed capacity rate in a contract does not fully reflect the long-term capacity avoided costs of the purchasing utility because of the length of the QF contract, that QF may pursue a claim under the statutory provisions for the enforcement of PURPA.

139. Solar Energy Industries request that the Commission clarify that where QFs continue to lack nondiscriminatory access to buyers other than the host utility, the circumstances have not changed since 1980.^[265] It is not apparent what Solar Energy Industries asks the Commission to clarify. But to the extent that this is a criticism of the final rule, the final rule continues to require that state determinations of avoided costs reflect the purchasing utility's avoided costs and that QFs have the right to sell to directly and indirectly interconnected utilities.^[266]

140. We disagree with Public Interest Organizations' and Northwest Coalition's assertions that the variable rate option overemphasizes the avoided cost rate cap and underemphasizes the prohibition on discrimination against the QF and the requirement to encourage QF development.^[267] PURPA specifically states 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.” ^[268] Thus, the Commission's actions to better ensure that it has not prescribed a rule requiring that the rates paid to QFs not exceed the purchasing utility's avoided costs reflect Congress's priorities in enacting PURPA and give meaning to all provisions of the statute.^[269]

141. We disagree with Northwest Coalition that the final rule discriminates against QFs by failing to put them on a competitive footing with utilities in violation of Environmental Action.^[270] In that case, the D.C. Circuit discussed PURPA's prohibition on discriminating against QFs in connection with PURPA's mandatory purchase obligation. The D.C. Circuit stated that “[a] QF may force a sale only at the purchasing utility's avoided cost . . . . If the QF is less efficient (i.e., has higher costs) than its competitors, its guaranteed ability to sell power only at a price below its cost will not cause its competitors any loss of sleep.” ^[271] But, in contrast, if a “QF is more efficient [than the purchasing electric utility], then the preference it receives is not a threat to, but only a redundant (legal) guarantee of, the competitive (economic) outcome. In fact, the principal effect of the preference seems to be to ensure that large power producers do not discriminate against QFs.” ^[272] Thus the court confirmed that QFs are not guaranteed to recover their costs and they must take the risk of being unable to make a profit selling at the purchasing utility's avoided costs. Contrary to Northwest Coalition's assertions, this case hardly suggests that fixed energy avoided cost rates are necessary to place QFs on a competitive footing with utilities or that therefore the Commission must provide QFs the same rate structure or rate recovery as a utility.

142. Public Interest Organizations cite Commission and federal district court decisions to argue that the Commission's final rule results in discrimination.^[273] But those cases do not address how PURPA's nondiscrimination standard relates to the avoided cost cap, and Order No. 872 provides that QFs are still entitled to a fixed avoided cost capacity rate.^[274] Similarly, Congress and the Supreme Court both recognized that PURPA treats QFs differently from purchasing utilities, rendering QFs not similarly situated to non-QF resources.^[275]

143. We also disagree with Public Interest Organizations that the final rule's reference to Town of Norwood does not justify use of variable energy rates. The Commission cited Town of Norwood for the proposition that “variable energy rate/fixed capacity rate construct is . . . the standard rate structure used throughout the electric industry for power sales agreements that include the sale of capacity.” ^[276] The D.C. Circuit in Town of Norwood explained that the rate construct at issue in that case had separate fixed demand and variable energy charges.^[277] The final rule does not state that this rate construct necessarily represented a particular generator's agreement nor did it need to do so to justify granting states flexibility to use fixed capacity/variable energy avoided cost rates: PURPA is only concerned with the purchasing electric utility's avoided costs.^[278] Indeed, the rate construct in Town of Norwood was a marginal cost rate structure, which resembles the definition of avoided costs under PURPA. Therefore, the Commission properly referenced the utility rate structure in Town of Norwood for the proposition that a purchasing utility has a fixed capacity/variable energy rate structure.

144. Furthermore, PURPA gives the Commission (and the states) discretion to implement all the requirements applicable to QF rates in a manner that gives all the requirements meaning. The Commission's interpretation in the final rule is a reasonable one that gives effect to all relevant statutory provisions by encouraging QF development and preventing discrimination against QFs, while respecting the avoided cost rate cap.^[279] In contrast, petitioners' interpretations do not give appropriate effect to all provisions of the statute because they fail to give full effect to the requirement that QF rates cannot exceed the avoided cost rate cap. Together with the greater transparency the final rule permits with respect to competitive market prices and competitive solicitations and greater clarity with regard to LEOs, the final rule has implemented all provisions of the statute consistent with Congress's intent in passing PURPA.

c. Effect of Variable Energy Rates on Financing

145. In the final rule, the Commission agreed with commenters that PURPA does not guarantee QFs a rate that, in turn, guarantees financing. The Commission stated that, although PURPA requires the Commission to adopt rules that encourage the development of QFs, PURPA does not provide a guarantee that any particular QF will be developed or profitable.^[280]

146. Notwithstanding that PURPA does not guarantee QF financeability, the Commission stated its belief that the variable avoided cost energy rate option implemented by the final rule will still allow QFs to obtain financing.^[281]

147. The Commission reiterated that it is not eliminating fixed rate pricing for QFs. The Commission explained that, under the final rule, QFs will be able to require that avoided cost capacity rates in their contracts and LEOs be fixed. The Commission further explained that 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. The Commission stated that a combination of fixed avoided cost capacity rates and variable avoided cost energy rates can provide important revenue streams that can support the financing of QFs.^[282]

148. Furthermore, the Commission found that 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. The Commission explained that, 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. The Commission described 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 as attempting to impose a standard that could never be satisfied.^[283]

149. In response, the Commission cited to ample evidence demonstrating that generation projects that are similar to QFs (i.e., independent power producers) with fixed capacity rate-variable energy rate contracts are financeable.^[284]

150. The Commission found that the record showed that, even without the right to require long-term fixed energy rates, non-QF independent power producers have been able to obtain financing for large amounts of generation capacity, including from renewables. Based on this data, the Commission found that the right to require counterparties to pay fixed energy rates is not essential for the financing of independent power generation capacity.^[285]

151. The Commission acknowledged that a number of different financing mechanisms were used for this independent generation capacity, not all of which may be available to QFs. Nevertheless, the Commission understood 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.^[286] Accordingly, the Commission found that 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.

152. The Commission did 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.^[287] Similarly, the Commission was 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.^[288]

153. The Commission found that the record demonstrated that the amount of renewable resources being developed outside of PURPA greatly exceeds the amount of renewable resources developed as QFs. The Commission reasoned that the fact that renewable resources were able to develop outside of PURPA showed that they were able to obtain financing despite lacking the legal right to fixed energy rates.^[289]

154. The Commission also disagreed with those commenters who asserted that the Commission should “require[] the variable energy component to be structured in a way that removes market risk from the QF.” ^[290] The Commission found that this argument is contrary 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.^[291] The Commission described concerns regarding the alleged mismatch between avoided costs and the costs of renewable technologies as collateral attacks on the requirements of PURPA itself, not our proposed implementation of it.

155. The Commission acknowledged those comments explaining that hedging tools increase project expense and may not be available to all QFs.^[292] However, the Commission stated that it never intended to suggest that hedging is cost-free or that it would be appropriate for all QFs.

156. The Commission found that testimony that Public Interest Organizations cited from the Technical Conference, which indicated that Southern Company has negotiated non-QF renewable contracts with fixed energy rates rather than variable energy rates, did not support the contention that the Commission must provide for fixed avoided cost energy rates for QF contracts and other LEOs.^[293]

157. In the NOPR comments, 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.^[294] The Commission found that, 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.^[295] The Commission stated that 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.

158. The Commission recognized that there is some evidence that variable avoided cost energy rates in contracts and LEOs could result in longer-term contracts.^[296] The Commission did not find that the variable avoided cost energy rate provision in the final rule will necessarily lead to longer term contracts and LEOs in every state, nor did its decision to adopt this provision rely on such a finding.^[297] However, the Commission found that 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.^[298]

i. Requests for Rehearing

159. Public Interest Organizations argue that the Commission ignored evidence showing that allowing states to eliminate fixed energy rate contracts discourages QF development.^[299] Public Interest Organizations assert that the Commission ignored evidence that fixed energy rates are important to QF development. Similarly, Public Interest Organizations claim that the Commission ignored evidence that (1) allowing states to adopt variable energy rate contracts will violate PURPA and (2) states allowing only variable energy rate QF contracts have experienced little or no renewable QF development and QF development fell in states that switched from fixed price contracts to variable price contracts.^[300] For support, Public Interest Organizations point to the following: (1) Alabama offers standard contracts with only QF rates that vary based on month and time of day received and in 2018 Alabama's cumulative solar capacity was less than 300 MW; (2) Georgia Power's standard offer for solar QF contracts offered only a variable hourly avoided energy cost rate and there are about nine solar participants in this program with a total of less than 500 kW capacity; (3) Wisconsin utilities offer only short term variable pricing at LMP and no QFs have been developed in response, in contrast to neighboring states with fixed price contracts and substantial QF development; and (4) QF development related to fixed rate contracts in Idaho stopped after the Idaho Commission required variable energy rate contracts that reset every two years.^[301]

160. Public Interest Organizations argue that large, non-QF development and nuclear plant power purchase agreements also rely on fixed price contracts. Public Interest Organizations maintain that, even if non-QFs relied on variable- instead of fixed-energy price contracts, the Commission has not shown that renewable projects that are QFs can be developed under similar contract terms. Public Interest Organizations represent that renewable QFs have only been developed where contracts provide long-term price certainty (e.g., in Idaho, QF development ceased when states provide only variable energy pricing (even with fixed capacity rates), which is contrary to the Commission's unfounded assertion that QF development would increase with variable rates).^[302]

161. Public Interest Organizations argue that the Commission relies on speculation that QFs could be developed without fixed energy rates and that the Commission lacks evidence to argue that long-term price certainty is not material to QFs' ability to obtain financing. Public Interest Organizations assert that the Commission's citation to testimony from Southern Company about a hypothetical bilateral contract with an independent natural gas power producer does not show how renewable generators that could qualify as QFs using different financing structures, using different fuels, and at much smaller capacities could be developed. Public Interest Organizations contend that the Commission could point to no renewable QF that could be developed without long-term energy price certainty. Public Interest Organizations similarly assert that the Commission misconstrued testimony from Solar Energy Industries in suggesting that a fixed energy price was unnecessary to encourage QF development.^[303]

162. Public Interest Organizations argue that, contrary to the Commission's assertions, there is no evidence that bilateral energy transactions to hedge energy price risk as used in large gas plant transactions are sufficient without fixed energy rates for lenders to finance new wind and solar QF development. Public Interest Organizations claim that the Commission has no evidence that financial hedge products exist for QFs for a sufficient period of time and at a reasonable price to permit financing.^[304] Public Interest Organizations assert that, because the Commission has provided no evidence that any QFs, renewable projects the size of QFs, or non-QF renewables were developed without fixed price energy contracts, the Commission's assertions that new generation was developed without PURPA's avoided cost provisions are irrelevant.^[305]

163. Public Interest Organizations argue that the Commission ignored evidence showing the fixed capacity rates alone will not encourage renewable energy development.^[306] Public Interest Organizations claim that the Commission ignored evidence showing that, in vertically integrated markets like the Southeast, several utilities have eliminated or dramatically lowered capacity payments to QFs and that QFs cannot use financing arrangements available to non-QFs, such as independent natural gas generators, to be viable. Public Interest Organizations assert that, because the capacity price for a QF may be zero, no QFs were effectively developed after Dominion Energy South Carolina's capacity rates were set at zero and QF development is minimal in Alabama due to Alabama Power's zero price capacity rates. Therefore, Public Interest Organizations maintain that the Commission has no evidence to support its contention that a fixed capacity rate should be sufficient to recover QF capacity costs and enable QF financing.^[307]

164. Public Interest Organizations argue that renewable QFs have different financing needs than non-QF independent natural gas generators and that the Commission lacked evidence to support applying the variable energy/fixed capacity rate construct to QFs.^[308] Specifically, Public Interest Organizations represent that “wind and solar QFs have higher capital costs, lower operating costs, and provide energy intermittently—characteristics that may present different financing challenges as compared to non-QF natural gas fired capacity.” ^[309] Public Interest Organizations state that even RTO/ISO capacity markets, which they note many QFs do not have access to, “are implicitly biased in favor of resources with low capital costs, such as natural gas plants, and may be “ill-suited to finance” renewable resources with high-fixed costs and near-zero operating costs.” ^[310]

165. Solar Energy Industries contend that, while securing financing based on an as-available energy rate and a fixed capacity rate may be a rare possibility in a few locations across the country, there is no evidence in the record that financing is generally available in such circumstances.^[311] Solar Energy Industries claim that, therefore, long-term contracts are necessary to finance new non-utility generation because capital providers will not finance a project without a reasonable expectation of the revenue the project expects to generate over its useful life.^[312] Solar Energy Industries conclude that, if the purchasing electric utility does not offer the QF a forecasted energy rate over the life of a long-term contract and the QF is not otherwise able to compete for a long-term contract through a competitive bidding program, then the QF will not be able to obtain financing in the capital markets.^[313]

166. Solar Energy Industries further argue that there is no credible evidence in the record that even merchant generation projects are financed on variable energy rate contracts.^[314] Solar Energy Industries provide examples where such generators have sought longer-term contracts as a means to support capital market financing.^[315] Solar Energy Industries further argue that merchant natural gas generators have relatively low capital costs and are thus able to rely on the fuel products markets to mitigate the risk of variable energy pricing, whereas fuel-less QFs do not have a similar ability, and thus bear the entire risk of volatile market prices.^[316] Solar Energy Industries provide examples of industry studies that they claim have consistently shown that only very small portions of new capacity additions have been financed with variable energy rates.^[317]

167. Solar Energy Industries also assert that the Commission acted arbitrarily and capriciously in failing to consider the fact that many states do not offer QFs a fixed price for capacity that is sufficient to support financing.^[318] Solar Energy Industries argue that, when purchasing electric utilities do not provide for fixed capacity payments over the term of the QF contract, the Commission should not provide a state flexibility to terminate the QF's right to elect a long-term energy rate in a long-term contract.^[319] Solar Energy Industries contend that it would be arbitrary and capricious, for example, to allow New Mexico the flexibility to terminate the QF's right to elect a long-term energy rate because Public Service Company of New Mexico (PNM) does not compensate QFs for capacity despite the fact that PNM has announced it is replacing all of the capacity from its San Juan Generating Station with renewables.^[320]

168. Finally, Solar Energy Industries claim that the final rule's reliance on the prospects for QFs' ability to leverage the use of financial products (i.e., a hedge) when offered a variable energy rate contract is without any factual basis, adding that, even when hedges are made available, many hedge providers decline to work with small projects because they are not cost effective and have higher risk profiles.^[321]

169. Northwest Coalition argues that the Commission's assumption that QFs will be able to secure financing without fixed energy prices is not supported by sufficient evidence and ignores extensive evidence to the contrary. Northwest Coalition asserts that the Commission's conclusion that QFs can be financed using contracts with variable energy rates is without evidentiary support and arbitrarily ignores or misconstrues evidence from different sources demonstrating that exposing generation projects to unpredictable market risks makes financing QFs impossible. Northwest Coalition contends that, although the Commission relies on evidence that non-QF renewable energy projects have grown in recent years, it cites no underlying contract terms and ignores that these projects have largely been built on the strength of fixed price contracts. Northwest Coalition claims that the Commission takes evidence out of context and ignores real-world evidence that attempts to develop generation based on short-term prices have failed ^[322] and that short-term prices do not represent utility avoided costs for long-term energy.^[323]

170. Northwest Coalition argues that the Commission relies on arbitrary reasoning to support the decision to reverse 40 years of precedent, holding that fixed-price contracts are necessary to encourage QFs and support financing of QFs, to authorize states to deprive QFs of fixed energy prices. Northwest Coalition asserts that the Commission failed to respond to legitimate objections raised by commenters opposing the proposal, ignores evidence that QFs require a substantial minimum term to support financing, and fails to establish any minimum contract term, despite well-established precedent requiring contract terms long enough to support financing and substantial evidence that states have undermined PURPA by imposing unreasonably short contract terms.^[324]

171. Northwest Coalition claims that there is no guarantee that the long-term avoided capacity payment will be sufficient to support a QF's financing and permitting avoided cost energy payments to vary with volatile short-term market prices forces QFs to bear the risks of market volatility.^[325]

ii. Commission Determination

172. We disagree with the arguments raised on rehearing. First, in enacting PURPA, Congress made clear that QFs' “risk in proceeding forward in the cogeneration or small power production enterprise is not guaranteed to be recoverable.” ^[326] The Commission determined, based on record evidence described in the final rule and below, that significant amounts of generation capacity, including renewable resource capacity, have obtained financing without a regulatorily-required fixed energy rate. But to the extent that a state determines that a variable energy rate is required to ensure that the QF's rate does not exceed avoided costs, then PURPA prevents the Commission from requiring that the state award the QF with a fixed energy rate to ensure that the QF obtains financing.

173. We also reiterate that the Final Rule did not eliminate fixed rates for QFs. The final rule gives states the flexibility, if they choose to take advantage of this flexibility, to require that the avoided cost energy rates in QF contracts vary depending on the purchasing utility's avoided energy costs at the time of delivery. However, in the final rule, the Commission did not alter QFs' right to require capacity rates to be fixed for the length of the QF's contract. Those capacity rates would still need to meet the standards of 18 CFR 292.304(e). Furthermore, because those rates must continue to be set at a purchasing utility's full avoided costs, a particular QF's inability to be developed under that rate does not mean that rate violates PURPA.

174. Further, as stated in the final rule, the variable energy rate/fixed capacity rate construct is common among merchant generators for power sales agreements that include the sale of capacity, which demonstrates that other types of non-utility generation are able to raise useful financing under such an arrangement.^[327] As Finadvice, a commenter with experience in project finance observed in its NOPR comments, given the mandatory purchase obligation,

QFs utilizing a variety of standard hedging and risk management tools, provide sufficient comfort to facilitate the financing of variable priced PPAs. Having a fixed capacity rate, as proposed by the Commission will help attract capital and reduce the cost of financing in this regard, but is not a necessary prerequisite.^[328]

175. Moreover, many QFs do share significant characteristics with other types of independent, non-utility generation; thus, it is reasonable to assume that they would be able to raise useful financing under such a financing arrangement.^[329] It is not necessary to prove that all potential QFs would be able to raise useful financing under such an arrangement, particularly where a state has determined that mandating variable as-available QF energy rates is necessary to respect the statutory avoided cost cap on QF rates.^[330]

176. While independent non-QFs are not subject to the same limits as QFs (i.e., avoided cost caps, 80 MW limit), these resources have been developed, likely with financing, despite lacking the encouragement provided by PURPA (i.e., mandatory purchase obligation, interconnection rights, exemption from state and federal regulations). While the Commission has indicated that hedging and other financial instruments can be helpful for QFs to obtain financing, the Commission did not suggest that all QFs need such instruments to obtain financing.^[331]

177. We are not persuaded by Public Interest Organizations' argument that states' use of variable energy rates is a dispositive cause of a drop in QF development in particular states; it is possible that such a decrease in QF development was due to a variety of reasons, such as non-PURPA-related permitting, or PURPA-related reasons that preceded the final rule, such as the avoided capacity costs equaling zero, which has been permissible under Commission precedent.^[332] While we do not in this proceeding invalidate any state actions taken thus far, the final rule and this order provide greater emphasis that QFs are entitled to a fixed capacity rate if the purchasing utility's avoided capacity costs exceed zero. If a QF believes that a state is not implementing these rules, then that QF may seek relief 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)).^[333]

d. Requested Clarification of the Final Rule

178. If the Commission does not grant rehearing, Solar Energy Industries request that the Commission clarify that such “flexibility” offered by revised 18 CFR 292.304(d) is not available to any state unless the purchasing electric utility (1) has separately-stated avoided energy and capacity rates on-file and (2) is complying with the data reporting requirements of 18 CFR 292.302.^[334]

i. Commission Determination

179. We grant Solar Energy Industries' request for clarification that a state may only use variable rates to set avoided energy costs if the utility has fulfilled its obligations to disclose avoided cost data under 18 CFR 292.302. We do not find the disclosure of such information unreasonable as the Commission's PURPA Regulations already require its disclosure.^[335] In addition, although electric utilities are required to disclose this data generally, it is especially important when a state has selected the fixed capacity/variable energy rate construct to ensure that QFs have this data from the purchasing electric utility to provide transparency with regard to a utility's avoided costs, i.e., to understand what a utility's cost are to generate itself or purchase from another source. Particularly in the context of a state selecting a variable energy rate that can change over the term of a QF contract, ensuring that QFs have access to such avoided cost data encourages QF development.^[336]

180. We deny Solar Energy Industries' additional request that a utility must have separately-stated avoided energy and capacity rates on-file in order for a state to set variable energy rates in QF contracts. Solar Energy Industries has not shown how having such rates on file necessarily encourages the development of QFs and, as explained below, likely would be inconsistent with the authority that PURPA grants the states.^[337] Under PURPA, states are permitted to determine avoided cost rates differently among themselves (i.e., through adjudication, rulemaking, or legislation).^[338] Requiring each utility to have a stated rate on file (beyond standard rates ^[339] ) may interfere with states' rights to determine a rate and the flexibility provided in Order No. 872 to set such rates. However, as noted above, we are requiring the disclosure of the data that would allow QFs to review any rate that is set by a state, and the disclosure of such data should encourage the development of QFs.

5. Consideration of Competitive Solicitations To Determine Avoided Costs

181. In the NOPR, the Commission 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.^[340]

182. 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.^[341] That rulemaking proceeding, along with several related proceedings, ultimately was withdrawn as overtaken by events in the industry.^[342]

183. Since then, in 2014, the Commission held, with respect to a particular competitive solicitation, 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.^[343] 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.^[344]

184. Given this precedent, in the NOPR, 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 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.^[345]

185. Nevertheless, in considering what constitutes proper design and administration of a competitive solicitation, in the NOPR, 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,^[346] the Bidding NOPR, and the Hydrodynamics case ^[347] all suggest factors that could be considered in establishing an appropriate competitive solicitation that is conducted in a transparent and non-discriminatory manner.^[348]

186. As proposed in the NOPR, these factors included, 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; ^[349] (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).^[350]

187. 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.^[351]

188. In the final rule, the Commission adopted 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 pursuant to appropriate procedures in a transparent and non-discriminatory manner. The Commission stated that the 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. The Commission found that 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.^[352]

189. Consistent with its general approach of giving states flexibility in the manner in which they determine avoided costs, the Commission did not prescribe detailed criteria governing the use of competitive solicitations as tools to determine rates to be paid to QFs and to determine other contract terms. The Commission found that states are in arguably 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.^[353]

190. However, as in the NOPR, the Commission in the final rule found it 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. The Commission found 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.^[354]

191. The Commission affirmed 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). The Commission explained that the final rule does not undo any competitive solicitations conducted prior to the effective date of the final rule that may not have met these criteria. The Commission described the final rule as applying only to competitive solicitations conducted after the effective date of the final rule.^[355] The Commission also stated that it will presume that any future competitive solicitation that does not comply with the factors adopted in the final rule does not comply with the Commission's regulations implementing PURPA.^[356]

192. The Commission explained that, more generally, it supports 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. The Commission further explained 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. The Commission found 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. The Commission expressed its belief that a properly administered competitive solicitation can help provide such price signals.^[357]

193. The Commission also clarified 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. The Commission clarified 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 declined to direct such a requirement.^[358]

194. The Commission determined that, 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.^[359] However, the Commission determined that 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.^[360]

195. The Commission also determined that, 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.^[361]

196. The Commission affirmed that, when capacity is not needed, the avoided capacity cost rate can be zero.^[362] The Commission described how competitive solicitations conducted pursuant to the rules adopted in the final rule that are held whenever capacity is needed provide QFs a level playing field on which to compete to sell capacity. The Commission explained that 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.^[363] The Commission found that 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. The Commission clarified, however, that the competitive solicitation is not to be a means to determine a QF's right to put as-available energy to the utility. Rather, the competitive solicitation can be the means to determine what, if any, rate the QF will be paid for capacity.^[364]

197. The Commission clarified 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.^[365]

198. The Commission also revised 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 safeguards. The Commission found 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 that requiring that this information be provided will help ensure that a competitive solicitation is open and transparent.^[366]

199. The Commission also clarified 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. The Commission found this post-solicitation report requirement to be consistent with the requirement that competitive solicitations be open and transparent, not only to 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.^[367]

200. The Commission declined to be overly prescriptive as to what constitutes an “independent administrator,” responsible for administering the competitive solicitation. The Commission clarified that the independent administrator must be an entity independent from the purchasing electric utility in order to help ensure fairness. Whether called an independent administrator or a third-party consultant, the Commission stated that the substantive requirement is that the competitive solicitation not be administered by the purchasing electric utility itself or its affiliates, but by a separate, unbiased, and unaffiliated entity not subject to being influenced by the purchasing utility.^[368]

201. The Commission declined to add any additional requirements for competitive solicitations, given that states may be in the best position to consider their particular local circumstances. The Commission found that the guidelines adopted in the final rule, in conjunction with the Allegheny principles and other clarifications, provide an adequate framework for competitive solicitations to be conducted efficiently, transparently and in a nondiscriminatory manner.^[369]

202. 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, the Commission found that an exemption from competitive solicitation processes is unnecessary. The Commission did not exempt small power production facilities from the competitive solicitation process and was 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. The Commission clarified, however, that QFs with capacity of 100 kW or less already are entitled to standard rates regardless of whether they compete in a competitive solicitation, and the final rule did not change that regulation.^[370]

i. Requests for Rehearing

203. Northwest Coalition argues that allowing states to use competitive solicitations to be the exclusive means of securing a long-term PPA to sell energy and/or capacity is arbitrary, capricious, and not in accordance with law.^[371]

204. Northwest Coalition notes that PURPA section 210(a) requires that the Commission's rules must “encourage” QFs and must “require electric utilities to offer to . . . purchase electric energy from such facilities.” ^[372] Northwest Coalition argues that, while the term “electric energy” is not defined in the statute, the phrase's context within the statutory scheme unambiguously confirms that electric energy includes both energy and capacity, meaning that the Commission's rules must require utilities to purchase energy and capacity made available by QFs.^[373] Northwest Coalition asserts that, following the enactment of PURPA, the Commission interpreted this language in Order No. 69 to mean that the statutory phrase “electric energy” must include both energy and capacity.^[374] Northwest Coalition contends that the final rule does not provide any basis to change the Commission's longstanding interpretation of PURPA section 210(a) that requires electric utilities to purchase all energy and capacity made available by QFs.^[375]

205. Northwest Coalition relies on the U.S. Court of Appeals for the Ninth Circuit's invalidation of the California Commission's Re-Mat competitive solicitation program, which found that under the Re-Mat program, “a utility could purchase less energy than a QF makes available, an outcome forbidden by PURPA.” ^[376] Northwest Coalition argues that, because the same problem exists with the final rule's exclusive use of competitive solicitations to offer to buy capacity from QFs, allowing states to refuse to require electric utilities to offer to purchase capacity from QFs violates the statutory requirement that utilities offer to purchase all capacity made available from QFs.^[377]

206. Northwest Coalition asserts that PURPA section 210(a) requires that the Commission design its rules implementing the statutory must-purchase obligation in such a manner that those rules will encourage the development of QFs, adding that allowing utilities to evade the mandatory purchase obligation through the exclusive use of competitive solicitations that utility-owned resources commonly win is inconsistent with statutory requirements.^[378]

207. Northwest Coalition contends that the final rule arbitrarily fails to acknowledge the Commission's own precedent and therefore does not constitute reasoned decision making.^[379] Northwest Coalition points to Hydrodynamics, in which the Commission rejected the “Montana Rule,” which imposed a “competitive solicitation process as the only means by which a QF greater than 10 MW can obtain long-term avoided cost rates.” ^[380] Northwest Coalition also points to Windham Solar LLC, in which the Commission confirmed that it has held “a state regulation to be inconsistent with PURPA and the PURPA regulations `to the extent that it offers the competitive solicitation process as the only means by which a QF . . . can obtain long term avoided cost rates.' ” ^[381] Northwest Coalition argues that, under Commission precedent, “regardless of whether a QF has participated in a request for proposal, that QF has the right to obtain a legally enforceable obligation.” ^[382] Northwest Coalition claims that the final rule's reasoning for allowing states to use competitive solicitations as a substitute for long-term PURPA contracts does not acknowledge these precedents or explain how the use of competitive solicitations could still comply with the statute.^[383] Northwest Coalition argues that, aside from generally averring it expects competitive solicitations will be fair with the newly adopted criteria, the final rule does not cite evidence suggesting that competitive solicitations will provide an adequate mechanism for QFs to sell energy and capacity or any other basis to overrule Commission precedent and therefore is arbitrary and capricious.^[384]

208. Northwest Coalition asserts that the final rule relies on insufficient evidence to conclude that exclusive use of competitive solicitations will encourage QFs.^[385] First, Northwest Coalition contends that the Commission's decision fails to address multiple commenters' concerns with inherent bias in utility-run competitive solicitations and the difficulty and complexity of designing competitive solicitations that are fair to independent bidders, especially in regions with vertically integrated utility structures like the Pacific Northwest.^[386] Northwest Coalition argues that, given the evidence submitted concerning competitive solicitations in the Northwest, the Commission is required to conduct a more meaningful investigation and inquiry into the subject before it could rationally conclude that it has now developed bidding criteria that would suffice to justify denial of an LEO to any QF.^[387]

209. Northwest Coalition claims that the Commission fails to explain why it rejected more restrictive criteria proposed by parties but not included in the final rule. As an example, Northwest Coalition points to the Commission's failure to discuss in the final rule its additional proposed criteria for any RFP process to overcome inherent utility-ownership bias: (1) Require that the RFP include no utility-ownership options; or (2) if utility-owned generation may result, the RFP must be (i) administered and scored (not just overseen by an independent evaluator) by a qualified independent party, not the utility, (ii) any utility or 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, i.e., the utility or affiliate may not have an informational advantage in the RFP. Northwest Coalition asserts that, while the final rule adopted a requirement for independent third-party design and administration of the RFP, it rejected the rest of its proposals without discussion.^[388]

210. Northwest Coalition contends that the final rule also ignores the lack of reasonable enforcement for the proposed exclusive use of competitive solicitations.^[389] Northwest Coalition argues that the final rule established a process that only allows QF advocates to challenge competitive solicitations after the fact, when it is too late to correct the harm caused by the utility's reliance on the competitive solicitation process as a basis to refuse to contract with QFs in the interim.^[390]

211. Northwest Coalition asserts that the final rule relies on insufficient evidence that small QFs and those primarily engaged in a business other than power production (e.g., irrigation districts and waste-to-power facilities) can succeed in the type of all-source competitive solicitation identified in the final rule.^[391] Northwest Coalition contends that the final rule summarily declines to adopt any exceptions other than a statement that 100 kW and smaller QFs can still obtain standard rates ^[392] without a meaningful explanation, which fails to encourage such QFs, in contravention of PURPA.^[393]

212. Mr. Mattson asserts that a QF should not have to compete in a competitive solicitation with coal and natural gas generators where the utility is selling their excess energy.^[394] Mr. Mattson alleges that requiring a QF to accept the competitive solicitation process to sell its capacity is a violation of the “constitutional law right to contract.” ^[395] Mr. Mattson argues that QFs should have the right to a capacity payment if a capacity reduction will occur and the right to sell their capacity in the market.^[396]

213. Public Interest Organizations contend that the competitive solicitation provisions are arbitrary and capricious, unless the Commission clarifies that the solicitation only sets the full avoided energy costs for QFs when the utility procures all energy through solicitation.^[397] Public Interest Organizations claim that the final rule does not require a state or non-regulated utility which uses a competitive solicitation process to determine the price for QF energy and/or capacity rates to also determine that the price reflects the utility's avoided cost.^[398] Public Interest Organizations assert that 18 CFR 292.304(b)(8) not only requires that a utility procure all capacity through competitive solicitations to satisfy its capacity requirement but also assumes that such competitive solicitation results reflect the full avoided energy cost without similarly requiring the purchasing electric utility to acquire all energy requirements through competitive solicitation.^[399] Public Interest Organizations allege that QFs are discriminated against in circumstances in which the competitive solicitation price is lower than the cost of energy produced or acquired by the utility outside the solicitation process.^[400] Public Interest Organizations argue that, while the final rule appears to agree that out-of-market acquisitions preclude competitive solicitation from setting the avoided cost price, the regulation only imposes limitations on the use of competitive solicitations in the capacity context.^[401]

ii. Commission Determination

214. We find no merit in the competitive solicitation arguments on rehearing. As an initial matter, we emphasize that the competitive solicitation framework adopted in the final rule: (1) Harmonizes the Commission's precedent on competitive solicitations; (2) establishes transparent and non-discriminatory procedural protections for and encourages the development of QFs; and (3) provides price discovery that may better determine a purchasing utility's avoided cost rates.

215. We disagree with Northwest Coalition's arguments that the final rule goes against Commission precedent in Hydrodynamics and Windham Solar and essentially eliminates the mandatory purchase obligation for QF capacity. In those cases, the Commission found the states' decisions inconsistent with PURPA because the competitive solicitations were not regularly held.^[402] In contrast, the Commission in the final rule found that a properly run solicitation must be held at regular intervals, in which a utility's capacity needs are open for bidding to all capacity providers, including QF and non-QF resources, which is a level playing field for QFs to provide capacity.

216. If a state does not require utility self-build and purchase options to participate in competitive solicitations, then QFs that lose still may have the right to avoided cost capacity rates more than zero if the state determines that the utility still has capacity needs.^[403] The Commission has already determined, and affirmed in the final rule, that capacity rates can be zero.^[404] The possibility of a zero capacity rate does not mean that the Commission has determined that utilities have no obligation to purchase capacity from QFs. It just means that, under our precedent, if a purchasing utility avoids no capacity costs due to the QF purchase, then the avoided cost for capacity will be zero. As we mentioned above, Northwest Coalition has conflated avoided energy costs with long-term power purchase agreements. Long-term avoided costs necessarily represent a utility's avoided capacity costs, and the Commission described how competitive solicitations could be “exclusive” means for obtaining a capacity rate, not an energy rate.

217. Under the final rule, even if a QF loses a competitive solicitation where the state requires utility self-build and purchase options to participate, it is still entitled to an energy rate outside of the competitive solicitation and would receive a capacity rate of zero, which is already permitted under Commission precedent where the purchasing utility's avoided cost capacity value is zero.^[405] The final rule, which largely adopted the NOPR, also provides procedural protections that the Commission has already indicated are prerequisites to competitive solicitations while allowing for a competitive solicitation, under certain conditions, to be a state's exclusive vehicle for setting QF capacity rates.^[406] The final rule therefore merely harmonizes, rather than overrules, that prior precedent.

218. We also disagree with Northwest Coalition's argument that the final rule does not encourage QFs. Using competitive solicitations encourages the development of QFs by providing them a price both consistent with a competitive market and more accurately reflecting a purchasing utility's avoided costs of capacity. The procedural protections the Commission has adopted for conducting competitive solicitations protect QFs from auctions that only benefit the utility's self-build because the QF is still entitled to a capacity rate that may exceed zero if the utility's self-build is not included in the competitive solicitation. Furthermore, the competitive solicitation regulation helps ensure that states can set QF rates no higher than avoided costs while guaranteeing QFs' rights to sell capacity and energy.^[407] In addition, while a competitive solicitation may be the exclusive forum for establishing avoided cost capacity rates, once a state has determined that the competitive solicitation set avoided capacity costs (even if they equal zero), there is no infringement on QFs' rights, and the rule does not allow a utility to evade its purchase obligation.

219. We also disagree with Northwest Coalition's argument that the Commission fails to address multiple commenters' concerns about inherent bias in utility-run competitive solicitations, especially in regions with vertically integrated utility structures like the Pacific Northwest. The final rule described practices that cannot be used and incorporated into the Commission's regulations a requirement for independent administration and review to prevent the exercise of any utility bias. The Commission will not assume that failure to hold an acceptable competitive solicitation in the past will prevent the establishment of an acceptable solicitation in the future given the guard rails for independent administration and review the Commission has now required through the final rule. Indeed, the new rules are designed to ensure that future competitive solicitations are not biased in favor of the purchasing utility. Northwest Coalition's concerns that this new competitive solicitation framework will leave QFs without a contract while they challenge the process or results of a competitive solicitation is misplaced. This framework is not meaningfully different from administrative determinations of avoided costs, wherein a QF might not receive a contract until it has exhausted administrative or judicial processes.

220. Northwest Coalition argues that the Commission failed to explain why it rejected more restrictive criteria proposed by parties, including some of Northwest Coalition's own suggestions. The Commission weighed and considered all proposed criteria in determining which criteria to adopt. We explain below why the Commission did not adopt Northwest Coalition's proposed criteria.

221. First, Northwest Coalition proposed that the Commission require that the competitive solicitation include no utility-ownership options. The Commission did not adopt this criterion because precluding utility ownership from competitive solicitations or limiting how a utility could bid does not provide the price discovery benefit of competitive solicitations.

222. Second, Northwest Coalition proposed that, if utility-owned generation may result from the competitive solicitation, the competitive solicitation must be (1) administered and scored (not just overseen by an independent evaluator) by a qualified independent party, not the utility, (2) any utility or affiliate ownership bid must be capped at its bid price and not allowed traditional cost plus ratemaking treatment, and (3) the product sought, minimum bidding criteria, and detailed scoring criteria must be made known to all parties at the same time (i.e., the utility or affiliate may not have an informational advantage in the RFP).^[408]

223. With regard to Northwest Coalition's proposed criterion for an independent administrator, as noted above, the Commission “decline[d] to be overly prescriptive as to what constitutes an `independent administrator.' ” ^[409] Although this finding in the final rule had to do with whether the Commission required an “independent administrator” or a “third party consultant,” the Commission stated that 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.” ^[410] We continue to believe that we should not be overly prescriptive, but expect states to design competitive solicitations that meet these criteria in a transparent and non-discriminatory manner. To that end, we grant Northwest Coalition's request that a competitive solicitation should be administered and scored by an independent entity. We conclude that this requirement is consistent with our efforts to ensure a fair competitive solicitation and the criteria we established in the final rule pursuant to the Allegheny factors.^[411]

224. Regarding Northwest Coalition's proposal that any utility or affiliate ownership bid must be capped at its bid price and not allowed traditional cost-plus ratemaking treatment, we decline to adopt this criterion on rehearing. The Commission does not have any jurisdiction to dictate how electric utility retail rates should be set. Instead, it is the responsibility of retail regulators to establish the retail rates associated with an award to a utility resulting from a competitive solicitation. And to the extent that Northwest Coalition is arguing that QFs are entitled to cost plus ratemaking, Congress has already determined that QFs are not entitled to the same rate recovery as purchasing utilities. With regard to Northwest Coalition's proposal that the product sought, minimum bidding criteria, and detailed scoring criteria must be made known to all parties at the same time, we find that these requests should already be addressed in the factors adopted by the Commission here, including the first factor, that the process be open and transparent, and the fifth factor, which includes the requirement of a post-solicitation report.^[412] We note that our inclusion of the Allegheny principles also addresses the concerns underlying this proposal.

225. We disagree with Northwest Coalition's argument that the final rule ignores the lack of reasonable enforcement. If a QF believes that it was improperly excluded from a competitive solicitation or lost a competitive solicitation that did not meet the criteria in the final rule, the QF may bring an enforcement action to the Commission or other appropriate fora. Further, the final rule more clearly establishes how states must run their auctions, and we do not presume at this juncture that states will fail to follow these new rules. If the Commission or a court finds that a competitive solicitation violates these criteria, then a remedy may be warranted, for example a court may decide to require a state to provide a specific rate to a QF or re-run the competitive solicitation pursuant to those criteria.

226. We also disagree with Northwest Coalition's argument that the final rule relies on insufficient evidence that small QFs and those primarily engaged in a business other than power production (e.g., irrigation districts and waste-to-power facilities) can succeed in the type of all-source competitive solicitation identified in the rule. We find that it may be difficult to define which entities could qualify for this exemption and that this exemption may defeat the price discovery benefits of including these entities in competitive solicitations. We believe that a fairly administered competitive solicitation is a more accurate reflection of a purchasing electric utility's avoided energy and capacity costs. Moreover, in addition to the requirement to provide standard rates for QFs 100 kW and below, states already have discretion to set that standard rate threshold above 100 kW. Removing their discretion to determine which entities must participate in competitive solicitations may undermine the price discovery benefit of competitive solicitations.

227. We disagree with Public Interest Organizations' claim that the final rule does not address its argument that Nevada's competitive solicitation process is unfair because it limits to QFs to meet a small, segregated portion of the utility's energy and unmet capacity requirements. The final rule does not apply to competitive solicitations, like the one in Nevada, that occurred prior to the effective date of the final rule. For that reason, the Commission did not address Public Interest Organizations' concerns with the Nevada process in the final rule, nor will we do so here.^[413] Any future competitive solicitation must meet the criteria outlined in the final rule, including the Allegheny principles.^[414] We clarify that, if a competitive solicitation is not conducted in accordance with the requirements of the final rule guidelines, then an aggrieved entity may challenge the competitive solicitation before the Commission or in the appropriate fora.

228. A state must still ensure that QFs are entitled to an as-available energy avoided cost rate regardless of whether they win a competitive solicitation for capacity.^[415] Such as-available avoided cost energy rates could be determined as a result of the competitive solicitation, a competitive market price, or the avoided cost regulations in 18 CFR 292.304(e) that pre-date the final rule.

229. We reject Mr. Mattson's argument that the competitive solicitation framework infringes on a “constitutional law right to contract.” ^[416] Regardless of the outcome of a competitive solicitation, the PURPA Regulations continue to permit QFs to negotiate agreements with electric utilities that differ from those required by PURPA.^[417] Similarly, the Commission's requirement in the final rule that a QF may receive a capacity rate of zero if the QF loses a competitive solicitation following the framework adopted in the final rule and in which a utility's self-build participated is consistent with the Commission's precedent.^[418] The final rule only governs the maximum rate for a sale made pursuant to the mandatory purchase obligation imposed on purchasing utilities by PURPA, but continues to permit a QF to contract voluntarily at a different rate with a purchasing utility.

230. We disagree with Public Interest Organizations' assertion that the competitive solicitation framework fails to ensure that a competitive solicitation pays QFs the full avoided energy costs because it does not require a utility to obtain all its energy needs through a competitive solicitation.^[419] The primary purpose of a competitive solicitation is to determine a utility's capacity needs, not its energy needs, which can be purchased separately from capacity. The final rule provides that QFs can continue to sell energy to utilities at the purchasing utility's avoided energy costs outside of the context of a competitive solicitation, even if such solicitations are the exclusive vehicle for acquisition of capacity. The new regulatory text in 18 CFR 292.304(c)(8)(ii) provides that:

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.^[420]

231. This regulation provides that the utility presumptively has no avoided capacity costs if all the utility's capacity needs are satisfied through the competitive solicitation. If the utility's avoided energy costs change after a competitive solicitation is conducted, the as-available avoided energy rate for a QF selling outside such a competitive solicitation would necessarily be different than the avoided energy rate determined in the competitive solicitation itself. States must continue to use either competitive market prices or the traditional factors in 18 CFR 292.304(e) to calculate avoided energy costs at the time of delivery for QFs. Under the final rule, where the purchasing electric utility procures all of its capacity, including capacity resources constructed or otherwise acquired by the electric utility, through a competitive solicitation process, the electric utility is presumed to have no avoided capacity costs unless and until it determines to acquire capacity outside of such competitive solicitation process. However, under the final rule, QFs continue to have the opportunity, outside of a regularly held competitive solicitation, to sell energy at a purchasing utility's avoided cost rate.

C. Rebuttable Presumption of Separate Sites

232. In the final rule, the Commission determined 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. If a small power production facility seeking QF status is located 10 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 10 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.^[421]

233. The Commission adopted 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-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. The Commission stated that it would allow any interested person or entity to challenge a 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.^[422]

234. The Commission also adopted the NOPR's proposed factors, with certain additions.^[423]

1. Need for Reform

235. In the final rule, the Commission found 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. The Commission found 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.^[424]

a. Requests for Rehearing

236. Public Interest Organizations reiterate that there is little or no evidence of circumvention in the record.^[425] Public Interest Organizations argue that a theoretical threat that has failed to materialize in any significant way during 40 years of small power-production facility development sufficiently for the Commission to consider it more than a possibility does not justify the burden imposed by the final rule.^[426] Similarly, Solar Energy Industries assert that changing one-mile rule precedent to prevent gaming without any evidence of gaming in the record is arbitrary and capricious and will discourage QF development.^[427] Solar Energy Industries contend that the Commission is seeking to reduce the number of QFs that can be constructed in any one territory.^[428]

237. Public Interest Organizations argue that, assuming that it is true that some QF developers are indeed making siting decisions based on the one-mile boundary, it will be just as likely that they will make siting decisions based on the ten-mile boundary; therefore, expanding the radius from one mile to 10 miles does nothing to address the purported problem of gaming boundaries.^[429] Public Interest Organizations contend that developers will take the boundary into account when making siting decisions, which is not to game the system but rather to play by the rules.^[430] Solar Energy Industries agree that facilities that are sited more than one mile apart have not “gamed” the one-mile rule; rather, those facilities have complied with the one-mile rule.^[431]

b. Commission Determination

238. As the Commission explained in the final rule, the record shows that some large facilities were disaggregating into smaller facilities and strategically spacing themselves slightly more than one mile apart in order to be able to qualify as separate small power production facilities.^[432] Because PURPA provides advantages for small power production facilities, i.e., no larger than 80 MW, not large facilities that exceed that cap and have disaggregated into smaller facilities under that cap, and based on evidence and examples of QFs separating into several smaller QFs just over one mile apart (in efforts to be considered separate QFs for purposes of the one-mile rule), the Commission determined that reform of the one-mile rule was necessary.

239. The following specific examples demonstrate the need for the Commission to revise the one-mile rule. The Idaho Commission gave the example of a group of five projects that had originally been proposed as a single project greater than 80 MW and not eligible for PURPA. This project was disaggregated into five smaller projects, each separated by one mile, which were then eligible for Idaho's standard published rate contracts at that time. The estimated cost impact of these five projects disaggregating in order to qualify for more favorable standard rate contracts was $10 million per year over the term of the contract.^[433] The Idaho Commission also provided a chart showing the wind projects brought before the Idaho Commission in 2009 and 2010, explaining that the circumstances of these projects suggest that they were disaggregated to qualify for the more favorable standard rate or to take advantage of PURPA's must-purchase obligation.^[434]

240. Commissioner Paul Kjellander of the Idaho Commission also stated that, within Idaho Power's territory, there were 183 MW of power from four developers that were broken up into 16 projects. He stated that the Oregon Commission approved six PURPA projects that require Idaho Power to take 60 MW of power from six solar projects, adding that the similarities among these six projects include the same operation dates, project size, terms and payment conditions, developer, and solar panel manufacturers. He concluded that this looked like a disaggregated project that stretched the spirit and intent of PURPA.^[435]

241. EEI and Xcel argued that the one-mile requirement can be evaded as resources with common ownership, financing, and even operation are located just slightly over one mile from each other to qualify for the 80 MW threshold in the statute. EEI and Xcel provided the example of Northern Laramie Range Alliance, in which the applicant filed for QF self-certification of two 48.6 MW projects that were part of a single wind farm with one site permit and that shared a point of interconnection. Because the projects were located more than one mile apart, each project was certified as an individual QF.^[436]

242. Furthermore, large power stations based on modular generation technologies like solar photovoltaic (PV) panels and wind turbines can relatively easily be presented as subsets of the component generation modules in order to appear as multiple smaller generation stations, even if they act and operate as one large (i.e., over 80 MW) power station in reality.

243. Based on these concerns and evidence of large facilities disaggregating into small facilities in order to circumvent the one-mile rule and receive QF status, the Commission determined that it would be best to address the circumvention of the one-mile rule by reforming the one-mile rule, not simply addressing this concern on a case-by-case basis.

244. We agree that QF developers may make siting decisions based on the 10-mile boundary just as they may have in the past based on the one-mile boundary. However, in the final rule, the Commission found that, at 10 miles or more apart, it can be assumed that affiliated small power production facilities are sufficiently far apart that it is reasonable to treat them as irrebuttably at separate sites.^[437] In contrast, the Commission found that, for affiliated small power production facilities using the same resource that are more than one mile but less than 10 miles apart, the distinction between same site or separate site was not as clear and thus provided for a rebuttable presumption of separate sites.^[438] In adopting these boundaries and accompanying presumptions, the Commission recognized that 10 miles is a more reasonable place to draw the line of irrebuttably separate sites than the previous one-mile boundary, and provided for the ability to rebut the presumption for affiliated small power production facilities in the less clear, grey zone where affiliated facilities are more than one mile apart but less than 10 miles apart.^[439]

245. We disagree with Public Interest Organizations and Solar Energy Industries' contentions that taking the boundary into account when making siting decisions is not gaming the system but playing by the rules and that the Commission seeks to reduce the number of QFs that can be constructed in any one territory. We find that disaggregation practices—whereby a facility exceeding the 80 MW cap and therefore unable to take advantage of the benefits of PURPA (such as mandating that the utility buy its output) disaggregates into several smaller facilities for the purpose of fitting within the statutory mandate and receiving the benefits of PURPA—contradict the spirit and purpose of PURPA. PURPA section 210(a) directs the Commission to encourage cogeneration and small power production.^[440] PURPA 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.^[441] The statute bestows certain advantages on small power production, not on large power production facilities that masquerade as small power production. Disaggregation practices aim to advantage large power production facilities with benefits that they are not eligible to receive. The intention of the new same site determination framework is not to reduce the number of QFs that can be constructed in an area, but to encourage small power production facilities as Congress intended under PURPA.

2. Distance Between Facilities

246. In the final rule, the Commission adopted the NOPR proposal that an entity can seek to rebut the presumption of separate sites only for a small power production facility seeking QF status that have an affiliated small power production QF or QFs that are located more than one and less than 10 miles from it.^[442] The Commission recognized that it is debatable where to set these thresholds. The Commission stated that PURPA requires that no small power production facility, together with other facilities located “at the same site,” exceed 80 MW and Congress has tasked the Commission with defining what constitutes facilities being at the same site for purposes of PURPA. The Commission found that providing set geographic distances will limit unnecessary disputes over whether facilities are at the same site; therefore, the Commission must choose reasonable distances at which small power production facilities will be considered irrebuttably at the same site or irrebuttably at separate sites.^[443]

247. The Commission found that 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 and that one mile or less is a reasonable distance to treat such facilities as irrebuttably at the same site. The Commission found that 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 and found 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 found that the distinction between the same site or separate site is not as clear; therefore, it is reasonable to treat them as rebuttably at separate sites but to allow interested parties to provide evidence to attempt to rebut that presumption. The Commission found 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 that are being developed as QFs, such as modular solar or wind power plants, and provides for improved administration of PURPA. The Commission therefore determined that the one-mile and 10-mile limits are reasonable inflection points for differentiating between the same site and separate sites.^[444]

248. In the final rule, the Commission explained that, with respect to hydroelectric generating facilities, the regulations currently provide that the same energy resources essentially means “the same impoundment for power generation,” finding that it is unlikely that hydroelectric generating facilities located more than one mile apart would rely on the same impoundment.^[445] The Commission explained that, if that circumstance arises, the applicant could seek waiver, and argue that its facilities should not be considered at the same site.^[446]

249. The Commission also noted that it was retaining the 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.^[447]

a. Requests for Rehearing

250. Public Interest Organizations argue that the Commission does not connect the one-mile and 10-mile rule to the statutory phrase “located at the same site,” instead relying on policy arguments that exceed the statutory text and FERC's authority.^[448] Public Interest Organizations assert that the Commission ignored relevant data presented by commenters and failed to articulate a satisfactory explanation connecting facts to its “ten-mile rule” determination.^[449] Public Interest Organizations contend that the decision was arbitrary and capricious because the Commission ignored relevant data and failed to articulate a satisfactory explanation connecting the facts presented to its determination.^[450] Public Interest Organizations further argue that there is nothing in the record to show that 10 miles is a rational or appropriate threshold for determining whether QFs are at the same site, adding that the record indicates that the new approach will cause regulatory uncertainty and substantial burden on an industry it is supposed to be encouraging.^[451] Similarly, Solar Energy Industries argue that the Commission has not offered any justification for the change.^[452]

251. Public Interest Organizations contend that the Commission does not explain why there should be any geographic distance at which two facilities are irrebuttably considered to be located at the same site.^[453]

252. Public Interest Organizations question whether the same opportunities for waiver provided under the previous bright-line test, which the Commission maintained in the final rule, will apply for facilities within one mile of each other.^[454] Public Interest Organizations argue that, if a facility received a waiver in the past, there is no guarantee that they would receive one again under the final rule.^[455] Public Interest Organizations assert that the inability for an applicant to show that a small power production facility should not be treated as located at the same site as other affiliated facilities using the same resource within one mile discourages QF development.^[456]

253. Public Interest Organizations raise concerns about how the final rule will apply to hydroelectric facilities, asserting that the previous one-mile rule did not penalize hydroelectric facilities that were located in close proximity but should not be deemed to be at the same site.^[457] Public Interest Organizations state that, under the previous one-mile rule, hydroelectric facilities were considered to be located at the same site whenever they use water from the same impoundment.^[458] Public Interest Organizations further state that the final rule creates a new rule that a hydroelectric facility will be considered to be located at the same site as the one for which certification is sought if the facility is “located within one mile of the facility for which qualification or recertification is sought and use[s] water from the same impoundment for power generation.” ^[459] Public Interest Organizations add that a footnote in the final rule states that “[f]or hydroelectric generating facilities, the regulations currently provide that the same energy resources essentially means “the same impoundment for power generation.” ^[460] Public Interest Organizations state that it appears that the Commission in practice would consider a hydroelectric facility to be located at the same site whenever it uses the same impoundment as the facility for which qualification is sought, is located within one mile, or both, which would conflict with the text of the final rule and limit QF development.^[461]

254. Northwest Coalition, Public Interest Organizations, and Solar Energy Industries reiterate NOPR comments that the new rebuttable presumption will increase the “exclusion zone” around a QF's electrical generating equipment from approximately three square miles to over 300 square miles—a 100% increase.^[462] Public Interest Organizations argue that a 100-fold increase in the area in which a party that owns a small power production facility will find it very difficult or impossible to develop another facility is the definition of discouraging small power production facilities.^[463]

b. Commission Determination

255. We disagree with Public Interest Organizations' arguments that the Commission did not provide an explanation for the “10-mile rule” beyond policy arguments and did not adequately connect the “10-mile rule” to the statutory determination of “located at the same site.” PURPA requires that no small power production facility, together with other facilities located “at the same site,” exceed 80 MW, and Congress has tasked the Commission with defining what constitutes facilities being at the same site for purposes of PURPA.^[464] The Commission explained 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 one mile or less apart), there are some facilities that are sufficiently far apart that it is reasonable to treat them as irrebuttably separate facilities.^[465] The Commission believed that the latter distance is 10 miles or more apart.^[466] The statute allows the Commission to determine the meaning of “same site.” ^[467] Pursuant to this discretion, the Commission chose to pick a distance as an inflection point beyond which it is safe to irrebuttably presume separate sites.

256. In response to arguments that the 10-mile demarcation is arbitrary and that nothing in the record supports it as a rational or appropriate threshold,^[468] we note that PURPA requires that no small power production facility, together with other facilities located “at the same site,” exceed 80 MW. In the final rule, the Commission aimed to protect that statutory requirement by ensuring that facilities that, together with other affiliated facilities located “at the same site,” exceeded 80 MW did not receive the benefits that Congress intended only small facilities 80 MW and under to receive. The Commission therefore found that 10 miles is qualitatively a large enough distance to serve as the inflection point beyond which it is safe to irrebuttably presume separate sites, while allowing entities to seek to rebut such presumption between one mile and 10 miles.^[469] Ten miles need not be the only possible choice under the statute in order for it to be considered reasonable; what matters is that the choice made in the exercise of the Commission's discretion does not run afoul of the statue and is reasonable rather than arbitrary and capricious.^[470]

257. We find no merit in Public Interest Organizations' arguments that the final rule does not explain why there should be any geographic distance at which two facilities are irrebuttably considered located at the same site. PURPA requires that no small power production facility, together with other facilities located “at the same site,” exceed 80 MW. As the Commission explained in the final rule, 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. Consistent with long standing practice, the Commission has found that one mile or less is a reasonable distance to treat such affiliated facilities as irrebuttably at the same site.^[471] Additionally, in response to Public Interest Organizations, we reiterate that the final rule retains the waiver provision in 18 CFR 292.204(a)(3), which allow the Commission to waive the method of calculation of the size of the facility for good cause.^[472]

258. In response to Public Interest Organizations' concerns that it is unclear what the waiver provision will mean now that the one-mile rule is irrebuttable, or whether those who previously obtained a waiver will get it again if they recertify, we note that the Commission has always determined whether to grant waivers on a case-by-case basis. The Commission will continue to apply the waiver provision consistent with the Commission's waiver precedent. For example, in Windfarms, Ltd., the Commission granted waiver of the one-mile rule, finding that three clusters of wind turbine generators were at three separate and distinct sites when they “had sufficiently distinct and identifiable topographical and energy resource-related characteristics.” ^[473] In contrast, in Pinellas County, the Commission declined to grant waiver of the one-mile rule because a new generator was within 600 to 700 feet of the existing generator.^[474]

259. We disagree with Public Interest Organizations that the final rule establishes a new rule that hydroelectric facilities are at the same site if they are located within one mile of the facility for which qualification is sought and at the same impoundment. The final rule did not change the prior requirement that hydroelectric facilities are at the same site if they are located within one mile of the facility for which qualification is sought and at the same impoundment.^[475] The only change that the Commission made in the final rule was to create a rebuttable presumption of separate sites for affiliated small power production facilities located more than one mile but less than 10 miles apart. Footnote 769 of the final rule, noted by Public Interest Organizations, explains that it is unlikely that hydroelectric generating facilities located more than one mile apart would be located on the same impoundment. We clarify that, if a hydroelectric generating facility is more than a mile apart (but less than 10 miles apart) from an affiliated facility, yet on the same impoundment, the rebuttable presumption would be that they are at separate sites. We further clarify that, although the second sentence of footnote 769 suggested that a hydroelectric generating facility in this circumstance was free to seek waiver (most likely in order to eliminate any uncertainty as to its status), it would be unlikely that any such a facility would, in practice, need to request such waiver.

260. In the final rule, the Commission addressed Northwest Coalition, Public Interest Organizations, and Solar Energy Industries' contention that the new rule causes a 100-times increase to the “exclusion zone” around a QF's electrical generating equipment and a 100-fold increase in the area in which a party who owns a small power production facility will find it very difficult or impossible to develop another facility is almost the definition of discouraging small power production facilities.^[476] We reiterate that the rule providing for a rebuttable presumption for affiliated small power production QFs located more than one but less than 10 miles apart is necessary to address allegations of improper circumvention of the one-mile rule that had been presented to the Commission.^[477] Furthermore, we disagree with characterizing a rebuttable presumption of separate sites between one mile and 10 miles as an “exclusion” zone for development purposes. While QF developers understandably may prefer that any attempts to rebut be prohibited, our disagreement with their preference (and our establishment of a presumption of separate sites between one mile and 10 miles, albeit a rebuttable presumption) can hardly be equated with enacting a development exclusion zone.

3. Factors

261. In the final rule, the Commission adopted the physical and ownership factors proposed in the NOPR with a few modifications. First, the Commission modified the NOPR proposal by changing 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 referring to “the same site.” Accordingly, the Commission adopted these factors as relevant indicia of whether affiliated small power production facilities are “at the same site.” Second, the Commission modified the NOPR proposal to identify the following additional physical factors as indicia that small power production facilities should be considered located at the same site: (1) Evidence of shared control systems; (2) common permitting and land leasing; and (3) shared step-up transformers.^[478]

262. Specifically, the Commission adopted the following factors 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), 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.^[479]

263. The Commission adopted 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 affiliated small power production QFs more than one but less than 10 miles away from it. The Commission stated that any party challenging a 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 miles from that facility are actually at the same site.^[480]

264. The Commission emphasized that, as a general matter, no one factor is dispositive. The Commission stated that it 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.” ^[481]

a. Requests for Rehearing

265. Solar Energy Industries assert that in adopting the physical and ownership characteristics as proposed in the NOPR, the Commission stepped beyond the statutory bounds that limit the Commission to determining whether a facility is located “at the same site” as any other facilities,^[482] instead imposing a separate facilities analysis. Solar Energy Industries argue that the Commission has previously recognized that “[t]he critical test under PURPA relates to whether the facilities are located at one site rather than whether they are integrated as a project.” ^[483] Solar Energy Industries contend that the Commission erred in concluding that ownership and other characteristics are germane to the “same site” determination.^[484] Solar Energy Industries claim that Congress did not authorize the Commission to analyze factors that have nothing to do with physical commonality or surrounding geographical terrain as part of the same site determination.^[485]

266. Similarly, Public Interest Organizations assert that the Commission's definition of “at the same site” is “beyond the meaning that the statute can bear.” ^[486] Public Interest Organizations argue that the American Heritage Dictionary defines “site” as “[t]he place where a structure or group of structures was, is, or is to be located.” ^[487] Public Interest Organizations contend that the statute limits multiple QF facilities to the 80 MW cap only if those facilities are located at the same physical place.^[488] Public Interest Organizations claim that whether affiliated generators using the same energy resource and which are located between one mile and 10 miles are located at separate sites depends on various non-exclusive and non-dispositive factors, many of which have no relationship to whether the two facilities are located in the same physical place.^[489]

267. Public Interest Organizations argue that the reasonable meaning of the phrase does not permit the Commission's definition that introduces numerous extraneous factors, such as corporate structure, financing, offtake entities, number of energy sources or “motive forces,” shared use of offsite engineering services or maintenance contractors, or construction timelines.^[490] Solar Energy Industries assert that the employment of common contractors, such as grading and electrical contractors, has nothing to do with whether two otherwise distinct generation facilities are located at the “same site,” instead having more to do with the availability of experienced, qualified contractors in a given region.^[491] Solar Energy Industries contend that many QFs are developed in rural regions where there are often a limited number of qualified maintenance providers and a commonality of such engagement should not be a factor in the Commission's “same site” analysis. Solar Energy Industries add that the fact that two facilities are constructed by the same entity within a period of 12 months is also irrelevant for a “same site” determination given that there are a limited number of qualified construction firms within each region.^[492] Solar Energy Industries claim that portfolios of QFs in multiple states (and which thus are unquestionably at separate sites) are frequently financed (and re-financed) as part of a common investment portfolio for passive investment vehicles that do not exercise day-to-day control over the QF; therefore, they should not determine whether two facilities with separate ownership structures should not be consolidated for purposes of the 80 MW size limitation.^[493]

268. Public Interest Organizations argue that there are significant problems with the factors list that render the factors unreasonable, arbitrary, and capricious.^[494] Public Interest Organizations assert that the failed to respond to the flaws raised regarding the factors identified by the Commission for consideration under the rebuttable presumption, instead summarily adopting these factors.^[495] Public Interest Organizations state that commenters identified the list of “physical characteristics,” particularly “control facilities,” “access and easements,” “collector systems or facilities,” and “property leases,” as “far too broad and unclear,” and subject to varying interpretations.^[496] Public Interest Organizations contend that factors listed under “ownership and other characteristics,” such as control and maintenance, are even more problematic.^[497] Public Interest Organizations argue that, in certain geographic regions, there are often a limited number of solar maintenance companies, creating the opportunity for frivolous challenges to QF certifications and recertifications.^[498] Public Interest Organizations point to Southeast Public Interest Organizations' comments that

“[l]ikewise, the sale of electricity to a common utility, the financing of a project through a mutual lender, the construction of a facility through a mutual contractor, the timing of contract execution, and the timing of facilities being placed into service are all factors listed in the NOPR which do not provide relevant evidence as to common ownership requiring facilities to be considered a single unit. The use of these factors will likely prejudice solar facilities constructed nearby each other that used common associates, contractors, or partnering organizations or entities.” ^[499]

269. Public Interest Organizations assert that, rather than grappling with the data and information presented by commenters on these factors, the final rule simply summarizes the critiques and then summarily concludes that these factors shall be adopted in the final rule.^[500] Public Interest Organizations argue that the lack of response to these criticisms and failure to articulate a rationale for why the factors are appropriate for making a same site determination render the Commission's determination arbitrary and capricious.^[501]

270. Solar Energy Industries contend that, by going beyond the same site limitation, the Commission is discouraging the development of these resources.^[502] Solar Energy Industries assert that the Commission's failure to provide support for the expansion of its authority beyond that granted by Congress is arbitrary, capricious, and not consistent with reasoned decision-making.^[503]

271. Solar Energy Industries seek rehearing of the Commission's determination in Paragraph 508 and ask the Commission to rescind dicta and associated regulations allowing for review, evaluation, or consideration of physical and operational characteristics that are not germane to whether a facility, “together with any other facilities located at the same site,” has a power production capacity greater than 80 MW.^[504] Solar Energy Industries argue that, if the Commission does not grant reconsideration, a QF could be subject to challenge throughout the facility's entire useful life based on overly broad factors that are not related to preventing a QF from “gaming” the same-site determination and development of other QFs long after a QF starts operation.^[505]

272. Public Interest Organizations add that, although the final rule allows applicants to “preemptively defend against rebuttal by identifying factors that affirmatively show that its facility is indeed at a separate site,” it does not provide guidance on what these factors are, which creates uncertainty.^[506]

b. Commission Determination

273. PURPA defines small power production facilities as those facilities that 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.” ^[507] Congress notably did not specify that “site” may only encompass consideration of physical or geographic factors; in fact, Congress expressly delegated the determination of “site” to the Commission.^[508] When the Commission adopted the PURPA Regulations in 1980, it determined that the capacity of all facilities within one mile of each other and which use the same energy resource and are owned by the same person, be added together.^[509] Thus, for 40 years the PURPA Regulations implementing “same site” have included examination not only of geography or distance, but also ownership and resource. The final rule's inclusion of physical and ownership factors is a continuation of the Commission's past practice and is not, as Solar Energy Industries contend, an expansion of the Commission's authority. We therefore decline to rescind the list of example factors, as requested by Solar Energy Industries.

274. Solar Energy Industries' reliance on El Dorado is misplaced. In El Dorado, a protester argued that three hydroelectric facilities located more than one mile from each other should nevertheless be treated as a single hydroelectric project, noting that the three facilities were aggregated together as a single project for the purposes of receiving a hydroelectric license. The Commission found that, because the three facilities were located more than a mile from each other, under the then-current regulations, the facilities were located at three distinct sites, despite having been aggregated together for the purpose of receiving a hydroelectric license. The sentence Solar Energy Industries quotes, “the critical test under PURPA relates to whether the facilities are located at one site rather than whether they are integrated as a project,” explains that the requirements for certification as a small power production facility are not the same requirements to receive a hydroelectric license.^[510] The Commission did not address which kind of considerations may go into the same site determination; it merely applied the same site analysis that existed at the time, distinct from other requirements.

275. We disagree with Solar Energy Industries' contention that, if the Commission does not grant reconsideration of the list of example factors, a QF could be subject to challenge throughout the facility's entire useful life. We note that, prior to the final rule, an interested party could file a petition for declaratory order challenging the QF certification at any time and on any grounds. An interested party may still file a petition for declaratory order with the accompanying filing fee, just as they could prior to the effective date of the final rule. The final rule merely added what already exists for essentially every Commission proceeding, “no fee” protests, which will not subject a QF to challenges throughout the facility's entire useful life because any such protest must be filed with 30 days from the date of the filing of the Form No. 556 at the Commission.^[511]

276. Moreover, we reiterate that the final rule provided that such protests (and hence, consideration of the factors) may only be filed in response to an initial certification or to a recertification that makes substantive changes to the existing certification,^[512] which limits the time periods during which such a protest may be filed. Additionally, 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 upon which the Commission acted on the certification filing that call into question the continued validity of the earlier certification.^[513]

277. We also disagree with Public Interest Organizations' assertion that the Commission failed to respond to the flaws raised regarding the factors, including that the list of “physical characteristics,” particularly “control facilities,” “access and easements,” “collector systems or facilities,” and “property leases,” was far too broad, unclear, and subject to varying interpretations.^[514] In the final rule, the Commission explained that these are examples of factors the Commission may consider on a case-by-case basis. The factors are not further defined because their application will depend on the context of the individual certification. Likewise, we disagree with Public Interest Organizations' contentions that “ownership and other characteristics” is a problematic factor and “the sale of electricity to a common utility, the financing of a project through a mutual lender, the construction of a facility through a mutual contractor, the timing of contract execution, and the timing of facilities being placed into service” do not provide relevant evidence of common ownership that requires facilities to be considered a single unit.^[515] We reiterate that no single factor is dispositive and the factors are included as examples of facts that the Commission may consider on a case-by-case basis.^[516] For example, Public Interest Organizations state that, in certain geographic regions, there are a limited number of solar maintenance companies, and Southeast Public Interest Organizations NOPR Comments stated that, because of the costs and complexity of financing the construction of QFs, developers frequently secure financing for a portfolio of distinct projects that may be hundreds of miles apart, at clearly separate facilities.^[517] A protester could indeed assert common maintenance or common financing as evidence that a facility is at the same site as another facility, but the Commission could choose to dismiss a protest based on those factors if the protestor's claims are not sufficient to warrant a “same site” finding, particularly if there are no other factors indicating that the facilities are at the same site.

278. Similarly, Public Interest Organizations argues that the Commission must articulate a rationale for why the factors are appropriate for making a same site determination. We believe that, when affiliated facilities are located more than one mile but less than 10 miles from each other and demonstrate these factors, then they may reasonably be considered to be located at the same site. We again stress that, in the final rule, the Commission stated that the factors in the list were merely “examples of the factors the Commission may consider.” ^[518] The Commission will conduct a case-by-case analysis, weighing the evidence for and against determining whether small power production facilities that are owned by the same person(s) or its affiliates are located “at the same site.” The Commission included the example factors in the final rule to provide a guide for the kinds of facts that an applicant seeking QF status or that a protester may assert, and that the Commission may consider in making its determination.

279. In response to Public Interest Organizations' concern that the Commission allows applicants to “preemptively defend against rebuttal by identifying factors that affirmatively show that its facility is indeed at a separate site” without identifying these factors, we clarify that the factors that may be used by an applicant to preemptively defend against rebuttal include the example factors identified in that same Paragraph 509 of the final rule which is the subject of the discussion above.^[519]

D. QF Certification Process

280. In the final rule, the Commission adopted 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. The Commission found 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.^[520] The Commission stated that 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.^[521]

281. The Commission agreed with commenters that QF recertifications to implement or address non-substantive changes should not be subject to the new protest rule in order to respect QFs' settled expectations. The Commission therefore found 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 the 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 the final rule. The Commission explained that 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 five 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. The Commission found that recertifications (both self-recertifications and applications for Commission recertifications) making “administrative only” changes should not be subject to a protest pursuant to the final rule.^[522]

282. The Commission disagreed with Solar Energy Industries' estimates that compliance with these new requirements would require an additional approximately 90 to 120 hours per year. The Commission noted that 18 CFR 292.207(d) already stated 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; hence, it is long-standing practice that a QF must recertify when material facts or representations in the Form No. 556 change.^[523]

283. The Commission explained that certifications and recertifications are already subject to protests, albeit in the form of petitions for declaratory order; therefore, dealing with objections to a certification or recertification is not new. The Commission stated that, although the new procedures may result in more protests being filed than the number of petitions that had been filed, the Commission believed that the conditions imposed in the final rule will limit the number of protests filed. The Commission anticipated 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. The Commission reasoned that 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. The Commission stated that only a small power production facility seeking QF status that has an affiliated small power production QF more than one but less than 10 miles away and that uses the same energy resource would be subject to the rebuttable presumption. The Commission stated that small power production facilities that do not have affiliated small power production facilities will not be affected by the new rebuttable presumption, nor will cogeneration QFs be affected by the new rebuttable presumption. The Commission reiterated that 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 the final rule, and only 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 the final rule.^[524]

284. The Commission instituted time limits on protests that may be filed under the final rule. The Commission adopted the NOPR proposal that interested parties will have 30 days from the date of the filing of the Form No. 556 (both initial self-certification and self-recertification) at the Commission to file a protest (without paying a fee).^[525]

285. The Commission also stated that, even if it indeed takes some small power production facilities an additional 90 to 120 hours to comply with the new requirements (which the Commission thought was unlikely), that was 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 is complying with PURPA.^[526]

286. The Commission found that, due to the unique nature of rooftop solar PV developers, the recertification requirement for PV developers could be unduly burdensome. Therefore, to lessen the burden on such developers when recertifying, the Commission permitted rooftop solar PV developers an alternative option to file their recertification applications. Rather than require the developer to file for recertification each time the developer adds or removes a rooftop facility, the Commission allowed a rooftop solar PV developer to recertify on a quarterly basis. The Commission stated that the recertification 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, the Commission stated that the rooftop solar PV developer would not be required to recertify until it has accumulated changes greater than 1 MW total over the quarters since its last filing. Additionally, the Commission stated 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.^[527]

287. The Commission limited 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. The Commission stated that, 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 the final rule.^[528]

288. The Commission declined to impose a 60-day deadline after which a failure of the Commission to rule on the protest would result in the protest being denied by operation of law. The Commission stated that self-certification will be effective upon filing and will remain effective after a protest has been filed, until such time as the Commission issues an order revoking certification. The Commission clarified that self-recertifications will likewise remain effective after a protest has been filed, until such time as the Commission issues an order revoking recertification.^[529]

289. The Commission noted that 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, explaining that the Commission was simply making this presumption rebuttable.^[530]

1. Requests for Rehearing

290. Solar Energy Industries state that the self-certification process was intended to be “quick and not unduly burdensome” ^[531] to avoid the “complexity, delays, and uncertainties created by a case-by-case qualification procedure” that “would act as an economic disincentive to owners of smaller facilities.” ^[532] Solar Energy Industries argue that the new “[10]-mile rule” adds unnecessary regulatory burdens on QFs which will have a chilling effect on the development of QFs that is directly counter to PURPA's mandate to encourage QF development. Solar Energy Industries assert that, if the Commission does not reconsider the rebuttable presumption framework, the self-certification process will no longer be quick and will become unduly burdensome for all parties, including the Commission and its staff.^[533]

291. Public Interest Organizations state that one of the ways that PURPA directs the Commission to encourage development of small power production facilities is to prescribe rules exempting them from the FPA, PUHCA, and state laws and regulations, as necessary to encourage development.^[534] Public Interest Organizations argue that the final rule does the opposite by requiring applicants to list in Form No. 556 all “affiliated small power production QFs using the same energy resource within one mile,” as well as “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.^[535] Public Interest Organizations note that multiple commenters argued that this proposal would impose a significant burden,^[536] and that the burden is substantial.^[537] Public Interest Organizations contend that the basis for the Commission's estimate that the final rule would impose 62 hours of administrative work on every small power production facility over 1 MW with affiliated facilities between one and 10 miles away is not clear.^[538] Public Interest Organizations note that Solar Energy Industries extensively raised and documented the expected regulatory burden of the new rule, and refer to Solar Energy Industries' estimate that the new rule would require an additional 90 to 120 hours per year to comply.^[539]

292. Public Interest Organizations assert that the Commission's explanation for establishing its new protest procedure is unreasonable and unsupported by the record.^[540] Public Interest Organizations note that the new procedures make it far easier and more likely that an interested party will challenge certification. Both Public Interest Organizations and Solar Energy Industries contend that there is no need for this new procedure because any interested person could file a petition for declaratory order challenging certification.^[541] Public Interest Organizations and Solar Energy Industries claim that, if petitions for declaratory orders have been standing in for protests until now, they should be able to continue to do so without increasing the regulatory burden on small power production facilities by adding a protest option.^[542] Solar Energy Industries add that, while the current $30,000 ^[543] filing fee for petitions for declaratory order is substantial, it is not nearly as substantial as the increased legal fees that QFs will now have to bear to seek and defend certification.^[544]

293. Public Interest Organizations assert that the Commission's new same site determination is contrary to the congressional intent of PURPA because it will discourage small power production facilities.^[545] Public Interest Organizations argue that the litigation risk created by the possibility that various interested parties will protest the facility owners' certifications throughout the life of the project any time there is a change in circumstance will effectively establish a 10-mile exclusion zone for a developer around each small power production facility.^[546]

294. Solar Energy Industries claim that the rebuttable presumption process and procedure will discourage investment in QFs because it brings a substantially increased litigation risk in each certification and recertification.^[547] Solar Energy Industries argue that Congress did not give the Commission authority to undertake a detailed case-specific review to determine if the facility meets the maximum size requirements set forth in the statute.^[548] Solar Energy Industries assert that, by authorizing the Commission to determine whether facilities are considered to be located at “the same site,” Congress did not intend for the Commission to promulgate regulations that would stymie the development of QFs by discouraging potential financiers, investors, and owners from backing such resources.^[549]

295. Northwest Coalition asserts that the application of the final rule's same site determination to existing facilities is arbitrary, capricious, and not in accordance with law.^[550] Northwest Coalition argues that the Commission erred by failing to exempt existing facilities from applicability of the new same site determination for determining eligibility as a small power production facility.^[551] Northwest Coalition contends that the Commission arbitrarily applied the new rule to any existing facility that makes any substantive change to its certification documents with the Commission, causing owners of facilities financed and constructed in reliance on the former one-mile rule now to face the risk of decertification almost any time a non-ministerial change is made, including sale of a relatively minor stake in ownership of the facility.^[552]

296. Northwest Coalition argues that the new rule decreases the marketability of such facilities and upsets investment-backed expectations of their owners, who often invest in a portfolio of resources with the expectation that it can eventually be sold to another owner.^[553] Northwest Coalition argues that the new rule will effectively bar the transfer or sale of existing assets that were lawfully qualified under the one-mile rule but cannot qualify under the new same site determination because they consist of more than 80 MW of aggregate capacity within 10 miles.^[554] It asserts that this new precedent of the Commission upsetting settled expectations undermines the predictability needed for long-term investments in generation assets.^[555]

297. Public Interest Organizations argue that the final rule could lock in old technology because owners of existing facilities will have an enormous incentive to avoid making changes to their facility to avoid needing to recertify.^[556] Public Interest Organizations add that the final rule discourages development of new small power production facilities within 10 miles of existing facilities because the new facilities could potentially trigger revocation of certification for one or more existing facilities.^[557]

298. Northwest Coalition and Public Interest Organizations note that, since 1980, facilities located more than one mile apart enjoyed certainty that the rules would not result in them being located at the same site.^[558] Public Interest Organizations argue that the Commission arbitrarily and unlawfully ignored serious reliance interests because the Commission did not fully consider it or failed to provide a “more detailed justification” for its decision to not respect acknowledged, settled expectations in all cases, despite commenters' lengthy discussion of reliance interest.^[559]

299. Public Interest Organizations assert that the Commission's decision not to grant more extensive legacy treatment for existing facilities whose owners have reasonably relied on the longstanding one-mile rule sets a precedent of dramatic regulatory uncertainty that will have a chilling effect on the market.^[560] Public Interest Organizations contend that, going forward, entrepreneurs will question whether the Commission will further change the regulatory structure, despite longstanding precedent and reliance interests.^[561]

300. Northwest Coalition claims that, the Administrative Procedures Act (APA), pursuant to which the Commission acted, does not authorize retroactive rules; however, the new rebuttable presumption will have the retroactive effect of applying to existing facilities seeking recertification.^[562] Northwest Coalition asserts that the failure to exempt existing facilities is a significant change from the Commission's past practice of applying new certification criteria only to new facilities, not existing facilities seeking recertification.^[563] Northwest Coalition notes that, when the Commission revised section 292.205(d) of its regulations regarding the new operation and efficiency certification criteria required by the Energy Policy Act of 2005 (EPAct 2005) for cogeneration facilities, those new criteria applied only to “any cogeneration facility that was either not a qualifying cogeneration facility on or before August 8, 2005, or that had not filed a notice of self-certification or an application for Commission certification as a qualifying cogeneration facility under [18 CFR] 292.207 of this chapter prior to February 2, 2006. . . .” ^[564] Northwest Coalition further notes that the Commission clarified “that there is a rebuttable presumption that an existing QF does not become a `new cogeneration facility' for purposes of the requirements of newly added section 210(n) of PURPA merely because it files for recertification.” ^[565] Northwest Coalition also points out that, in Order No. 671, the Commission found that only changes to the facility that lead it to be a whole new facility, “such as an increase in capacity from 50 MW to 350 MW,” could trigger the applicability of the new qualification criteria.^[566]

301. Northwest Coalition argues that the Commission did not respond to the precedent on this issue that NIPPC, CREA, REC, and Solar Energy Industries provided in their NOPR comments.^[567] Northwest Coalition asserts that the Commission's failure to respond to legitimate objections renders its decision arbitrary and capricious.^[568]

302. Public Interest Organizations state that several commenters provided data, maps, and information to show that the application of the new “[10]-mile rule” to existing projects has potentially widespread implications for states with significant QF development.^[569] For example, Public Interest Organizations point out Southeast Public Interest Organizations' comment that the change to the one-mile rule would have implications for nearly every existing QF in North Carolina and map that shows that facilities in compliance with the original one-mile rule are within 10 miles from other QFs and could trigger the new rule on recertification.^[570]

303. Public Interest Organizations complain that, although the Commission responded to these concerns by limiting protests to recertifications to instances in which a substantive change is made to an existing certification, it provided no further explanation or rationale as to how the “substantive change” limitation would specifically address the concerns raised.^[571] Public Interest Organizations add that the Commission failed to consider the valid concerns because the term “substantive changes” is vague and undefined and is unlikely to meaningfully limit protests.^[572]

304. Solar Energy Industries argue that, if the Commission does not grant rehearing of the “10-mile rule,” then the Commission must establish a grandfathering provision for facilities that are already installed.^[573] Solar Energy Industries ask the Commission to clarify that all existing facilities will retain their QF status unless a recertification filing is made that changes the maximum net output or qualifying technologies of the QF.^[574] Solar Energy Industries assert that, unless there is a change in the output of the facilities or another change in circumstance that has economic consequences to the utility-purchaser, then the facility's status should be beyond challenge.^[575] Solar Energy Industries contend that failing to offer grandfathering to existing facilities is arbitrary, capricious, inconsistent with Commission precedent that preserves contractual expectations between parties in the event of regulatory change, and does not encourage QFs as the statute requires.^[576]

305. Solar Energy Industries state that, if the Commission does not grant rehearing and grandfather existing facilities, then they seek clarification that challenges to recertification filings can only be brought “in circumstance that has economic consequences to the utility-purchaser and its ratepayers.” ^[577] Solar Energy Industries argue that, by limiting challenges to existing facilities to situations where there is a change in output of the facilities or other change in circumstances that has economic consequences to the utility-purchaser and its ratepayers, the final rule will more closely align with the direction of the statute.^[578]

2. Commission Determination

306. As explained in the final rule (and also above), the record shows that large facilities were disaggregating into smaller facilities and spacing themselves at a distance sufficient to be able to qualify as QFs. PURPA provides advantages for small power production facilities, and the final rule, consistent with the statute, limits those advantages to small power production facilities. To that end, the purpose of the new rules regarding the same site determination is to ensure compliance with PURPA.

307. We disagree with Solar Energy Industries' arguments that the “[10]-mile rule” adds unnecessary regulatory burdens, making the self-certification process no longer “quick and not unduly burdensome.” The changes to the one-mile rule and the corresponding changes to the Form No. 556 are necessary to provide the Commission the information it needs to determine whether a facility qualifies to be a QF, consistent with the standards laid out in the statute. In particular, the new requirement to list 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, both on initial certification and recertification, is needed to assess whether the applicant facility and other affiliated facilities using the same energy resource are located at the same site and ultimately whether they meet the statutory 80 MW limit. Moreover, the requirement is to list affiliated small power production QFs; thus, only facilities with affiliates will be affected by this information requirement—single, unaffiliated QFs will face no additional burden. Similarly, for QF applicants with few affiliated facilities less than 10 miles from the applicant facility, this listing requirement should be only minimally burdensome. The requirement to list affiliates less than 10 miles from the applicant facility would likely require more time when a project owner owns many QFs less than 10 miles from the applicant facility, which will likely be a larger, more sophisticated QF developer that has resources to prepare the form. Even then, it is a necessary burden in order to ensure compliance with PURPA.

308. Additionally, in response to Solar Energy Industries' argument that the final rule adds unnecessary regulatory burden “on QFs,” ^[579] the final rule was responsive to comments on the burden of the proposed rule and, as an example of the Commission taking care to ascertain that the rules are not unduly burdensome, specifically lessened the burden on rooftop solar PV developers.^[580]

309. However, in light of Public Interest Organizations' and Solar Energy Industries' renewed assertion that the regulatory burden on QFs is substantial,^[581] we modify and clarify our requirements regarding the identification of affiliated small power production QFs, in order to further ensure that the regulatory burden on small power production facilities is within reasonable limits. The new Form No. 556, as revised by the final rule, requires that a facility filing a certification or recertification after the effective date of the final rule identify, in item 8a of the Form No. 556, any affiliated small power production QFs that use the same energy resource and are located less than 10 miles from the electrical generating equipment of the applicant facility, by including in the Form No. 556 each affiliated facility's: (1) Location, including geographic coordinates; (2) root docket number, if any; (3) maximum net power production capacity; and (4) common owners. Section 292.207(d) of the Commission's regulations, which the final rule renumbered to 18 CFR 292.207(f), 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.^[582]

310. As a result, when any of a small power production QF's affiliated facilities less than 10 miles away changes any of the items listed above, the final rule would require a small power production QF to recertify its own Form No. 556 to reflect its affiliated facility's updated information. This represents an expansion from the requirement prior to the final rule that a small power production QF reflect the updated information of its affiliated small power production facilities one mile or less away.^[583] Moreover, in order to maintain an up-to-date Form No. 556 and recertify with the correct affiliated facility information, under the final rule a small power production QF would need to monitor continually all of its affiliated small power production QFs that are less than 10 miles away for changes. This also is an expansion from the requirement, prior to the final rule, that a small power production QF monitor its affiliated small power production QFs one mile or less away for changes.^[584] We conclude that it may be overly burdensome that a small power production QF monitor continually all of its affiliated facilities less than 10 miles away for changes, and that the small power production QF recertify its own facility whenever an affiliated small power production QF less than 10 miles away changes.

311. We therefore modify the final rule to state that a small power production QF evaluating whether it needs to recertify does not need to recertify due to a change in the information it has previously reported regarding its affiliated small power production QFs that are more than one mile but less than 10 miles from its electrical generating equipment, including adding or removing an affiliated small power production QF more than one mile but less than 10 miles away, or if an affiliated small power production QF more than one mile but less than 10 miles away and previously reported in item 8a makes a modification, unless that change also impacts any other entries on the evaluating small power production QF's Form No. 556.

312. We will continue to require that a small power production QF, as it was prior to the final rule, recertify its Form No. 556 to update item 8a due to a change at any of its affiliated small power production facilities that use the same energy resource and are located one mile or less from its electrical generating equipment.^[585] We will also still require that a small power production QF recertify due to a change in material fact or representation to its own facility.

313. At such time as the small power production QF makes a recertification due to a change in material fact or representation to its own facility or at any of its affiliated small power production facilities that use the same energy resource and are located one mile or less from its electrical generating equipment, we will require that the small power production QF update item 8a for all of its affiliated small power production QFs within 10 miles, including adding or deleting affiliated small power production QFs, and recording changes to previously listed small power production QFs, so that the information in its Form No. 556 is complete, accurate, and up-to-date.^[586]

314. We believe that this modification reduces the burden on small power production QFs because they will not be required to continually monitor their affiliated small power production QFs more than one mile but less than 10 miles away for changes, nor will we require a small power production QF that is evaluating whether it must recertify its facility to recertify to update item 8a due to a change at its affiliated small power production facilities more than one mile but less than 10 miles from the evaluating facility's electrical generating equipment.^[587] However, the affiliated QF of that evaluating small power production QF will need to recertify if the affiliated QF makes a material change to its information in its Form No. 556. In providing this modification, we reiterate that the rule providing for a rebuttable presumption for affiliated small power production QFs located more than one but less than 10 miles apart is necessary to address allegations of improper circumvention of the one-mile rule that had been presented to the Commission.^[588] We emphasize that identifying affiliated facilities, and updating affiliated facility information, are necessary for the Commission to assess whether small power production facilities located more than one but less than 10 miles apart should be considered to be at the same site. However, we note that for affiliated small powder production QFs more than one mile but less than 10 miles apart, the presumption is that they are at separate sites. Therefore, we modify the recertification requirement as to a small power production QF's affiliated small power production QFs more than one mile but less than 10 miles away, because we believe this modification strikes an appropriate balance between the need to address improper circumvention and the need to avoid unduly burdening small power production QFs consistent with the presumption that QFs more than one mile but less than 10 miles apart are located at separate sites.

315. We note that, when a small power production QF makes a material change to its own facility, or when any of its affiliated small power production facilities that use the same energy resource and are one mile or less from of its electrical generating equipment makes a material change, it needs to recertify, at which point it would also be required to update item 8a for all of its affiliated small power production QFs within 10 miles. If any of the changes made are substantive, including substantive changes at any of its affiliates less than 10 miles away, the recertification will be subject to protests.^[589]

316. In response to Public Interest Organizations' concerns that existing facilities will lose their certification any time they make a change requiring a recertification, we note that protests may only be made to recertification making substantive changes, and if a substantive change is made, both the entity filing the QF certification and any protesters will be allowed to present evidence supporting their respective positions. The Commission will examine any such evidence presented on a case-by-case basis to determine whether the facility in question does not actually meet the qualifications for QF status under PURPA. For a same site determination, the Commission will examine the relevant factors as discussed above. The Commission will decertify only if, after a review of the evidence, the Commission determines that the facility in question should be considered at the same site with affiliated facilities and their combined power production capacity exceeds 80 MW. The Commission's decision will be based on the evidence of whether the entity continues to comply with PURPA.

317. In response to Public Interest Organizations' assertion that several commenters provided data, maps, and information showing that the application of the new “[10]-mile rule” to existing projects has potentially widespread implications for states with significant QF development ^[590] and argument that litigation risk will effectively establish a 10-mile exclusion zone for a developer around each small power production facility,^[591] we note that the Commission anticipated that most 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.^[592] If two facilities are not owned by the same person(s) or its affiliates, then the facilities are definitionally not located at the same site.^[593] Thus, protests cannot assert that two facilities are at the same site, unless those facilities are affiliates using the same energy resource (and more than one mile but less than 10 miles apart). Conversely only entities that have affiliates will be subject to protests regarding the same site determination. Single, unaffiliated facilities will not be subject to protests on the new same site determination.^[594] Furthermore, facilities with nearby affiliates whose combined capacity does not exceed 80 MW also will not be decertified because of the new same site determination. The only facilities that will have concerns under the new same site determination are those that are affiliated with other facilities using the same energy resource, are relatively near each other, have a total combined capacity with such affiliated facilities exceeding 80 MW, and are considered at the same site by the Commission after a consideration of the evidence.

318. Therefore, assertions that existing QFs risk decertification almost any time they recertify and that the new rule decreases marketability or discourages QF development are overstated. To the extent that the new same site determination decertifies particular QFs, decreases their marketability, or discourages their development, it only does so because such entities do not comply with PURPA. To the extent that large facilities disaggregated in order to qualify as small power production facilities, or strategically built facilities just over one mile apart, in reliance on the old one-mile rule, we note that rules can and do change. In fact, Congress specifically directed the Commission to revise its PURPA rules from time to time.^[595] Moreover, we note that the new regulations do not apply to an existing facility unless and until it makes substantive changes. When the existing QF makes a substantive change, it is no longer the same facility it was before, and it is only then that the new regulations should apply. Additionally, we note that the facilities more than one but less than 10 miles from affiliated facilities continue to enjoy the presumption that they are at separate sites; only now the presumption is rebuttable.

319. The Commission provided examples of factors it may consider when determining whether affiliated facilities using the same resource and more than one mile but less than 10 miles apart should be considered to be at the same site, and stated that it will make a case-by-case determination on whether such facilities are indeed at the same site.^[596] In response to Solar Energy Industries' argument that Congress did not give the Commission authority to undertake a detailed case-specific review, we find that Congress delegated to the Commission the authority to determine the “same site” and did not limit the way in which the Commission can do so, nor did Congress specify that the Commission cannot conduct a case-by-case analysis.^[597]

320. Regarding Public Interest Organizations and Solar Energy Industries' arguments that there is no need for the new protest procedure because any interested person could file a petition for declaratory order to challenge a certification, we further explain the rationale for implementing the new protest structure. First, allowing protests will bring the certification process more in line with other Commission procedures, where protests to filings do not require a petition for a declaratory order and associated filing fee. Second, while self-certifications themselves are free, prior to the final rule, the only way to protest a self-certification was via paying the fee for a declaratory order, which today is $30,060. Consequently, it was possible for a facility owner to file multiple certifications with minor changes effectively shutting out a protester who could not afford to repeatedly pay the declaratory order fee for every QF submission. Allowing protests equalizes the opportunity for both facility owners and opponents to weigh in on the certification of a facility as a QF.^[598]

321. While petitioners are correct that purchasing electric utilities, competitors, and local project opponents now may file protests, we believe that a more robust protest system encourages transparency and allows for better oversight by the Commission, as well as by states and other stakeholders. To the extent that petitioners imply that such entities may file frivolous protests for the purposes of delaying or otherwise hindering QF development or certification, the Commission has limited protests to within 30 days of the date of the filing of an initial certification or of a recertification making a substantive change.^[599] For a facility that meets the standards to qualify as a QF, the only effect is the potential for an exchange of filings immediately after the certification is filed and some limited uncertainty while awaiting the Commission's decision. Additionally, we note that quite often QF developers file for certification even before construction of the facility has commenced; in such a case, the potential for some limited uncertainty during the exchange of filings will have minimal impact. The Commission also has determined that self-certifications will be effective upon filing and will remain effective after a protest has been filed, until such time as the Commission issues an order revoking the certification.^[600]

322. In response to Public Interest Organizations' argument that the final rule does the opposite of exempting QFs from the FPA, PUHCA, and state laws and regulations, the Commission is not removing or amending the exemptions provided by the regulations implementing PURPA section 210(e).^[601]

323. We also disagree with Public Interest Organizations' arguments that “substantive change” is vague and does not limit challenges. In the final rule, the Commission explained that “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.” ^[602] The Commission provided examples of what it may consider to be a substantive change because it intends to make a case-by-case determination. The Commission will be able to reject a protest to a recertification that the Commission does not believe rises to the level of a substantive change.

324. Regarding Northwest Coalition's argument that the APA does not authorize retroactive rules, we disagree with Northwest Coalition's premise that the new rebuttable presumption for affiliated facilities more than one mile but less than 10 miles apart will have retroactive effect when applied to existing facilities seeking recertification. The new regulations do not apply to an existing facility unless and until it must recertify because of changes to the material facts and representations at its facility or that of an affiliated facility one mile or less away. When the existing QF makes a change to the material facts and circumstances of its certification, it very well may no longer be the same facility it was when originally certified. Due to the change in material facts, the new regulations should apply. Thus, the rule is prospective, and applied only if and when new facts have prompted a recertification.^[603]

325. Northwest Coalition argues that the Commission's past practice in developing new certification criteria is to apply the new criteria only to new facilities, not existing facilities seeking recertification.^[604] We disagree. Northwest Coalition relies on Commission Order No. 671, which implemented section 210(n) following EPAct 2005. However, Northwest Coalition overlooks that section 210(n) of PURPA required the Commission to issue a rule revising the criteria for new cogeneration facilities, and therefore the Commission in Order No. 671 focused on defining what is a new facility.^[605] In contrast, here the Commission was not implementing 210(n) and therefore was not revising the criteria solely for new facilities.

326. For the foregoing reasons, we decline to establish further legacy treatment for existing facilities, as requested. Existing QFs that seek to recertify due to substantive changes will be subject to protests. The Commission can determine, on a case-by-case basis, whether the evidence presented represents a substantive change or whether the change is non-substantive and thus not subject to protests, in which case the Commission will dismiss any protests submitted. We decline to specify, as Solar Energy Industries request, that only changes to the maximum net output or the qualifying technology, or in circumstances that have economic consequences to the utility-purchaser and its ratepayers, will make an existing QF's recertification subject to challenge. We likewise disagree with Solar Energy Industries' contention that failing to offer grandfathering to existing facilities is arbitrary, capricious, and inconsistent with Commission precedent. We continue to believe that conducting a case-by-case analysis is the best way to determine whether the change that prompted recertification is substantive, will avoid arbitrary outcomes, and is necessary to comply with the intent of PURPA to provide advantages only to small power production facilities.

E. Corresponding Changes to the FERC Form No. 556

327. In the final rule, the Commission adopted the NOPR proposals regarding changes to the Form No. 556, with some further clarifications and additions. The Commission found that the added information collected through these changes was necessary to implement the changes made to the regulations in the final rule and thus justified the increase in reporting burden.^[606]

328. The final rule revised 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 representations presented . . . in its submittals to the Commission.” ^[607] The Commission stated that this addition does not alter our recertification requirements, and the Commission included it on the Form No. 556 simply to make the Form No. 556 clearer in its application.^[608]

329. The Commission stated that the total burden estimates in the “Paperwork Reduction Act Notice” section of Form No. 556 would be updated based on the changes in the 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.^[609]

1. Requests for Rehearing

330. Public Interest Organizations state that the final rule would impose 62 hours of administrative work on every small power production facility over 1 MW with affiliated facilities between one and 10 miles away and the basis for this calculation is not clear.^[610]

2. Commission Determination

331. Public Interest Organizations misread the final rule on this point. The final rule provided a total burden estimate of 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 apart that use the same energy resource, but 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.^[611] The estimate is not that every small power production facility over 1 MW with affiliated facilities between one and 10 miles away will have a total burden of 62 hours, but only those who chose to apply for Commission certification (as opposed to use the self-certification process). For those who self-certify, the burden estimate is 9.5 hours.

332. In response to Public Interest Organizations' assertion that the basis for the calculation is not clear, below we explain the calculation. Prior to the final rule, “[t]he estimated burden for completing the Form No. 556, including gathering and reporting information, [was] as follows: 1.5 hours for self-certification of a small power production facility . . . 50 hours for an application for Commission certification of a small power production facility. . . .” ^[612] The Information Collection Section of the final rule showed changes due to the final rule and estimated an additional 8 hours for the category “self-certifications” and 12 hours for the category “applications for Commission certification” of small power production facilities greater than 1 MW that are more than one but less than 10 miles from affiliated small power production QFs. Therefore, the total burden estimate as provided in the final rule is as follows: 1.5 hours plus 8 hours for a total of 9.5 hours for self-certifications and 50 hours plus 12 hours for a total of 62 hours for applications for Commission certification.

333. In light of the modification to the final rule described in section III.D, we further modify the “Recertification” section in page one of the instructions of the Form No. 556, which was added by the final rule. The “Recertification” section currently reads “A QF must file a recertification whenever the qualifying facility `fails to conform with any material facts or representations presented . . . in its submittals to the Commission.' 18 CFR 292.207(f).” To this, we will add “Among other possible changes in material facts that would necessitate recertification, a small power production QF is required to recertify to update item 8a due to a change at an affiliated facility(ies) one mile or less from its electrical generating equipment. A small power production QF is not required to recertify due to a change at an affiliated facility(ies) listed in item 8a that is more than one mile but less than 10 miles away from its electrical generating equipment, unless that change also impacts any other entries on the Form 556.”

F. PURPA Section 210(m) Rebuttable Presumption of Nondiscriminatory Access to Markets

334. In the final rule, the Commission acknowledged that, when Order Nos. 688 and 688-A were issued, the Commission decided that small QFs may not have nondiscriminatory access to markets.^[613] In Order Nos. 688 and 688-A, based on factors present at that time, the Commission decided to draw the line for small entities at 20 MW.^[614] However, as stated in the final rule, energy markets have matured and market participants have gained a better understanding of the mechanics of such markets.^[615] In the final rule, the Commission stated that, since Order Nos. 688 and 688-A, the Commission recognized multiple examples of small power production facilities under 20 MW participating in RTO/ISO energy markets.^[616] The Commission stated that it had found that the electric utilities in those proceedings rebutted the presumption of no market access and therefore terminated the mandatory purchase obligation.^[617]

335. The Commission adopted the proposal to revise 18 CFR 292.309(d) to update 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. After reviewing commenters' concerns, the Commission updated the rebuttable presumption from 20 MW to 5 MW, rather than from 20 MW to 1 MW as originally proposed in the NOPR. The Commission explained that 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.

336. The Commission disagreed with commenters who argued that a lack of record evidence existed to support the proposed reduction below 20 MW. The Commission explained that, in Order Nos. 688 and 688-A, the Commission had determined that small QFs may not have nondiscriminatory access to wholesale markets and, therefore, it was reasonable to establish a presumption for small QFs. The Commission explained that, at that time, the Commission had found that it was “reasonable and administratively workable” to define “small” for purposes of this regulation to be QFs below 20 MW.^[618] The Commission noted that a number of commenters, including state entities which are charged with applying PURPA in their jurisdictions, supported revising the definition of small QFs eligible for the presumption in reducing the 20 MW threshold.

337. The Commission again acknowledged that there is no unique number to draw a line for determining what is a small entity.^[619] The Commission explained that, in establishing the 20 MW presumption as the line between large and small QFs for purposes of section 210(m), the Commission had looked at other non-QF rulemaking orders in which it had considered what constituted a small entity and those orders showed 20 MW was a reasonable number at which to draw the line.^[620] The Commission explained that it had 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, a capacity level of 20 MW may no longer be a reasonable place to establish the presumption on what constitutes a smaller entity under our regulations.

338. The Commission explained that it was updating the rebuttable presumption based on industry changes since Order No. 688. The Commission stated that it was reasonable to update the rebuttable presumption as the markets defined in PURPA section 210(m)(1)(A), (B), and (C) evolve because the statute itself does not establish a presumption and the statue requires the Commission to update the rules from time to time to ensure it complies with PURPA.

339. The Commission explained that, over the last 15 years, the RTO/ISO markets have matured and market participants have gained a better understanding of the mechanics of such markets. As a result, the Commission found 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. The Commission further explained that, as in Order No. 688, it looked to indicia in other orders to determine where the presumption should be set.^[621]

340. The Commission found that market rules are inclusive of power producers below 20 MW participating in markets. The Commission explained that, 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.^[622]

341. The Commission found that, 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. The Commission found that 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.^[623]

342. The Commission explained that, 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.^[624] The Commission explained that these proposals require RTO/ISOs to revise their tariffs to provide easier access for smaller resources. The Commission determined that requiring markets to accommodate storage resources as low as 100 kW also supports this finding that resources smaller than 20 MW have nondiscriminatory access to those RTO/ISO markets. The Commission stated that it believed that these developments support updating the 20 MW presumption to a lower number.

343. The Commission found that, when these changes are viewed together, their cumulative effect demonstrates that it is reasonable for the Commission to maintain a small entity presumption but update its determination of what is a small entity under this presumption under the PURPA Regulations. The Commission found that 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.^[625]

344. The Commission recognized that certain of these precedents would support reducing the presumption below 5 MW and perhaps even lower than 1 MW. The Commission explained that it 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.^[626] The Commission therefore determined that 5 MW is a more reasonable threshold of non-discriminatory access to RTO/ISO markets.

345. The Commission therefore found it reasonable to update the presumption under these regulations as to what constitutes a small entity that is presumed to have 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. The Commission acknowledged that “there is no unique and distinct megawatt size that uniquely determines if a generator is small.” ^[627] The Commission found 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.^[628]

346. The Commission explained that individual small power production QFs that are over 5 MW and less than 20 MW can seek to make the case; however, they do not truly have nondiscriminatory access to a market and should still be entitled to a mandatory purchase obligation.^[629]

347. The Commission disagreed with Advanced Energy Economy's argument that the Commission failed to sufficiently justify its change in policy.^[630] The Commission noted that, 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.” ^[631]

348. The Commission clarified that it was maintaining its determination from Order No. 688 that small entities potentially may not have non-discriminatory access for purposes of PURPA section 210(m). The Commission explained that it had determined that using 20 MW as an indicator of what constitutes a small entity is no longer valid. The Commission found that entities below 20 MW increasingly have access to the markets and become familiar with practices and procedures and that markets have since implemented changes to provide easier access to smaller facilities, including small power production QFs, storage facilities, and distributed energy resources. The Commission found that these changes demonstrate a change in facts since the time it issued Order No. 688, which supports updating what constitutes a small entity for purposes of PURPA section 210(m).^[632]

349. The Commission explained that, while it found that it is reasonable to update the rebuttable presumption from 20 MW to 5 MW, it recognized 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. The Commission explained that, to address these concerns, it was 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. The Commission clarified that 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.^[633]

350. The Commission added to 18 CFR 292.309(c) the following 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 QF'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. The Commission explained that this list was not intended to be an exhaustive list of the factors that a QF could rely upon in seeking to rebut the presumption. The Commission further explained that these factors, among other indicia of lack of nondiscriminatory access, would be assessed by the Commission on a case-by-case basis when considering a claim that the presumption of nondiscriminatory access to the defined markets should be considered rebutted for a specific QF.^[634]

351. The Commission found that the addition of these factors addressed 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.^[635] The Commission explained, for example, that, 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, 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.^[636]

352. The Commission further explained that, for example, several commenters expressed 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, the Commission 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.^[637]

353. The Commission agreed with commenters that some small power production facilities are similar to cogeneration facilities because their predominant purpose is not power production. The Commission found that, 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. The Commission therefore allowed the small subset of small power production facilities that are between 20 MW and 5 MW to rebut the presumption of access to markets when the predominant purpose of the facility is other than selling electricity, and the sale of electricity is simply a byproduct of that purpose. The Commission recognized that, like all QFs over 20 MW, 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.^[638]

1. Requests for Rehearing and Clarification

354. Northwest Coalition, Public Interest Organizations, and Solar Energy Industries contend that the Commission erred in revising the rebuttable presumption for QFs between 5 MW and 20 MW, arguing that the Commission failed to demonstrate that QFs between 5 MW and 20 MW have nondiscriminatory access to markets prior to shifting the burden from requiring utilities to demonstrate QFs 20 MW and under have non-discriminatory access to markets to requiring QFs between 5 MW and 20 MW to prove that they do not have access.^[639] Public Interest Organizations, Northwest Coalition and Solar Energy Industries argue that, under the terms of section 210(m), a utility must “set forth the factual basis” showing that QFs have non-discriminatory access to the market, and the Commission is statutorily required to determine if the record sufficiently demonstrates that QFs have non-discriminatory access to the market before terminating the mandatory purchase obligation.^[640] Public Interest Organizations argue that general presumptions that conditions are improving for small QFs to access competitive markets is insufficient justification.^[641]

355. Northwest Coalition and Public Interest Organizations assert that there is no evidence that circumstances have changed since Order No. 688, arguing that most QFs 20 MW and under (1) are still connected to lower-voltage distribution facilities that are subject to state regulations instead of Commission-regulated interconnection procedures; and (2) require technical enhancements, face pancaked rates, and additional administrative burdens.^[642] Public Interest Organizations contend that the Commission has repeatedly concluded that QFs below 20 MW face obstacles to transmission access in RTO/ISO regions that prevent them from participating in competitive markets.^[643] Northwest Coalition and Public Interest Organizations claim that the only two examples of small QFs selling into wholesale markets that the Commission included in the final rule did so with a larger, more experienced company acting on their behalf.^[644] Public Interest Organizations and Northwest Coalition contend that there is no evidence that small QFs are actually participating in regional markets, therefore, it is impossible to conclude that small QFs do so regularly.^[645]

356. Northwestern Coalition and Public Interest Organizations dispute the Commission's claims that (1) small QFs have gained a better understanding of the markets; (2) changes to interconnection rules indirectly support small QFs' access to markets; and (3) changes in RTO/ISO market rules to accommodate energy storage resources support the Commission's finding that QFs between 5 and 20 MW have non-discriminatory access to markets.^[646] Northwestern Coalition and Public Interest Organizations argue that the Commission provided no evidence that small QFs have gained a better understanding or how that understanding helped them overcome the obstacles small QFs face in accessing markets.^[647] Northwestern Coalition and Public Interest Organizations assert that the adoption of fast-track procedures for facilities under 5 MW or accommodations for energy storage resources do nothing to support access by QFs between 5 and 20 MW to markets.^[648] Northwest Coalition contends that the Commission also ignored evidence that smaller resources face unique barriers to accessing competitive markets, such as that the standard trading block in wholesale markets is 25 MW, or that requiring transmission be scheduled in 1 MW blocks place a disproportionate burden on small generators.^[649]

357. One Energy claims that behind-the-meter distributed energy resources (DERs) are more like cogeneration than small power production because their primary purpose is to directly power homes and business and not to sell energy at wholesale.^[650] Therefore, One Energy argues that the final rule was “unduly discriminatory” in finding that behind-the-meter DERs between 5 and 20 MW have non-discriminatory access to markets. One Energy asserts that behind-the-meter resources should be exempted from the reduction like cogeneration facilities. Further, One Energy contends that the Commission cited QFs that are similar to cogeneration facilities, such as solid waste facilities and biogas facilities, but did not specifically include behind-the-meter DERs. One Energy argues that at a minimum the Commission should list behind-the-meter DERs like other categories of small power production facilities that are entitled to rebut the presumption of nondiscriminatory market access.^[651]

358. One Energy also seeks clarification as to how the new same site determination rules will affect the PURPA section 210(m) presumption that small power production facilities with a net power production capacity at or below 5 MW do not have nondiscriminatory access to markets. One Energy states that it has three behind-the-meter wind projects with three separate off-takers, within one mile of each other. One Energy is concerned that, if one of the off-takers no longer takes service, the Commission would aggregate the formerly behind-the-meter facility with the other facilities within one mile, find that the three together are 15 MW and consequently find that the formerly behind-the-meter facility is not eligible for the below 5 MW presumption.^[652]

359. Public Interest Organizations assert that the rebuttable list of factors is only included in 18 CFR 292.309(c) and was not added to 18 CFR 292.309(e) that applies to QFs in ISO-NE, MISO, NYISO and PJM nor in 18 CFR 292.309(f) that applies to QFs in ERCOT. Public Interest Organizations request that, to prevent unnecessary confusion, the Commission incorporate the factors listed in 18 CFR 292.309(c) into both (e) and (f).^[653]

2. Commission Determination

360. We disagree with parties' arguments and reaffirm the finding that market conditions have changed since the issuance of Order No. 688. In establishing the original rebuttable presumption of 20 MW in Order No. 688, the Commission relied on the market conditions at that time. As the Commission stated, markets have matured and the markets have provided, and continue to provide, increased access to smaller resources demonstrating the need for the Commission to reconsider its definition of small power production QFs. In the final rule, the Commission updated the relevant definition of a small power production facility for purposes of 292.309 to be 5 MW and, despite the arguments on rehearing, we affirm that finding here.^[654]

361. We disagree with arguments that the Commission did not provide sufficient support for its finding that QFs between 5 and 20 MW can be presumed to have non-discriminatory access competitive markets. Specifically, the Commission explained that, 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.^[655] The Commission explained that these proposals require RTO/ISOs to revise their tariffs to provide easier access for smaller resources. The Commission determined that requiring markets to accommodate storage resources as low as 100 kW also supports this finding that resources smaller than 20 MW have nondiscriminatory access to those RTO/ISO markets. Further, 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.^[656] The Commission stated that it believed that these developments support updating the 20 MW presumption to a lower number.^[657]

362. While these factors were a sufficient basis to support the Commission's action, they were by no means an exhaustive recitation of relevant developments in competitive markets since Order Nos. 688. For example, as the Commission noted in another recent rulemaking, all of the RTOs/ISOs have at least one participation model that allows resources as small as 100 kW to participate in their markets.^[658] Indeed, even since the final rule, the Commission has continued to provide greater opportunities for small power production facilities to participate in wholesale organized markets.^[659]

363. Regarding arguments from Public Interest Organizations and Northwest Coalition that the final rule failed to consider that smaller resources face unique barriers to accessing competitive markets, we disagree. In the final rule, the Commission carefully considered such concerns and amended 18 CFR 292.309(c) to include factors that small power production QFs between 5 and 20 MW can use to rebut the presumption of non-discriminatory access to markets.^[660] These factors include (1) specific barriers to connecting to the interstate transmission grid, such as excessively high costs and pancaked delivery rates; (2) unique circumstances impacting the time/length of interconnection studies/queue to process small power QF interconnection requests; (3) lack of affiliation with entities that participate in RTO/ISO markets; (4) 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) having certain operational characteristics that effectively prevent the qualifying facility's participation in a market; and (6) lack of 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.^[661] The Commission adopted the first four of these factors recognizing that some small power production facilities between 5 and 20 MW may lack nondiscriminatory access to markets.^[662] The first four factors address concerns that a small power production QF may lack expertise, either directly or within its corporate family, to access markets defined in PURPA section 210(m)(1) or has operational characteristics or is remotely located such that it faces additional transmission obstacles to reach such markets. Additionally, the Commission applied the last two factors on the list, i.e., “operational characteristics” and “transmission constraints,” which were originally adopted in Order No. 688 for QFs between 20 and 80 MW, to permit QFs between 5 and 20 MW to rebut the presumption that they have non-discriminatory access to markets. This list of factors, we stress, is not exclusive but was adopted in the final rule to address the specific concerns commenters raised in responding to the NOPR.

364. Like the initial regulations implementing PURPA section 210(m), the final rule's revision to the rebuttable presumption merely provides a framework for evaluating whether individual small power production facilities have nondiscriminatory access to the markets defined in PURPA section 210(m); it does not decide that every small power producer QF between 5 MW and 20 MW in fact has nondiscriminatory access. The D.C. Circuit has held that “[t]he fact that FERC chose to adopt certain rebuttable presumptions via rulemaking, rather than by case-by-case adjudication, does not violate any of the statute's requirements.” ^[663] Contrary to Public Interest Organizations' argument,^[664] the rebuttable presumption, if applicable, provides the requisite “factual basis” for a utility to invoke. Conversely, the corresponding factors for rebutting this presumption, if applicable, provide a “factual basis” that a QF may invoke to rebut that presumption.

365. In undertaking this rulemaking, the Commission stated its intent to modify PURPA in light of changed circumstances since it first implemented PURPA section 210(m).^[665] During the rulemaking process, the Commission appropriately reviewed the MW level at which to set a presumption of nondiscriminatory market access for small power production qualifying facilities. As discussed above, a variety of factors have led to the increased ability to access wholesale markets by small power production qualifying facilities, and in supporting this trend of an increased ability to access the energy market, the Commission has established policies and procedures such as the fast-track interconnection process, among others, to accommodate and encourage smaller energy resources' participation in organized electricity markets.^[666] Thus, as the Commission stated in the final rule, 20 MW is no longer the appropriate threshold to presume nondiscriminatory access to markets for small power production QFs under PURPA section 210(m).^[667]

366. In the final rule, as noted above, the Commission addressed commenters' concerns by establishing a list of established specific factors that QFs between 5 and 20 MW can utilize, among others, to rebut nondiscriminatory access.^[668] Commenters stated that small power production QFs 20 MW and less are often located on local distribution systems and have additional hurdles to gain transmission access to energy markets. To address this concern, the Commission established the first factor: Specific barriers to connecting to the interstate transmission grid, such as excessively high costs and pancaked delivery rates.^[669]

367. In response to commenters' concerns over the potential disproportionate high costs and delays a small power production QF between 5 and 20 MW could face, the Commission added the second factor: The unique circumstances impacting the time or length of interconnection studies or queue to process small power producer QF interconnection requests.^[670]

368. Commenters asserted that those QFs between 5 and 20 MW that have larger energy affiliates could access the knowledge and expertise needed to participate in such markets, whereas other QFs could not, which led the Commission to adopt the third factor: A lack of affiliation with entities that participate in RTO/ISO markets.^[671]

369. Commenters representing solid waste, biogas, and hydro facilities claimed that some small power production QFs between 5 and 20 MW were more similar to cogeneration QFs than small power production QFs in that their primary purpose was not the sale of electricity. In response, the Commission included the fourth factor: 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).^[672]

370. As the Commission explained in the final rule (and reiterated above), this is not intended to be an exhaustive list but is intended to provide a framework for the Commission to evaluate small power producer QFs between 5 and 20 MW who wish to rebut the presumption of nondiscriminatory access.^[673] Any small power producer QF may use these factors (or other evidence) to rebut the presumption that a specific QF between 5 MW and 20 MW has non-discriminatory access to markets, and the Commission will review each request on a case-by-case basis.

371. One Energy argues that a behind-the-meter DER's primary purpose is to generate electricity for its host and any potential sale is secondary like cogeneration facilities. While not ruling on the validity of this argument with respect to any behind-the-meter DER, we clarify that small power production QFs that are behind-the-meter DERs are permitted to argue that the fourth factor which states “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-power dams)” supports their argument that they lack nondiscriminatory access to markets.^[674] We will rule on any such arguments on a case-by-case basis taking into account the specific facts of the DER making the argument.

372. We grant Public Interest Organizations request for clarification that the list of factors in section 18 CFR 292.309(c) 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 was not—but should be—added to 18 CFR 292.309(e) that applies to QFs in ISO-NE, MISO, NYISO, and PJM, and also to 18 CFR 292.309(f) that applies to QFs in ERCOT. In order to avoid confusion, we hereby incorporate the factors listed in 18 CFR 292.309(c) into both (e) and (f).

373. In response to One Energy's request for clarification as to how the new same site determination rules will affect the PURPA section 210(m) presumption, in determining whether a QF is eligible for the rebuttable presumption that a qualifying small power production facility with a capacity at or below 5 MW does not have nondiscriminatory access to the market, the Commission will look primarily at the net certified capacity of each QF. We note that the regulations state that, for the purposes of implementing the rebuttable presumption of nondiscriminatory access, the Commission will not be bound by the standards (i.e., the new ten-mile rule) of section 292.204(a)(2). The Commission will review, on a case-by-case basis, any question that involves applying both 18 CFR 292.309 and 292.204 to the same entity. We further note that, while we will look primarily at the net certified capacity of each QF, we may consider, inter alia, the new “ten-mile rule.”

G. Legally Enforceable Obligation

374. In the final rule, the Commission adopted 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.^[675] The Commission affirmed that the states have flexibility in determining what constitutes an acceptable showing of commercial viability and financial commitment, albeit subject to the criteria being objective and reasonable. The Commission found that requiring a showing of commercial viability and financial commitment, based on objective and reasonable criteria, would 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 Commission found, the criteria also ensure that the purchasing utility does not unilaterally and unreasonably decide when its obligation arises. The Commission believed that this struck the right balance for QF developers and purchasing utilities and should encourage development of QFs.^[676]

375. The Commission explained that 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 Commission found that 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. The Commission also clarified 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. Moreover, the Commission noted that the factors that the state requires must be factors that are within the control of the QF.^[677]

376. The Commission clarified that demonstrating the required financial commitment does not require a demonstration of having obtained financing. The Commission explained that 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 to the QFs' development and allows utilities to reasonably rely on the LEO in planning for system resource adequacy.^[678]

377. The Commission explained that 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.^[679] The Commission further explained that 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.^[680] The Commission explained that, in adopting this provision, the Commission was raising the bar to prevent speculative QFs from obtaining LEOs, with an associated burden on purchasing utilities, but was not establishing a barrier for financially committed developers seeking to develop commercially viable QFs.

378. The Commission disagreed that establishing reasonable, transparent factors is an onerous barrier or will cause a substantial reduction in QFs. The Commission found that the objective and reasonable criteria it had established would protect QFs against onerous requirements for LEOs that hinder financing, such as a requirement for a utility's execution of an interconnection agreement ^[681] or power purchase agreement,^[682] requiring that QFs file a formal complaint with the state commission,^[683] limiting LEOs to only those QFs capable of supplying firm power,^[684] or requiring the QF to be able to deliver power in 90 days.^[685] The Commission found that, by making clear that such conditions are not permitted, and by instead providing objective criteria to clarify when a LEO commences, the LEO provisions it adopted would encourage the development of QFs.

379. The Commission, however, declined to establish specific factors for the states to adopt, to establish a baseline for eligible factors, or to otherwise limit states' flexibility. The Commission found that states are in the best position to determine, in the first instance, what specific factors would best suit the specific circumstances of each state so long as they are objective and reasonable and provided the suggested prerequisites above as examples of objective and reasonable factors.^[686]

380. The Commission explained 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.^[687] The Commission stated that it had 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.^[688] The Commission stated that, 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 develop the QF that are within the QF's control to complete, and not on those factors that a utility controls. The Commission explained, for example, that requiring a QF to make a deposit 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.^[689]

1. Requests for Rehearing

381. Public Interest Organizations argue that the final rule's provision allowing states to require a showing of commercial viability and financially commitment results in additional barriers to QFs without sufficient safeguards to protect QFs from states' abuses. Public Interest Organizations contend that the Commission erred in failing to justify how these factors are consistent with PURPA's purpose of encouraging QFs. Public Interest Organizations assert that the Commission ignored the evidence that utilities adopt requirements to avoid their mandatory purchase obligation and states often acquiesce. Public Interest Organizations contend that the requirement that the factors be reasonable and objective are insufficient to protect QFs in seeking to establish a LEO and reiterate their request that the Commission establish specific limits on the kind of showing that is required before a LEO is established.^[690]

382. Public Interest Organizations argue that the Commission has repeatedly issued declaratory orders showing the unlawfulness of several LEO restrictions adopted by states but has repeatedly declined to initiate enforcement actions. They add that state regulators and courts have dismissed the Commission's declaratory orders as advisory and states have supported utilities' efforts to restrict LEOs. Public Interest Organizations assert that the Commission erred in considering the potential benefits to the utility's planning process of imposing new burdens on QFs. Instead, they contend that Congress directed the Commission to develop rules that would encourage QFs, not impose new burdens on QFs to benefit a utility's planning process.^[691]

383. Mr. Mattson argues that requiring financing as a factor to obtain a LEO is problematic because a LEO is needed to obtain financing.^[692]

2. Commission Determination

384. We disagree with the arguments raised on rehearing. The Commission created the LEO concept in Order No. 69 and has the authority to refine its contours in a way that continues to encourage QF development. The final rule achieves that result. Therefore, we reaffirm the Commission's finding in the final rule that requiring a showing of commercial viability and financial commitment based on objective and reasonable criteria encourages the development of QFs.^[693] It also strikes an appropriate balance between the needs of the QFs and the needs of the purchasing utilities.

385. That the revisions to the LEO eligibility requirements encourage the development of QFs is clear. In the past, purchasing utilities impeded the development of QFs by unilaterally erecting barriers to QFs establishing an obligation, such as by requiring a QF to have entered into an interconnection agreement or a power purchase agreement with the purchasing utility. It would then be up to the purchasing utility to decide whether and when to enter into such an agreement. The Commission changed that dynamic in the final rule by adopting regulations formalizing Commission precedent that takes away from the purchasing utility the unilateral ability to determine when the purchasing utility's obligation arises. Under the final rule, state-established objective and reasonable criteria would clarify when an obligation arises, rather than leave it to the purchasing utility.^[694] What is more, the criteria should be such that the ability to meet the criteria is in the hands of the QF and not in the hands of the purchasing utility. For example, it is the QF, and not the purchasing utility, that decides when it will apply for necessary permits or when it will apply for an interconnection agreement.^[695] Therefore, providing guidelines for establishing reasonable and objective criteria will prevent purchasing utilities from unilaterally and unreasonably deciding when its obligation to purchase arises and provides guidance to QFs seeking to establish a LEO. Moreover, to meet the needs of the purchasing utility, requiring a showing of commercial viability and financial commitment 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.

386. The criteria the Commission provided under the final rule are different from the prerequisites that the Commission in the past has found inconsistent with PURPA or that courts have permitted despite such Commission precedent.^[696] Objective and reasonable criteria for demonstrating commercial viability and financial commitment to proceed give a better sense to a state and a purchasing utility that a QF is more likely to be built. In comparison, requiring that a utility execute an interconnection agreement ^[697] or power purchase agreement,^[698] a QF file a formal complaint with the state commission,^[699] a QF be capable of supplying firm power,^[700] or a QF be able to deliver power in 90 days ^[701] are likely beyond the control of a QF or procedural requirements that do not reveal the likelihood that a QF will be developed and are therefore inappropriate obstacles to QF development.

387. Allowing states to require a showing of commercial viability and financial commitment from QFs will enable utilities and states to know which QFs are more likely to be built, thus enabling them to better plan their systems and accommodate all sources of QF power, and are just and reasonable to the consumers of the electric utility. States are not required to adopt specific criteria, but, as with other PURPA Regulations, the Commission has established the boundaries within which each state can adopt appropriate criteria that address each states' unique characteristics. As explained in the final rule, providing guidance as to how QFs can establish commercial viability and a financial commitment will provide certainty that QF developers can rely upon, thereby encouraging QF development.^[702] We believe that providing clear, objective, and reasonable guidelines for establishing a LEO will also reduce disputes between state commissions, utilities, and QF developers.

388. Finally, the final rule explicitly provided that “obtaining a PPA or financing cannot be required to show proof of financial commitment.” ^[703]

III. Information Collection Statement

389. The Paperwork Reduction Act ^[704] 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 contained in rulemakings (including deletion, revision, or implementation of new requirements).^[705] Upon approval of a collection of information, OMB will assign an OMB control number and an expiration date. Respondents subject to the information collection 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.

390. With respect to the Form No. 556 information collection (Certification of Qualifying Facility (QF) Status for a Small Power Production or Cogeneration Facility, OMB Control No. 1902-0075), in the final rule, the Commission affirmed 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. The Commission stated that it was making the following changes to the Form No. 556 which affect the burden of the information collection:

• 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 the 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 the 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 the 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 the final rule.

The Commission stated that these changes in burden are appropriate because they are necessary to meet the statutory requirements contained in PURPA.

391. The Commission included the following table (shown below) which provided estimated changes to the burden and cost of the Form No. 556 due to the final rule.^[706] (The estimates have not changed from the final rule.)

FERC-556, Changes Due to Final Rule in Docket Nos. RM19-15-000 and AD16-16-000 ⁷⁰⁷

Facility type	Filing type	Number of respondents	Annual number of responses per respondent	Total number of responses	Increased average burden hours & cost per response ($)	Increased total annual burden hours & total annual cost ($)	Increased annual cost per respondent ($)
		(1)	(2)	(1) * (2) = (3)	(4)	(3) * (4) = (5)	(5) ÷ (1) = (6)
Cogeneration and Small Power Production Facility ≤1 MW 708	Self-certification	no change (692)	no change (1.25)	no change (865)	no change (1.5 hrs.); $0	no change (1,297.5 hrs.); $0	$0
Cogeneration Facility >1 MW	Self-certification	no change (63)	no change (1.25)	no change (78.75)	no change (1.5 hrs.); $0	no change (118.125 hrs.); $0	0
Cogeneration Facility >1 MW	Application for FERC certification	no change (1)	no change (1.25)	no change (1.25)	no change (50 hrs.); $0	no change (62.5 hrs.); $0	0
Small Power Production Facility >1 MW, ≤1 Mile from Affiliated Small Power Production QF	Self-certification	no change (899) 709	no change (1.25)	no change (1,123.75)	2 hrs.; $166	2,247.5 hrs.; $186,542.5	207.5
Small Power Production Facility >1 MW, ≤1 Mile from Affiliated Small Power Production QF	Application for FERC certification	no change (0)	no change (1.25)	no change (0)	6 hrs.; $498	no change (0 hrs.); $0	0
Small Power Production Facility >1 MW, >1 Mile, <10 Miles from Affiliated Small Power Production QF	Self-certification	no change (900)	no change (1.25)	no change (1,125)	8 hrs.; $664	9,000 hrs.; $747,000	830
Small Power Production Facility >1 MW, >1 Mile, <10 Miles from Affiliated Small Power Production QF	Application for FERC certification	no change (0)	no change (1.25)	no change (0)	12 hrs.; $996	no change (0 hrs.); $0	0
Small Power Production Facility >1 MW, ≥10 Miles from Affiliated Small Power Production QF	Self-certification	no change (899)	no change (1.25)	no change (1,123.75)	2 hrs.; $166	2,247.5 hrs.; $186,542.5	207.5
Small Power Production Facility >1 MW, ≥10 Miles from Affiliated Small Power Production QF	Application for FERC certification	no change (0)	no change (1.25)	no change (0)	6 hrs.; $498	no change (0 hrs.); $0	0
FERC-556, Total Additional Burden and Cost Due to Final Rule		no change (3,454)		no change (4,317.5)		13,495 hrs.; $1,120,085

A. Request for Rehearing

392. Public Interest Organizations state that Solar Energy Industries questioned the Commission's burden estimate in the NOPR, anticipating that the actual burden will be far higher.^[710] Public Interest Organizations assert that the Commission dismissed Solar Energy Industries' estimates that the new rule would require an additional 90 to 120 hours per year to comply ^[711] without providing additional justification or explanation for the Commission's time and expense estimates, which is arbitrary and capricious.^[712]

B. Commission Determination

393. The Commission in the final rule directly addressed Solar Energy Industries comments and explained why it did not agree with Solar Energy Industries' estimates.^[713] Additionally, we note that while other commenters agreed that the NOPR's proposals would result in increased administrative burden and expense,^[714] Solar Energy Industries was the only commenter to provide a numerical estimate to challenge the Commission's proposed estimates. The Commission nevertheless increased its burden estimates in the final rule in response to the comments received.^[715] We also note that Solar Energy Industries did not independently support its estimate of increased burden of 90 to 120 hours. Rather, Solar Energy Industries relied on a separate rulemaking proceeding for a different regulatory program administered by the Commission,^[716] and stated, without justification, that it believed the estimates for an ultimately withdrawn portion of that rulemaking (the proposed Connected Entity Information requirement) are a reasonable approximation of the burden that QFs would face in complying with the new requirements in the final rule.^[717] While both rulemakings require the disclosure of affiliate information, the withdrawn Connected Entity Information proposal would have also required reporting of certain employee information.^[718] Furthermore, the final rule limits the information geographically to require the listing of only those affiliated entities that are less than 10 miles away, whereas the withdrawn Connected Entity Information requirement from the other proceeding would not have limited its information collection geographically.

394. Moreover, we believe that Solar Energy Industries' estimate vastly overstates the regulatory burden. First, the Commission explained in the final rule that 18 CFR 292.207(d) (which the Commission did not alter in the final 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,^[719] and hence it is long-standing practice that a QF must recertify when material facts or representations in the Form No. 556 change.

395. Second, with regard to the new Form No. 556 requirement to identify all affiliated small power production QFs using the same energy resource that are less than 10 miles from the electrical generating equipment of the certifying facility, we note that the final rule expanded the requirement to identify such facilities to less than 10 miles away, but the requirement to identify such facilities less than one mile already existed.

396. Third, we note that not all QFs will be affected by this expanded requirement. Only small power production QFs that have an affiliated small power production QF more than one but less than 10 miles away that uses the same energy resource will be subject to the new requirement to list the affiliated small power production QF. QFs that have no affiliated small power production QFs will not be affected, nor will those whose only affiliates are more than 10 miles away. Moreover, those QFs that have only a few affiliated small power production QFs more than one but less than 10 miles away will only suffer a small increase in burden to list these affiliated facilities. The only facilities that may suffer a more significant burden—from the new requirement to identify affiliated facilities that use the same energy resource more than one and less than 10 miles away—are facilities with multiple facilities close together, and it is precisely this group of facilities from whom the Commission needs this information, in order to determine whether those facilities should be considered to be at the same site.

397. However, in light of Public Interest Organizations' and Solar Energy Industries' renewed assertion that the regulatory burden on QFs is substantial,^[720] we modify and clarify our requirements regarding the identification of affiliated small power production QFs, in order to further ensure that the regulatory burden on small power production facilities is within reasonable limits as described in section III.D. Specifically, as explained more fully in section III.D above, we modify the final rule to state that a small power production QF evaluating whether it needs to recertify does not need to recertify due to a change in the information it has previously reported regarding its affiliated small power production QFs that are more than one mile but less than 10 miles from its electrical generating equipment, including adding or removing an affiliated small power production QF more than one mile but less than 10 miles away, or if an affiliated small power production QF more than one mile but less than 10 miles away and previously reported in item 8a makes a modification, unless that change also impacts any other entries on the evaluating small power production QF's Form No. 556.

398. We will continue to require that a small power production QF, as it was prior to the final rule, recertify its Form No. 556 to update item 8a due to a change at any of its affiliated small power production facilities located one mile or less from of its electrical generating equipment.^[721] We will also still require that a small power production QF recertify due to a change in material fact or representation to its own facility.

399. At such time as the small power production QF makes a recertification due to a change in material fact or representation to its own facility or at any of its affiliated small power production facilities that use the same energy resource and are located one mile or less from its electrical generating equipment, we will require that the small power production QF update item 8a for all of its affiliated small power production QFs within 10 miles, including adding or deleting affiliated small power production QFs, and recording changes to previously listed small power production QFs, so that the information in its Form No. 556 is complete, accurate, and up-to-date.^[722]

400. We believe that this modification reduces the burden on small power production QFs because we will not require them to monitor continually their affiliated small power production QFs more than one mile but less than 10 miles away for changes nor will we require a small power production QF that is evaluating whether it must recertify its facility to recertify to update item 8a due to a change at its affiliated small power production facilities more than one mile but less than 10 miles from the evaluating facility's electrical generating equipment.^[723] However, the affiliated QF of that evaluating small power production QF will need to recertify if the affiliated QF makes a material change to its information in its Form No. 556. After reviewing the rehearing requests, and implementing the modification described above, we conclude that this requirement strikes an appropriate balance between the need to address improper circumvention and the need to avoid unduly burdening small power production QFs. With the modification described above, we find that our burden estimates, as reported in the final rule, continue to be reasonable, especially now that we have lessened the burden as compared to the final rule by making this change on rehearing. We do not believe that the change we have made today to the Form No. 556 to implement the above modification adds any additional burden to the information collection. We also note that, in retaining the pre-final rule requirement that a small power production recertify information on affiliate small power production facilities one mile or less away,^[724] we are not adding any additional burden.

401. Though Public Interest Organizations and Solar Energy Industries questioned the Commission's estimates, the Commission provided ample justification for why the burden and cost estimates would increase as a result of the final rule. In the final rule, the Commission estimated that the annual burden hours and costs for the information collection for the Form No. 556 would increase as a result of the changes to the “one-mile rule” in the final rule.^[725] The Commission explained that it was implementing new requirements for applicants to report the QF's geographic coordinates, list affiliated small power production QFs using the same energy resource one mile or less from the applicant facility, 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, and list the geographic coordinates of the nearest “electrical generating equipment” of both its own facility and the affiliated small power production QF in question.^[726] The Commission also suggested that if applicants anticipate a protest to their certifications, they could provide explanations as to 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 at separate sites from the applicant's facility.^[727]

402. Additionally, the Commission noted that, as a result of the changes to the PURPA Regulations made in the final rule, small power production QFs will have to spend more time identifying 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 further expected that there will be an increase in the burden hours and cost due to the new ability of entities to protest without a fee, which will affect initial self-certifications, applications for Commission certification, or recertifications that make substantive changes to an existing certification after the effective date of the final rule.^[728]

1. QFs Submitting Self-Certifications

403. Prior to the final rule, the estimated burden for a small power production facility greater than 1 MW filing a self-certification was 1.5 hours.^[729]

a. Small Power Production Facility Greater Than 1 MW, and Less Than One Mile From an Affiliated Small Power Production QF

404. In the final rule, given the implementation of the new 10-mile rule, the Commission estimated that it would take a small power production facility greater than 1 MW, and less than one mile from an affiliated facility, two hours in addition to the prior estimated 1.5 hours to fill out the new version of the Form No. 556 for a self-certification.^[730] In making this estimate of two additional hours, the Commission took into consideration that the applicant would now be required to additionally provide its geographic coordinates.^[731] While it would also be required to identify and provide the geographic coordinates for any small power production QFs located less than 10 miles from the applicant facility, the current Form No. 556 already required identifying any facilities located within one mile of the applicant facility. The Commission reasoned that the applicant may need to take some additional time to ascertain that there were no additional facilities located more than one mile from the applicant facility. The Commission therefore reasoned that, for this category, it may take an applicant facility an additional two hours to complete the Form No. 556.^[732]

b. Small Power Production Facility Greater Than 1 MW, and More Than One Mile but Less Than 10 Miles From an Affiliated Small Power Production QF

405. In the final rule, given the implementation of the new 10-mile rule, the Commission estimated that it would take a small power production facility greater than 1 MW, and more than one mile but less than 10 miles from an affiliated facility, eight hours in addition to the prior estimated 1.5 hours to fill out the new version of the Form No. 556 for a self-certification.^[733] In making this estimate of eight additional hours, the Commission took into consideration that the applicant would now be required to additionally provide its geographic coordinates and to identify and provide the geographic coordinates for any small power production QFs located less than 10 miles from the applicant facility. If the applicant chose, it could provide explanations as to 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.^[734] The Commission therefore reasoned that, for this category, it may take an applicant facility an additional eight hours to complete the Form No. 556.^[735]

c. Small Power Production Facility Greater Than 1 MW and 10 Miles or More From an Affiliated Small Power Production QF

406. In the final rule, given the implementation of the new 10-mile rule, the Commission estimated that it would take a small power production facility greater than 1 MW and 10 miles or more from an affiliated facility two hours in addition to the prior estimated 1.5 hours to fill out the new version of the Form No. 556 for a self-certification.^[736] In making this estimate of two additional hours, the Commission took into consideration that the applicant would now be required to additionally provide its geographic coordinates but would not be required to identify and provide the geographic coordinates for any small power production QFs located more than 10 miles from the applicant facility. The Commission reasoned that the applicant may need to take some additional time to ascertain that there were no additional facilities located less than 10 miles from the applicant facility. The Commission therefore reasoned that, for this category, it may take an applicant facility an additional two hours to complete the Form No. 556.^[737]

2. QFs Submitting Applications for Commission Certification

407. Prior to the final rule, the estimated burden for a small power production facility greater than 1 MW filing an application for Commission certification was 50 hours.^[738]

a. Small Power Production Facility Greater Than 1 MW, and Less Than One Mile From an Affiliated Small Power Production QF

408. In the final rule, given the implementation of the new 10-mile rule, the Commission estimated that it would take a small power production facility greater than 1 MW, and less than one mile from an affiliated facility, six hours in addition to the prior estimated 50 hours to fill out the new version of the Form No. 556 as part of an application for Commission certification.^[739] In making this estimate of six additional hours, the Commission took into consideration that the applicant would now be required to additionally provide its geographic coordinates. Also, while the applicant would also be required to identify and provide the geographic coordinates for any small power production QFs located less than 10 miles from the applicant facility, the current Form No. 556 already required identifying any facilities located within one mile of the applicant facility. The Commission reasoned that the applicant may need to take some additional time to ascertain that there were no additional facilities located more than one mile from the applicant facility. Unlike a self-certification, the application for Commission certification also requires the applicant to pay a filing fee, and applicants for a Commission certification generally provide more explanation and a narrative filing. The Commission therefore reasoned that, for this category, it may take an applicant facility an additional six hours to complete the Form No. 556.^[740]

b. Small Power Production Facility Greater Than 1 MW, and More Than One Mile but Less Than 10 Miles From an Affiliated Small Power Production QF

409. In the final rule, given the implementation of the new 10-mile rule, the Commission estimated that it would take a small power production facility greater than 1 MW, and more than one mile but less than 10 miles from an affiliated facility, 12 hours in addition to the prior estimated 50 hours to fill out the new version of the Form No. 556 for an application for Commission certification.^[741] In making this estimate of 12 additional hours, the Commission took into consideration that the applicant would now be required to additionally provide its geographic coordinates and to identify and provide the geographic coordinates for any small power production QFs located less than 10 miles from the applicant facility. If the applicant chose, it could also provide explanations as to 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.^[742] Unlike a self-certification, the application for Commission certification also requires the applicant to pay a filing fee, and applicants for a Commission certification generally provide more explanation and a narrative filing. Therefore, the Commission reasoned that, for this category, it may take an applicant facility an additional 12 hours to complete the Form No. 556.^[743]

c. Small Power Production Facility Greater Than 1 MW and 10 Miles or More From an Affiliated Small Power Production QF

410. In the final rule, given the implementation of the new 10-mile rule, the Commission estimated that it would take a small power production facility greater than 1 MW and 10 miles or more from an affiliated facility six hours in addition to the prior estimated 50 hours to fill out the new version of the Form No. 556 for an application for Commission certification.^[744] In making this estimate of six additional hours, the Commission took into consideration that the applicant would now be required to additionally provide its geographic coordinates, but the applicant would not be required to identify and provide the geographic coordinates for any small power production QFs located more than 10 miles from the applicant facility. The Commission reasoned that the applicant may need to take some additional time to ascertain that there were no additional facilities located less than 10 miles from the applicant facility. Unlike a self-certification, the application for Commission certification also requires the applicant to pay a filing fee, and applicants for a Commission certification generally provide more explanation and a narrative filing. The Commission reasoned that, for this category, it may take an applicant facility an additional six hours to complete the Form No. 556.^[745]

3. Calculations for Additional Burden and Cost

411. Lastly, the Commission explained that it believed that the industry is similarly situated in terms of wages and benefits. Therefore, estimates for the annual cost of additional burden are based on FERC's 2020 average hourly wage (and benefits) of $83.00 per hour.^[746] In order to determine the cost per response in the column titled “Increased Average Burden Hours & Cost Per Response ($) (4),” the Commission multiplied the number of additional burden hours by the average hourly wage of $83.00 per hour. For example, for small power production facilities greater than 1 MW located less than one mile from affiliated small power production QFs, the Commission determined that the increased average burden hours as a result of the final rule was two hours. The two-hour increase in the average burden hours, multiplied by an average hourly wage of $83.00 per hour, equals $166 cost per response.^[747] In order to determine the increased total annual burden hours and total annual cost in the column titled “Increased Total Annual Burden Hours & Total Annual Cost ($) (3) * (4) = (5),” the Commission multiplied the numbers in the column titled “Total Number of Responses (1) * (2) = (3)” by the numbers in the column titled “Increased Average Burden Hours & Cost Per Response ($) (4).” For example, for small power production facilities greater than 1 MW located less than one mile from affiliated small power production QFs, the Commission multiplied the increased average burden hours of two hours by the total number of responses of 1,123.75 for increased total annual burden hours of 2,247.5 hours. The Commission then multiplied the increased cost per response of $166 by the total number of responses of 1,123.75 for an increased total annual cost of $186,542.50.^[748]

IV. Environmental Analysis

A. No EIS or EA Is Required

412. In the final rule, the Commission noted that NEPA requires federal agencies to prepare a detailed statement on the environmental impact for “major Federal actions significantly affecting the quality of the human environment.” ^[749] 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) for a proposed action significantly affecting the quality of the human environment; ^[750] or (b) an Environmental Assessment (EA) to determine whether an EIS is required.^[751] The CEQ regulations also provide that agencies are not obligated to prepare either an EIS or an EA if they find that a categorical exclusion applies.^[752]

413. The Commission found that no EA or EIS was required for the final rule because the rule does not involve a particular project that “define[s] fairly precisely the scope and limits of the proposed development” and any potential environmental impacts from the final rule are not reasonably foreseeable.^[753] In response to comments on the NOPR that although an EA and later an EIS was prepared for the 1980 initial rules implementing PURPA (Order No. 70), the Commission explained, based on a number of factual differences between the initial rules and the final rule, that a meaningful NEPA analysis could not be prepared for the final rule.^[754] The Commission also found that, as a separate and independent alternative ground, that a categorical exclusion applied to the final rule so that an EA or EIS need not be prepared.^[755]

1. NEPA Analysis Is Not Required Where Environmental Impacts Are Not Reasonably Foreseeable

414. The Commission explained that 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.^[756] The Commission also explained that, while courts have held that NEPA requires “reasonable forecasting,” “NEPA does not require a `crystal ball' inquiry.” <sup>[757]</sup> The Commission added that 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” <sup>[758]</sup> or to “foresee the unforeseeable.” <sup>[759]</sup> and “[i]n determining what effects are `reasonably foreseeable,' an agency must engage in `reasonable forecasting and speculation,' . . . with reasonable being the operative word.” ^[760] The Commission explained that environmental impacts are not reasonably foreseeable if the impacts would result only through a lengthy causal chain of highly uncertain or unknowable events.^[761]

415. The Commission found that 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 unduly speculative, based on the difficulty in determining which, if any, of the additional flexibilities the final rule provides to the states will be adopted by each state, how state rules would impact QF development going forward and whether any reduction in QF renewables would be replaced by an increased amount of non-QF renewable resources with similar environmental characteristics.^[762]

416. The Commission pointed to Center for Biological Diversity v. Ilano,^[763] in which the court held that no NEPA review was required for United States Forest Service designations, pursuant to the Healthy Forests Restoration Act (HFRA), of certain forests as “landscape-scale areas.” The Commission explained that 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 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.' ” <sup>[764]</sup> The Commission further explained that the court concluded that “unless there is a particular project that `define[s] fairly 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.' ” ^[765]

417. The Commission found that 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) and neither the Commission's regulation nor the final rule authorize or prohibit the use of any particular technology or fuel, or mandate or prohibit where QFs should be or are built.^[766]

418. The Commission found that the final rule continues to give states wide discretion and that it is impossible to know what the states may choose to do in response to the 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 in any particular locale.^[767]

419. The Commission found that the scope of the final rule is even less defined than the landscape-scale area designations at issue in Center for Biological Diversity v. Ilano, explaining that 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.^[768] The Commission reasoned that, as was the case in Center for Biological Diversity v. Ilano, any attempt to evaluate the environmental effects of the final rule by necessity would involve hypothesizing the potential development of QFs and the resultant environmental consequences.^[769] The Commission found that 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. The Commission found that it was 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 (such as a fossil-fuel-burning cogenerator or a waste-coal-burning small power production facility). The Commission further found that environmental effects on land use, vegetation, water quality, etc. are all dependent on location, which is unknown and could be anywhere in the United States.^[770] The Commission therefore concluded that any the potential effects of the final rule on future QF development are so speculative as to render meaningless any environmental analysis of these impacts.^[771]

a. Requests for Rehearing

420. Northwest Coalition and Public Interest Organizations allege that the Commission erred in determining that there is no need to prepare an EA or EIS.^[772] With respect to the discussion in the final rule of why potential environmental impacts are too speculative, Northwest Coalition asserts, with no explanation, that the Commission provided “out-of-context quotations from a number of cases.” ^[773] Northwest Coalition and Public Interest Organizations argue that the impacts are not too speculative or uncertain for a NEPA analysis because the Commission used the wrong standard to determine impact, asserting that the “question is whether the proposed rules may have a significant impact on the human environment,” not whether it will have an impact.^[774] They claim that, because states were prohibited from lawfully denying fixed-price contracts to QFs under previous rules, the Commission must assume that under the new rules the states will eliminate the right to fixed-price contracts and that the development of new QFs will halt, which is the type of analysis that must be done in a NEPA document.^[775] Northwest Coalition claims that the final rule does not appear to seriously dispute that the new rules may have a significant effect; instead, it appears to merely conclude the precise impact would be too difficult to pinpoint.

421. Public Interest Organizations similarly argue that the Commission cannot avoid NEPA review by making unsupported claims that environmental impacts are unforeseeable, prior to any NEPA analysis, as the role of NEPA itself is to “indicate the extent to which environmental effects are uncertain or unknown.” ^[776] Public Interest Organizations assert that the Commission mistakenly found that any environmental analysis of the final rule would be speculative and would not meaningfully inform the Commission or the public.^[777] Public Interest Organizations add that NEPA requires agencies to examine all foreseeable impacts, including cumulative and indirect impacts, when undertaking rule changes that grant states new regulatory authority, which “plainly includes changes to allow new ways and options for states when exercising their authority.” ^[778] Public Interest Organizations contend that NEPA may apply when the agency makes a decision that permits actions by other parties that will have an impact on the environment.^[779] Northwest Coalition adds that courts have required a NEPA analysis in cases where the agency proposes rules that will have an impact on future development, even for widespread regulatory changes that do not themselves authorize any discrete project.^[780]

422. Public Interest Organizations assert that a NEPA analysis is required when uncertainty may be resolved by collecting further data or the collection of such data may prevent speculation on potential environmental effects.^[781] Public Interest Organizations add that the Commission's position that collecting data and analyzing it would be too difficult is an impermissible basis for foregoing an EA or EIS.^[782] Public Interest Organizations contend that, when an agency is faced with incomplete or unavailable information, the CEQ regulations require an EIS to include a summary of existing credible scientific evidence that is relevant to evaluating the reasonably foreseeable impacts of a proposed action.^[783]

423. Northwest Coalition and Public Interest Organizations argue the Commission is required to prepare an EIS because courts have found an EIS is required where “substantial questions” have been raised as to whether an agency action “may cause significant degradation of some human environmental factor,” adding that parties are not required to show that significant effects will occur, but only raise substantial questions that they may occur.^[784]

424. Northwest Coalition and Public Interest Organizations allege that the Commission improperly relied on Center for Biological Diversity v. Ilano to determine that the rulemaking's impacts were too speculative for NEPA analysis.^[785] Public Interest Organizations assert that the court found that the action would not change the “status quo,” in contrast to here, where they claim the final rule legally alters the status quo.^[786] Public Interest Organizations claim that “significantly” reduced QF development is foreseeable based on experience in states that have undermined the prior rules, regardless of the fact that the proposed changes do not mandate or prohibit the construction of any specific QF's, and the environmental impacts of removing major incentives for emissions-free renewable resources will be significant and far-reaching.^[787] Northwest Coalition asserts that the Center for Biological Diversity v. Ilano court “relied on its finding that the designation did not authorize any discrete projects and would only potentially lead to such projects, making the exercise of an EIS too speculative.” ^[788] Northwest Coalition claims that this reasoning does not apply to the final rule because the Commission has demonstrated it has the capability to conduct detailed market analysis on the impact of its proposed rules and their likely environmental impacts.^[789]

b. Commission Determination

425. As an initial matter, Northwest Coalition errs in suggesting that the Commission does not dispute that the final rule may have significant impacts on the environment and that the precise impact would be too difficult to pinpoint. Rather, the Commission found that any consideration of whether the final rule could potentially have significant environmental impacts would be so speculative as to render meaningless any environmental analysis of these hypothetical impacts.^[790]

426. Moreover, the Commission did not reach this conclusion based on an inability to “pinpoint” precise impacts. Rather the Commission made this determination based on, among other things, the inability to provide any reasonable forecast of the effects of the final rule on the environment. This is the case not only because it is not possible to predict how the states will exercise the increased flexibilities provided by the final rule and whether the effects, if any, of such state actions will encourage or discourage renewable resources as opposed to fossil-fueled resources, but also because any environmental effects on resources such as land use, vegetation, and water quality are all dependent on location, which is unknown at this time and could be anywhere in the United States.^[791]

427. We also reject Northwest Coalition's argument that in making an impact determination, the Commission erroneously considered whether the final rule “will,” rather than “may,” have a significant impact on the environment. In explaining why no EA or EIS was required, the Commission stated that any consideration of whether the final rule 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.^[792]

428. Public Interest Organizations' reliance on Mid States Coal. for Progress v. Surface Transp. Bd^[793] to support its claim that NEPA applies when an agency makes decisions which permit actions by other parties that will impact the environment is misplaced. In that case, parties challenged the permitting of a railroad extension that would transport coal to the Midwest, resulting in an increased availability of coal at reduced rates. The court found that the EIS prepared for the railroad extension had failed to address the indirect impacts of air emissions resulting from the consumption of this coal when it was used to generate electricity, even though the railroad had not yet signed any contracts to haul this coal. The court noted that “if the nature of the effect is reasonably foreseeable but its extent is not . . . the agency may not simply ignore the effects.” ^[794] In contrast to this proceeding, in Mid States Coal. for Progress v. Surface Transp. Bd, it was undisputed that the proposed rail line would increase the use of coal for power generation; the Surface Transportation Board itself had concluded that its action would lead to increased mining and air emissions but then failed to address those impacts in the EIS. Here, the Commission did not conclude that the final rule would have identifiable environmental impacts; on the contrary, it explained in detail why any potential impacts from the final rule are not reasonably foreseeable.

429. Public Interest Organizations' reliance on Scientists' Institute for Public Information, Inc., v. AEC ^[795] is equally misplaced. There, the D.C. Circuit faulted the Atomic Energy Commission (AEC) for failing to prepare a NEPA analysis for its proposed liquid metal fast breeder reactor program. The D.C. Circuit noted that AEC had prepared a complex cost/benefit analysis in attempting to justify the proposed program but failed to include a consideration of the environmental costs and benefits associated with the proposed program. The court was persuaded that a NEPA analysis should have been prepared because AEC had existing detailed estimates on the amount of waste and the amount of land area necessary for storage of the waste, as well as “much information on alternatives to the program and their environmental effects.” ^[796] In contrast here, for the reasons discussed in the final rule and herein, the Commission has no existing detailed or quantifiable information, nor is such information attainable, with respect to future actions that might or might not occur as a result of the final rule that would assist us in a meaningful analysis.^[797]

430. We also disagree with Public Interest Organizations' arguments that “substantial questions” have been raised with respect to potential significant environmental impacts such that the Commission must prepare an EA or EIS for the final rule.^[798] Courts have found that the applicable standard for determining whether substantial questions have been raised is whether the “alleged facts if true, show that the proposed project may significantly degrade some human environmental factor.” ^[799] Public Interest Organizations' arguments are based not on alleged facts, but on speculative assumptions which the Commission considered and addressed in the final rule.^[800] Public Interest Organizations' reliance on LaFlamme v. FERC ^[801] is without merit. There, the Commission approved the construction of a new hydroelectric project without benefit of an EA or an EIS. The court found that substantial questions had been raised regarding identifiable potential impacts from site specific activities.^[802] In contrast, the final rule does not authorize any site-specific activities for which there are identifiable potential impacts; as discussed above, the final rule does not authorize any specific projects.

431. Greenpeace Action v. Franklin ^[803] is similarly inapposite. There, the National Marine Fisheries Service prepared an EA for proposed fishery harvest specifications for pollock that concluded in a finding of no significant impacts on the Stellar sea lion, whose diet included a significant amount of pollock.^[804] The National Marine Fisheries Service determined that, while it was uncertain there would be adverse impacts on the Stellar sea lion, it would take precautions and impose management measures to provide an adequate buffer against any adverse impacts. The court rejected plaintiff's claim that the National Marine Fisheries Service should have prepared an EIS based on plaintiff's competing affidavits with respect to National Marine Fisheries Service's findings. While the court cited the general principle that an agency must prepare an EIS if substantial questions are raised as to environmental impacts, the court found that petitioner's affidavits did not set forth facts demonstrating there would be significant impacts on the Stellar sea lion; rather they only demonstrated “uncertainty as to how pollock fishing affects the sea lion, which is undisputed.” ^[805] The court declined to set aside the National Marine Fisheries Service's findings because there was no disagreement over whether the proposed action impact may have a significant impact on the environment but rather “represent[ed] a difference of scientific opinion” over the extent of potential impacts.^[806]

432. We also reject Northwest Coalition's claim that the Commission must consider the impacts of reasonably foreseeable future actions even if there is no specific proposal, asserting there are previous experiences on how states have allegedly reacted to prior PURPA Regulations. Specifically, Northwest Coalition argues the Commission must assume that under the new rules the states will eliminate the right to fixed-price contracts and, therefore, the development of new QFs will halt.^[807] Public Interest Organizations allege that the environmental impacts of removing major incentives for emissions-free renewable resources will be significant and far-reaching ^[808] Northwest Coalition's and Public Interest Organizations' arguments would require the Commission first to make highly speculative and hypothetical assumptions about future state action on QFs and that all QFs are renewables, as well as unrealistic and unsupported assumptions as to whether such actions would impact renewable QFs more than emitting QFs.

433. As discussed in the final rule, 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” or to “foresee the unforeseeable.” ^[809] Further, the Commission explained that 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 [the 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 alone any particular locale.” ^[810]

434. Public Interest Organizations cite National Parks & Conservation Ass'n v. Babbitt for the proposition that an EA or EIS is required “where uncertainty may be resolved by further collection of data.^[811] Here, attempting to collect further data or information would not resolve uncertainty; the Commission has explained that it is not possible to collect detailed or quantifiable information regarding future QF development.^[812] This contrasts with National Parks & Conservation Ass'n v. Babbitt, where the National Park Service issued an EA finding that a substantial increase in cruise ship traffic entering Glacier Bay National Park and Preserve would have no significant impact on the environment. In requiring the National Park Service to prepare an EIS, the court explained that scientific evidence provided by the National Park Service's own studies “revealed very definite environmental effects,” and the National Park Service's EA established that information was “obtainable and that it would be of substantial assistance” in considering the environmental impacts of the increased cruise ship traffic.^[813]

435. We also reject Northwest Coalition's and Public Interest Organizations' claims that the Commission improperly relied on Center for Biological Diversity v. Ilano, because, they assert, the final rule legally alters the “status quo.” The court in Center for Biological Diversity held that an EIS is not required where a proposed action does not change the status quo, and defined changes in the status quo as those “alter[ing] future land use or otherwise foreseeably impact[ing] the environment.” ^[814] The court further explained that “ `[l]ong-range aims are quite different from concrete plans,' and `NEPA does not require an agency to consider the environmental effects that speculative or hypothetical projects might have . . . .' ” ^[815] While the final rule results in changes to the implementation of the original PURPA Regulations, the final rule does not change the status quo as contemplated by NEPA. It does not direct or preclude the development of any project or otherwise require entities to take actions that foreseeably alter future land use or otherwise result in foreseeable environmental impacts. As discussed in the final rule, it is not possible 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.^[816] The final rule is premised on a finding that, even after the revisions, the PURPA Regulations will continue to encourage QF development while addressing concerns about how PURPA works in today's electric markets; therefore, there it cannot be presumed that the rule will result in a reduction in QF development or a change in the type of QFs that are built. The impact, if any, of the final rule on QF development is both uncertain or unknowable.^[817] As the court found in Center for Biological Diversity, such speculative environmental consequences are not required to be analyzed under NEPA.^[818] Thus, the Commission cannot analyze environmental impacts in this case, when such an analysis could only be done if multiple, unlikely, and unreasonable assumptions are made as to the variables above.^[819]

2. A Categorical Exclusion Applies

436. The Commission found as a separate and independent alternative basis for concluding that no environmental analysis is warranted that the final rule falls within the categorical exclusion for rules that, as relevant here: (1) Are clarifying in nature; (2) are corrective in nature; or (3) are procedural in nature.^[820]

437. The Commission explained that clarifying changes include those that clarify how market prices can be used to set as-available energy rates, the changes clarifying how fixed energy rates in contracts or LEOs may be determined, and the changes clarifying how competitive solicitations can be used to set avoided cost rates.^[821]

438. The Commission stated that corrective changes include those needed in order to ensure that a regulation conforms to the requirements of the statutory provisions being implemented by the regulation. The Commission noted that it does not find that its existing PURPA Regulations were inconsistent with the statutory requirements of PURPA when promulgated. The Commission found instead that the changes adopted in the 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 the final rule.^[822]

439. The Commission found that 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. The Commission explained 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 violate the statutory avoided cost rate cap. The Commission explained that 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.^[823]

440. 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.^[824] The Commission explained that it found, based on changed circumstances, that the current one-mile rule is inadequate to determine which facilities are located at the same site. The Commission determined that, based on this finding, the Commission was obligated by PURPA to revise its definition of when facilities are located at the same site.^[825]

441. The third corrective aspect relates to the implementation of PURPA section 210(m). The Commission explained that this 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.^[826] The Commission explained that the final rule updates 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.^[827]

442. The Commission explained 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.^[828] The Commission added that this determination rendered inaccurate the presumption currently reflected in the PURPA Regulations that QFs of 20 MW and below do not have non-discriminatory access to the relevant markets.^[829] The Commission explained that, 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).^[830]

a. Exception to Categorical Exclusion

i. Requests for Rehearing

443. Northwest Coalition and Public Interest Organizations assert that, as a threshold matter, the final rule does not qualify for a categorical exclusion because the Commission's regulations provide that, “[w]here circumstances indicate that an action may be a major Federal action significantly affecting the quality of the human environment,” the Commission will prepare either an EA or an EIS.^[831] They add that the Commission's regulations provide that an exception to a categorical exclusion may exist “[w]here the environmental effects are uncertain.” ^[832]

ii. Commission Determination

444. We disagree that the Commission's exceptions to categorical exclusions preclude the application of a categorical exclusion to the final rule. The CEQ regulations state that a categorical exclusion applies to an action that does not individually or cumulatively have a significant effect on the environment and an agency's categorical exclusion procedures should provide for limitations on the use of a categorical exclusion where “extraordinary circumstances” indicate that a normally excluded action may have a significant environmental effect.^[833] The Commission's regulations provide a list of these extraordinary circumstances, which are effects on Indian lands; Wilderness areas; Wild and Scenic rivers; Wetlands; Units of the National Park System, National Refuges, or National Fish Hatcheries; Anadromous fish or endangered species; or where environmental effects are uncertain.^[834] None of these extraordinary circumstances are present here except to the extent the environmental effects are uncertain. The final rule explained in detail why any potential environmental impacts are uncertain and unknown as they are too speculative to provide an EA or EIS that would meaningfully inform the Commission.^[835] In any case, the Commission's regulations state that the presence of one or more of the extraordinary circumstances “will not automatically require . . . the preparation of an environmental assessment or an environmental impact statement.” ^[836]

b. Applying a Categorical Exclusion for Clarifying and Corrective Actions Is Appropriate

i. Requests for Rehearing

445. Northwest Coalition and Public Interest Organizations also dispute that the final rule falls under the categorical exclusion for actions that are clarifying or corrective in nature.^[837] Northwest Coalition argues that the final rule is not merely clarifying in nature but rather a major change in policy.^[838] Northwest Coalition highlights what it deems the Commission's decision to change its long-standing precedent by allowing use of RFPs as the exclusive means for all QFs to obtain a long-term contract to sell energy and capacity.^[839] Northwest Coalition further argues that overruling existing precedent is not clarifying and the new policy will result in loss of existing QF capacity.^[840]

446. Northwest Coalition asserts that the Commission's reliance on the `corrective' exclusion fails because it is contrary to what Northwest Coalition deems the “obvious intent” of the categorical exclusion for corrective changes to regulations.” ^[841] Northwest Coalition opines that the categorical exclusion applies only to an action “to correct an error, such as a misplaced word or mis-numbered section.” ^[842] Northwest Coalition also contends that the Commission cites no authority to find that changes that are corrective in nature include “changes needed in order to ensure that a regulation conforms to the requirements of the statutory provisions being implemented by the regulation.” ^[843] Northwest Coalition asserts that, as noted in Commissioner Glick's dissent, this interpretation would exempt from NEPA analysis virtually any action the Commission takes under any of its enabling statutes.^[844]

447. Public Interest Organizations assert that the Commission fails to cite precedent for using multiple exclusionary categories for “such an impactful rulemaking.” ^[845] Public Interest Organizations suggest that doing so is a red flag that what they deem sweeping changes in the final rule are not suited for a categorical exclusion.^[846]

448. Finally, Public Interest Organizations argue the Commission failed to engage in the appropriate scoping in determining that a categorical exclusion was appropriate. Public Interest Organizations assert that CEQ regulations require a federal agency to engage in scoping, which is defined in relevant part: “There shall be an early and open process for determining the scope of issues to be addressed and for identifying the significant issues related to a proposed action.” ^[847] Public Interest Organizations note that the CEQ regulations define “NEPA process” to mean “all measures necessary for compliance with the requirements of section 2 and Title 1 of NEPA.” ^[848] Public Interest Organizations conclude that taken together, these two regulations require the application of scoping to the entire NEPA process, including the application of a categorical exclusion.^[849]

ii. Commission Determination

449. We affirm the alternative finding that the final rule was properly categorically excluded because it is clarifying and corrective in nature. Northwest Coalition's arguments are based primarily on what they deem to be the appropriate interpretation of the Commission's categorical exclusion regulation, rather than providing supporting precedent.^[850]

450. Northwest Coalition specifically challenges the use of the clarifying categorical exclusion for the changes to the competitive solicitation process (allowing the use of RFPs as the means for QFs to obtain long-term contracts).^[851] We affirm that the final rule's treatment of competitive solicitations is clarifying in nature because competitive solicitations are already often used by industry to set capacity rates in both PURPA and non-PURPA contexts. Additionally, by including the standards discussed in the Allegheny Principles and elaborating on how states may conduct competitive solicitations as the Commission explained in prior precedent,^[852] the Commission clarified, formalized, and consolidated existing policy.^[853] Finally, the final rule clarifies and follows logically from Commission precedent by requiring that, if a utility places its own capacity in competitive solicitations held at regular intervals and satisfies its capacity needs only through competitive solicitations following the procedural requirements formalized in the final rule, then that utility need not have an alternative avoided cost capacity rate for QFs because it no longer has any avoided capacity costs.

451. We also affirm that the final rule was corrective in nature. With respect to the challenge to variable energy rates in the QF contracts or LEOs, the Commission found that, contrary to expectations in 1980, there are numerous instances where overestimates and underestimates of energy avoided costs used in fixed energy rates did not balance-out over the long term.^[854] Such an imbalance resulted in long-term fixed avoided cost energy rates well above the purchasing utility's avoided costs for energy.^[855] This result is prohibited by PURPA section 210(b).^[856] The Commission's actions to adjust the QF rate framework are necessary to harmonize the Commission's regulations with this underlying finding and to comply with the statutory provisions of PURPA section 210(b).

452. We also find that the Commission's interpretation that corrective actions include those that ensure that a regulation conforms to the requirements of the statutory provisions being implemented by the final rule is appropriate. We disagree that such an interpretation sets a precedent for evading NEPA analysis for future Commission actions. The Commission considers all matters before it, including rulemakings, on a case-by-case basis to determine whether an EIS, EA or a categorical exclusion is appropriate based on the facts and circumstances of each matter. Further, in this case the Commission is not relying on general statutory standards, such as the just and reasonable standard under the FPA, but specific statutory requirements that the Commission may not require above avoided cost rates, that small power production facilities located at a single site may not exceed 80 MW, and that the mandatory purchase obligation may be terminated with respect to QFs with nondiscriminatory access to certain markets.

453. We also disagree with Public Interest Organizations' claim that the Commission inappropriately relied on multiple exclusionary categories in determining that the final rule was subject to a categorical exclusion. As an alternative to its explanation that the effect of the final rule are so speculative as to preclude the preparation of an environmental analysis, the Commission applied a single categorical exclusion that provides four possible bases for its application, including, as relevant here, that the rulemaking is clarifying, corrective, or procedural in nature. The categorical exclusion does not limit the Commission to invoking only one of these bases, nor do Public Interest Organizations elaborate on why the Commission is precluded from doing so.

454. Finally, contrary to Public Interest Organizations' claim, the Commission was not required to initiate a scoping process for the application of the categorical exclusion to the final rule. Public Interest Organizations appear to erroneously conflate the definition of “scoping process” with the definition of “NEPA process.” The CEQ regulations address requirements for scoping only when an EIS is prepared.^[857] Notwithstanding that there is no requirement to provide for scoping for a categorical exclusion, all commenters, including Public Interest Organizations, now have had ample opportunity to provide comments on the application of the categorical exclusion, which they have presented in their rehearing requests.

3. That the Commission Prepared NEPA Analyses for the Promulgation of the Original PURPA Rule and Other Prior Rulemakings Does Not Mean That Such Analysis Was Possible or Required Here

455. As discussed in the final rule, the Commission prepared an EA and EIS for its initial rules implementing PURPA in 1980.^[858] The Commission explained that the EA for Order No. 70 was based on a market penetration study and that, to carry out the market penetration study, the 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.^[859] The Commission stated that, based on these types of facilities, the EA conducted in 1980 identified specific resource conflicts related to each type of facility, which were nothing more than a generalized listing of potential impacts.^[860]

456. The Commission addressed comments on the NOPR that asserted that a NEPA analysis similarly should be possible for this rulemaking. The Commission explained that the assertions are undermined by the fact that circumstances have changed significantly since the promulgation of the original PURPA Regulations in 1980.^[861] The Commission explained that, 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. The Commission explained that by contrast, today QF generation technologies and other independent generation facilities are common, and they are predominantly built and operated outside of PURPA.

457. The Commission further explained that, 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.^[862] The Commission stated that its market penetration study was based on these projections.

458. The Commission noted that, 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.^[863] The Commission explained that the revisions to the PURPA Regulations are premised on a finding that, even after the revisions, the PURPA Regulations will continue to encourage QFs. The Commission found that, 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 ^[864] and have emissions comparable to non-QF fossil fueled generators. The Commission explained that, 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.

459. The Commission stated that renewable generation technologies today are commonly, and even predominantly, built and operated outside of PURPA.^[865] The Commission explained that current projections show that most new generation construction will be of renewable resources ^[866] and cost of renewables has declined so much that in some regions renewables are the most cost effective new generation technology available.^[867] The Commission found that, even if the final rule were 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.

460. The Commission found that, 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.^[868] The Commission explained that, 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.

461. The Commission explained that, 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.^[869] The Commission found that, 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.

a. Requests for Rehearing

462. Northwest Coalition and Public Interest Organizations assert that, in addition to the NEPA analysis for Order No. 70, the Commission has conducted a NEPA analysis for prior rulemakings, which they argue undermines the Commission's claim that the impacts here are too speculative and uncertain to prepare an EA or EIS.^[870] Specifically, Northwest Coalition and Public Interest Organizations point to the competitive bidding NOPR under section 210 of PURPA ^[871] and Order No. 888.^[872]

463. Public Interest Organizations argue that, because an EA was prepared for Order No. 70, the Commission “has experience doing the very thing it alleges is so impossibly burdensome.” ^[873] Public Interest Organizations add that, with respect to Order No. 70, the Commission acknowledged that its NEPA analysis contains uncertainties but is nevertheless required to assess the environmental effects to the fullest extent possible.^[874] They add that Order No. 70 states that the proposed rules did not authorize or fund a particular project or forbid or authorize the use of certain fuels, but the Commission nevertheless prepared a NEPA analysis.^[875] Public Interest Organizations also argue that, in Order No. 70, the Commission was able to develop a specific methodology for predicting its effects on QF development and should be able to do so here as well.^[876]

464. Northwest Coalition asserts that that the Commission's statement in the final rule that the NEPA analysis for Order No. 70 was simpler (because very few renewable cogeneration facilities were online prior to the rule) fails to address how the Commission was able to conduct NEPA analyses for later rulemakings with equal or greater magnitude and complexity than the current case.^[877] Similarly, Public Interest Organizations claim that the Commission cannot underplay its past modeling efforts and could use similar methodology, or advancements in modern modeling software that has significantly improved over the last 40 years, to model the final rule's potential impacts.^[878] As an example, Northwest Coalition and Public Interest Organizations point to the Commission's environmental analysis for the competitive bidding NOPR and Order No. 888, which they claim involved uncertainties and more complex market changes than the final rule.^[879] Related to Order No. 888 specifically, Public Interest Organizations argue that the Commission was able to conduct complex modeling to forecast emissions based on simulations of power generation patterns and should be able to reverse the modeling here to forecast the effects of the final rule.^[880]

b. Commission Determination

465. We reiterate that the Commission considers all matters before it, including rulemakings, on a case-by-case basis as to whether an EIS, EA, or a categorical exclusion is appropriate. As the Commission stated in the final rule, the basis for its NEPA analysis for Order No. 70 was the ability to conduct a market penetration study.^[881] However, circumstances since the promulgation of Order No. 70 have changed significantly, making it impossible to perform a market penetration study of the effects of the final rule that would not be wholly speculative. This is due in large part to the fact that renewable technologies that are commonly adopted by QFs are also commonly adopted by non-QF generation developers today.^[882] In contrast, in 1980, essentially no QF technologies, renewable or otherwise, were being built by non-QFs.^[883] Thus, it was possible in 1980 to assume that certain generation technologies would only be deployed if the PURPA Regulations were issued, and that assumption enabled a market penetration study that could underpin an analysis of the environmental impact of deploying those technologies.^[884] These same assumptions cannot be made today. Renewable technology, for example, is being widely deployed without PURPA support; thus, it is impossible to assume that any potential impact of this rule change will necessarily reduce the deployment of renewables because PURPA is no longer the only route, or even the predominant route, to such development.^[885] To the contrary, as much as 90 percent of all renewable capacity placed in service today was developed outside of PURPA.^[886]

466. We also disagree with Northwest Coalition's and Public Interest Organizations' arguments that the Commission should be able to prepare a NEPA analysis similar to those for the competitive bidding NOPR and Order No. 888, using similar methodology and advancements in modern modeling software. Contrary to Northwest Coalition's and Public Interest Organizations' assertions, the Commission's ability to prepare NEPA analyses in these prior rulemakings does not facilitate our ability to prepare an EA or EIS for this rulemaking. While we agree that modelling technology has advanced since the Commission conducted a NEPA analysis in these prior rulemakings, the Commission would be required to make too many unsupported assumptions to undertake an analysis in this case, which would result in a speculative and meaningless analysis.

467. For example, the Commission would need to assume that all affected QFs would be renewables and all replacement utility generation would be conventional emitting resources, which as previously explained would not necessarily be true in either case.^[887] Similar to the original PURPA rulemaking, the technologies that could qualify for QF status and independent generation more broadly were not widely used outside of the PURPA context when studies were conducted for the competitive bidding NOPR, so the Commission could make basic assumptions about the effects the competitive bidding NOPR would have on QF development.^[888] The same assumptions cannot be made about the final rule as the technologies that renewable QFs use are now widespread and developed outside of PURPA, making any market penetration study wholly speculative.

468. Finally, we disagree that the Commission could reverse engineer the modeling used to forecast emissions based on simulations of power generation patterns in Order No. 888 to forecast the effects of the final rule in a NEPA analysis. The modeling from prior rulemakings is not applicable here. Order No. 888 involved the direct regulation of entities under the Commission's jurisdiction to impose open access requirements, and it was possible to estimate potential changes in conventional generation (gas and coal) development and dispatch in light of the advent of open access to the transmission grid.^[889] In contrast, under the final rule, and PURPA more generally, the Commission sets rules for states and nonregulated electric utilities to implement. The Commission cannot predict how the states will choose to implement the final rule—if at all—and what effect that will have on QF development, whether renewable QFs will be impacted more than non-renewable QFs or whether non-QFs will develop renewables or conventional generation.

V. Regulatory Flexibility Act Certification

469. The Regulatory Flexibility Act of 1980 (RFA) ^[890] generally requires a description and analysis of rules that will have significant economic impact on a substantial number of small entities. No comments on the Regulatory Flexibility Act were filed on rehearing, and the comments on rehearing regarding burden and cost estimates are addressed in the Information Collection Statement section.

470. As discussed in the final rule, we estimate 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.^[891] Therefore, pursuant to section 605(b) of the RFA, we still conclude that this rule will not have a significant economic impact on a substantial number of small entities.

VI. Document Availability

471. 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).

472. 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.

473. User assistance is available for eLibrary and the Commission's website during normal business hours from the Commission's Online Support at [phone] (toll free at 1-866-208-3676) or email at [e-mail], or the Public Reference Room at [phone], TTY [phone]. Email the Public Reference Room at [e-mail].

VII. Effective Dates and Congressional Notification

474. The further revised regulation in this order is effective February 16, 2021. No other changes to the Commission's regulations have been made on rehearing to the final rule, however we modify the instructions to the Form No. 556. Out of an abundance of caution, this order addressing arguments raised on rehearing is being submitted to the Administrator of the Office of Information and Regulatory Affairs of OMB, Senate, House, and Government Accountability Office.

List of Subjects in 18 CFR Part 292

• Electric power plants; Electric utilities
• Reporting and recordkeeping requirements

By the Commission. Commissioner Glick is dissenting in part with a separate statement attached.

Issued: November 19, 2020.

Kimberly D. Bose,

Secretary.

In consideration of the foregoing, the Commission amends part 292, chapter I, title 18, Code of Federal Regulations, as follows.

SUBCHAPTER K—REGULATIONS UNDER THE PUBLIC UTILITY REGULATORY POLICIES ACT OF 1978

* * * * *

PART 292—REGULATIONS UNDER SECTIONS 201 AND 210 OF THE PUBLIC UTILITY REGULATORY POLICIES ACT OF 1978 WITH REGARD TO SMALL POWER PRODUCTION AND COGENERATION

1. The authority citation for part 292 continues to read as follows:

Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352.

2. Amend § 292.309 by revising paragraphs (c), (d), (e), and (f) to read as follows:

§ 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) 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 February 16, 2021, 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 § 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 should be relieved of the obligation to purchase electric energy from the qualifying facilities.

(1) A qualifying facility above 20 MW may seek to rebut this presumption by demonstrating, inter alia, that:

(i) The qualifying facility has certain operational characteristics that effectively prevent the qualifying facility's participation in a market; or

(ii) 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.

(2) A small power producer qualifying facility between 5 megawatts and 20 megawatts may show 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 section § 292.309(a)(1), (2), and (3);

(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.

(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.

(1) A qualifying facility above 20 MW may seek to rebut this presumption by demonstrating, inter alia, that:

(i) The qualifying facility has certain operational characteristics that effectively prevent the qualifying facility's participation in a market; or

(ii) 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.

(2) A small power producer qualifying facility between 5 megawatts and 20 megawatts may show 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 section § 292.309(a)(1), (2), and (3);

(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.

* * * * *

Note:

The following appendix will not appear in the Code of Federal Regulations.

Appendix B

Revised Form No. 556

United States of America

Federal Energy Regulatory Commission

	Docket Nos.
Qualifying Facility Rates and Requirements	RM19-15-001
Implementation Issues Under the Public Utility Regulatory Policies Act of 1978	AD16-16-001

(Issued November 19, 2020)

GLICK, Commissioner, dissenting in part:

1. I dissent in part from today's order on rehearing (Rehearing Order ^[1] ) because it upholds the overwhelming majority of Order No. 872,^[2] which effectively gutted the Commission's implementation of the Public Utility Regulatory Policies Act (PURPA).^[3] 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.^[4] I do not believe that Order No. 872 satisfies those responsibilities.

2. Although I have concerns about many of the individual changes imposed by the Order No. 872,^[5] 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.^[6] 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.

• PURPA's Continuing Relevance Is an Issue for Congress To Decide

3. This proceeding began with a bang. The Commission championed its NOPR as a “truly significant” action that would fundamentally overhaul the Commission's implementation of PURPA.^[7] And so it was. The NOPR suggested altering 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 for over four decades. Although Order No. 872 walked back some of the NOPR's most extreme proposals, it adopted the overwhelming majority of the NOPR, including all of its tenets. In so doing, the Commission upended the regulatory regime that has formed the basis of its implementation of PURPA almost since the day the statute was enacted.

4. I partially dissented from both the NOPR and Order No. 872 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.” ^[8] 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.^[9] And while Congress considered numerous proposals to further reform the law, it never saw fit to act on them.^[10] 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.” ^[11] 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.” ^[12]

5. Order No. 872 and today's order on rehearing retreat 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, Order No. 872 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 Order No. 872 is overturned on appeal, that does not change the fact that the 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 amend our regulations implementing PURPA.^[13] Order No. 872, 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 continue to doubt that is what Congress had in mind when it gave us responsibility for periodically updating our implementing regulations.

• 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,^[14] including by establishing rates for sales by QFs that are just and reasonable and by ensuring that such rates “shall not discriminate” against QFs.^[15] The changes adopted by the Commission in Order No. 872 fail to meet that standard. In addition, many of the reforms are unsupported—and, in many cases, contradicted—by the evidence in the record.^[16] Accordingly, I believe Order No. 872 is not just poor public policy, but also arbitrary and capricious agency action.

A. Avoided Cost

8. The Final Rule adopted two fundamental changes to how QF rates are determined. First, and most importantly, it eliminated 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.^[17] Second, it presumptively allows states to set the rate for as-available energy at the relevant locational marginal price (LMP).^[18] The record in this proceeding does not support either of those changes.

i. Elimination of Fixed Energy Rate

9. Prior to Order No. 872, 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 the two 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. Order No. 872 eliminated the requirement that states provide a contract option that includes a fixed energy rate.^[19] Prior to this proceeding, the Commission recognized time and again that fixed-price contracts play an essential role in financing QF facilities, making them a necessary element of any effort to encourage QF development, at least in certain regions of the country.^[20] 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.^[21]

11. The record before us confirms the continuing importance of the fixed-price contract option for QFs. Numerous entities with experience in 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.^[22] In both Order No. 872 and today's order on rehearing, the Commission responds to that evidence with a reference to the general track record of independent power producers, and renewables developers in particular, that develop new resources without a regulatory guarantee of a fixed revenue stream.^[23] But the overwhelming majority of the Commission's statistics reflect development in RTO/ISO markets, where developers generally can rely on financing arrangements, such as commodity hedges, to lock-in the revenue needed to secure financing.^[24]

12. Those products are far less ubiquitous—if they are available at all—outside of RTO/ISO markets.^[25] Accordingly, the success of relatively large independent power producers in the organized markets does not constitute substantial evidence suggesting that QFs will be able to finance new development outside RTO/ISO markets where PURPA plays a larger role.^[26] Indeed, the Commission's deliberate blurring of the lines between RTO/ISO markets and the rest of the country is the equivalent of arguing that Tommie and Hank Aaron ought to both be hall-of-famers because, together, they hit 768 home runs, while ignoring the fact that Hank was responsible for 755 of the brothers' 768 home runs.^[27]

13. The Commission next responds that PURPA does not require that QFs be financeable.^[28] 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.^[29] 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 order, notwithstanding the Commission's repeated assertions to the contrary.^[30]

14. In addition, 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.^[31] Commission precedent, however, permits utilities to offer a capacity rate of zero to QFs when the utility does not need incremental capacity.^[32] That means that, after Order No. 872, QF developers now face the very real prospect of not receiving any fixed revenue stream, whether for energy or capacity, on top the fact at they also may not be able to secure hedging products or other mechanisms needed to finance a new QF.^[33] 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.^[34]

15. 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.^[35] Vertically integrated utilities effectively receive guaranteed fixed-price contracts through their rights to recover prudently incurred investments.^[36] QFs' equivalent right to receive fixed-price contracts for energy has to date proved an integral element of the Commission's ability to prevent discrimination against QFs.^[37] Neither Order No. 872 nor today's order on rehearing adequately explain how eliminating the fixed-price option is consistent with that prohibition or, moreover, how permitting QFs to receive variable rates for energy while any vertically integrated utility to which they sell electricity receives fixed rates is consistent with the Commission's obligation to encourage QF development.^[38]

16. On rehearing, the Commission argues that both Congress and the Supreme Court “recognize that PURPA treats QFs differently from purchasing utilities, rendering QFs not similarly situated to non-QF resources.” ^[39] As an initial matter, the question of whether entities are similarly situated is one that is relevant to evaluating whether any discrimination is undue.^[40] PURPA, however, prohibits any discrimination against QFs, not just undue discrimination.^[41] In any case, the congressional language cited by the Commission,^[42] which the Court reiterated, stands only for the proposition that Congress did not intend to apply traditional utility ratemaking concepts, such as guaranteed cost recovery, to QFs. But while Congress clearly envisioned different cost-recovery regimes for incumbent utilities and QFs, PURPA's prohibition on discrimination against QFs indicates that the ratemaking regime applicable to QFs can be no less favorable than that applied to incumbent purchasing utilities. Permitting QFs to receive only variable-rate contracts while incumbent utilities simultaneously receive what are functionally decades-long fixed price contracts through their retail rates plainly falls short of the standard.

17. Finally, the Commission fails to explain why certain allegations of QF rates exceeding a utility's actual avoided cost require us to abandon fixed-price contracts.^[43] The Commission has long recognized that QF rates may exceed actual avoided costs, but, at the same time, 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.” ^[44] Today's order on rehearing takes the position that variable-price contracts are necessary to ensure that QF rates do not exceed utility avoided costs.^[45] The Commission, however, both fails to adequately explain that new interpretation of PURPA ^[46] and justify the avulsive change of course that it represents.^[47]

ii. Setting Avoided Cost at LMP

18. I also do not support the Commission's decision to treat LMP as a presumptively reasonable measure of a utility's as-available avoided cost for energy.^[48] The short-term marginal cost of production represented by LMP can be a useful and transparent input and ought to be considered in calculating an appropriate avoided-cost for as-available energy. But considering LMP in setting avoided cost is not the same thing as presuming that LMP is a sufficient measure to establish the avoided cost rate for energy. And, as the Public Interest Organizations explain, the record is replete with evidence indicating that vertically integrated utilities' costs are often well above LMP.^[49] Where there is good reason to believe that LMP may not actually reflect the avoided cost of the purchasing utility, it makes no sense to put the burden on QFs to prove the point.

19. On rehearing, the Commission responds that its rebuttable presumption has not changed the burden of proof, only the burden of production.^[50] That's an argument that only a lawyer's mother could love. It discounts the very real concerns about whether LMP is an accurate reflection of a purchasing utility's avoided energy costs. In any case, as the precedent cited by the Commission makes clear, an administrative agency cannot defend an irrational presumption simply by labeling it a shift in the burden of production.^[51] Because the presumption does not makes sense in its own right, the Commission cannot rehabilitate that presumption by labeling it merely a shift in the burden of production rather than persuasion.^[52]

20. Finally, the presumption that LMP is an adequate measure of a utility's full avoided energy cost is even more problematic when combined with the decision to eliminate the fixed-price contract option. Because the Commission has removed the requirement that utilities offer a fixed-price contract option for energy, it is entirely possible that a QF will be eligible to receive only LMP both on a short-term basis and a long-term basis as a result of the variable cost structure now permitted under the long-term contract.^[53] Given this reality, QFs may be reduced to relying solely on some highly variable measure of the spot market price for energy, all while the utilities whose costs the QF is avoiding potentially recover an effectively guaranteed rate well above that spot market price, particularly in RTO/ISO markets that remain vertically integrated.^[54] I am not persuaded that this approach will satisfy our obligation to encourage QFs and do so using rates that are non-discriminatory across all regions of the country.

B. Rebuttable Presumption 20 MW to 5 MW

21. 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.^[55] Order No. 872 reduced the threshold for that presumption from 20 MW to 5 MW.^[56] That was an improvement over the NOPR, which—without any support whatsoever—proposed to lower that threshold to 1 MW.^[57] But, even so, the reduced 5-MW threshold is unsupported by the record and inadequately justified on rehearing.

22. 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.^[58] 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.” ^[59]

23. Nevertheless, Order No. 872 abandoned the 20 MW threshold based on the conclusory assertion that “it is reasonable to presume that access to RTO/ISO markets has improved,” making it “appropriate to update the presumption.” ^[60] 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 still significantly inhibit non-discriminatory access, or why 5 MW is an appropriate new threshold for that presumption.^[61]

24. Instead of any such evidence, Order No. 872 noted that the Commission uses the 5-MW level as a demarcating line for other rules applying to small resources. It points in particular 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.^[62] 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. Specifically, the 5 MW cut off in the Commission's interconnection rule is based on the impacts that projects below 5 MW are likely to have on system safety and reliability, not on whether they have non-discriminatory market access.^[63] In addition, the Commission points to the fact that “`all of the RTOs/ISOs have at least one participation model that allows resources as small as 100 kW to participate in their markets.' ” ^[64] Be that as it may, that fact that all RTOs do not prohibit certain small resources from accessing their markets does not support the proposition that QFs below 5 MW now have non-discriminatory access to those markets.

25. Lacking substantial evidence to support the 5 MW threshold, Order No. 872 made a great deal out the deferential standard of review applied to the Commission's rulemakings.^[65] But while judicial review of agency policymaking is deferential, it is not toothless. The cases on which the Commission relied still 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.” ^[66] 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.” ^[67] For the foregoing reasons, the Commission has failed to produce any such explanation, making its change of course arbitrary and capricious.

• Environmental Review Under the National Environmental Policy Act

26. Today's order also doubles down on the Commission's refusal to conduct any environmental review whatsoever of the likely consequences of Order No. 872's reforms. Whatever one may think of the questionable merits of those reforms, no one can seriously argue that they are anything short of a significant and sweeping overhaul of the Commission's forty-year-old framework for implementing PURPA. And yet, at the same time that the Commission has championed the scope of its sweeping reforms, it simultaneously insists that no environmental review is necessary both because it cannot venture any guess as to the effects of those reforms and because they somehow fit into a categorical exception from NEPA review. Neither justification holds water.

27. As an initial matter, the Commission's assertion that Order No. 872's effects are overly speculative is tough to square with the fact that it has not undertaken any effort whatsoever to assess those effects. For example, instead of performing any modeling exercises, as the Commission did in the environmental assessment it issued along with its PURPA regulations in 1980,^[68] the Commission peremptorily rejects the possibility that it could glean anything useful from such an exercise. I have a hard time believing that our modeling capabilities have not improved dramatically over the course of the last four decades or that we cannot use those capabilities to perform an analysis that is quite a bit more detailed and reliable than that which was previously good enough for the Commission. In any case, NEPA does not require complete certainty or exacting precision. Instead, it recognizes that administrative agencies will often have to rely “ `reasonable forecasting' ” aided by “ `educated assumptions.' ” ^[69] Nothing in Order No. 872 or today's order on rehearing adequately explains why those techniques could not have formed the basis for a useful environmental review of the likely consequences of this proceeding.

28. In addition, in a head-spinning contrast to the Commission's crowing over the significance of its PURPA overhaul, the Commission describes the changes adopted as merely corrective and clarifying in nature for the purposes of avoiding its environmental review.^[70] 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.” ^[71] 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.

29. 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. That would seem to exempt any future Commission action under PUPRA or Title II of the FPA from NEPA, at least absent a major congressional revision of those statutes. 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. Accordingly, I do not believe that the Commission has demonstrated that the significant changes made in Order No. 872 qualify for any of the existing categorical exclusions, meaning that this significant revision of our PURPA regulations requires an environmental review under NEPA.

• The Way To Revise PURPA Is To Create More Competition, Not Less

30. 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.^[72] 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.^[73]

31. 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.^[74] 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.^[75] Other groups, including representatives of QF interests, submitted additional comments on how an approach along those lines might work.^[76] Several parties commented on those proposals.^[77]

32. 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. Although the Commission can still consider proposals along the lines of the NARUC approach,^[78] making that approach the center of our reforms 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 simply dismantle 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.

Footnotes

1.  Qualifying Facility Rates and Requirements Implementation Issues Under the Public Utility Regulatory Policies Act of 1978, Order No. 872, 85 FR 54638 (Sep. 2, 2020), 172 FERC ¶ 61,041 (2020).

2.  18 CFR part 292. In connection with the revisions to the PURPA Regulations, the Commission also revised its delegation of authority to Commission staff in 18 CFR part 375.

3.  16 U.S.C. 796(17)-(18), 824a-3.

4.  California Utilities consist of Pacific Gas & Electric Company; San Diego Gas & Electric Company; and Southern California Edison Company.

5.  Northwest Coalition consists of Northwest and Intermountain Independent Power Producers Association; the Community Renewable Energy Association; the Renewable Energy Coalition; IdaHydro; Oregon Solar Energy Industries Association; and NewSun Energy LLC. Excluding IdaHydro and NewSun Energy LLC, the entities comprising Northwest Coalition filed comments referred to in Order No. 872 as “NIPPC, CREA, REC, and OSEIA.” For ease of reference, in some instances below, we refer to Northwest Coalition below interchangeably with “NIPPC, CREA, REC, and OSEIA.”

6.  Public Interest Organizations consist of Alabama Interfaith Power and Light; Appalachian Voices; Center for Biological Diversity; Environmental Law and Policy Center; Gasp; Georgia Interfaith Power and Light; Montana Environmental Information Center; Natural Resources Defense Council; North Carolina Sustainable Energy Association; Sierra Club; South Carolina Coastal Conservation League; Southern Alliance for Clean Energy; Southern Environmental Law Center; Southface Institute; Sustainable FERC Project; Tennessee Interfaith Power and Light; Upstate Forever; and Vote Solar. Some of these entities filed comments as “Southeast Public Interest Organizations” and some of these entities filed comments as “Public Interest Organizations.” For ease of reference, we refer below to these organizations on rehearing as “Public Interest Organizations,” however, but when referring to the separate groups' comments in this rulemaking proceeding, we refer to their separate comments.

7.  964 F.3d 1 (D.C. Cir. 2020) (en banc).

8.  16 U.S.C. 825 l (a) (“Until the record in a proceeding shall have been filed in a court of appeals, as provided in subsection (b), the Commission may at any time, upon reasonable notice and in such manner as it shall deem proper, modify or set aside, in whole or in part, any finding or order made or issued by it under the provisions of this chapter.”).

9.  Allegheny Def. Project, 964 F.3d at 16-17. The Commission is not changing the outcome of the final rule. See Smith Lake Improvement & Stakeholders Ass'n v. FERC, 809 F.3d 55, 56-57 (D.C. Cir. 2015).

10.  16 U.S.C. 824a-3(a).

11.  16 U.S.C. 824a-3(b).

12.  Id.

13.  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”).

14.  H.R. Rep. No. 95-1750, at 98 (1978) (Conf. Rep.) (emphasis added).

15.  16 U.S.C. 796(17)(A)(ii).

16.  18 CFR 292.204(a)(ii).

17.  See 16 U.S.C. 824a-3(m).

18.  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) (AFPA v. FERC).

19.  18 CFR 292.309(d)(1).

20.  Order No. 688, 117 FERC ¶ 61,078 at P 74.

21.  Order No. 872, 172 FERC ¶ 61,041 at P 20.

22.  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 legally enforceable obligation (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.

23.  Qualifying Facility Rates and Requirements, 84 FR 53246 (Oct. 4, 2019), 168 FERC ¶ 61,184 (2019) (NOPR).

24.  Order No. 872, 172 FERC ¶ 61,041 at P 56.

25.  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).

26.  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.

27.  Order No. 872, 172 FERC ¶ 61,041 at P 57.

28.  Id. P 58.

29.  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).

30.  Order No. 872, 172 FERC ¶ 61,041 at P 59.

31.  Id.

32.  Id. P 60 (referencing Allegheny Energy Supply Co., LLC, 108 FERC ¶ 61,082, at P 18 (2004) (Allegheny Energy)).

33.  Id. P 62.

34.  Id. P 63.

35.  Id. P 64.

36.  Id. P 65.

37.  Id. P 66.

38.  Because California Utilities requested clarification, and not rehearing, of the final rule, we accept California Commission's answer to California Utilities' request for clarification of the final rule. See 18 CFR 385.213(a)(3).

39.  Public Interest Organizations Request for Rehearing at 6, 12-14.

40.  Id. at 13.

41.  Id. (citing 16 U.S.C. 824a-3(a)(2)).

42.  Id. at 13-14 (citing 50 CFR 402.14; Cooling Water Intake Structure Coal. v. U.S. Envtl. Prot. Agency, 905 F.3d 49, 78 (2d Cir. 2018)).

43.  Id. at 14.

44.  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).

45.  Connecticut Public Utilities Regulatory Authority (Connecticut Authority) and Massachusetts Department of Public Utilities (Massachusetts DPU) Comments, Docket No. AD16-16-000 (Nov. 7, 2016); Idaho Public Utilities Commission (Idaho Commission) Comments, Docket No. AD16-16-000 (Nov. 7, 2016); Commissioner Paul Kjellander, Idaho Commission Comments, Docket No. AD16-16-000 (June 29, 2016); Commissioner Christine Raper, Idaho Commission Comments, Docket No. AD16-16-000 (June 29, 2016); Commissioner Travis Kavulla, Montana Public Service Commission (Montana Commission) and on behalf of NARUC Comments, Docket No. AD16-16-000 (June 29, 2016).

46.  Commissioner Anthony O'Donnell, Montana Commission Comments, Docket No. RM19-15-000 (Dec. 3, 2019); Arizona Commission Comments, Docket No. RM19-15-000 (Dec. 3, 2019); California Public Utilities Commission (California Commission) Comments, Docket No. RM19-15-000 (Dec. 3, 2019); District of Columbia Public Service Commission (DC Commission) Comments, Docket No. RM19-15-000 (Dec. 3, 2019); Governor Brad Little (Idaho) Comments, Docket No. RM19-15-000 (Dec. 2, 2019); Idaho Commission Comments, Docket No. RM19-15-000 (Dec. 3, 2019); Kentucky Public Service Commission Comments, Docket No. RM19-15-000 (Dec. 3, 2019); Massachusetts Attorney General Maura Healey Comments, Docket No. RM19-15-000 (Dec. 3, 2019); Massachusetts DPU Comments, Docket No. RM19-15-000 (Dec. 3, 2019); Michigan Public Service Commission Comments, Docket No. RM19-15-000 (Dec. 3, 2019); Montana Commission Comments, Docket No. RM19-15-000 (Dec. 3, 2019); North Carolina Attorney General Comments, Docket No. RM19-15-000 (Dec. 3, 2019); North Carolina Public Service Commission Public Staff Comments, Docket No. RM19-15-000 (Dec. 3, 2019); Nebraska Power Review Board Comments, Docket No. RM19-15-000 (Nov. 22, 2019); Ohio Consumers Counsel Comments, Docket No. RM19-15-000 (Dec. 3, 2019); Oregon Public Utility Commission Comments, Docket No. RM19-15-000 (Dec. 3, 2019); Pennsylvania Public Utility Commission Comments, Docket No. RM19-15-000 (Dec. 3, 2019); Public Utility Commission of Ohio Federal Energy Advocate Comments, Docket No. RM19-15-000 (Dec. 3, 2019); South Dakota Public Utilities Commission Comments, Docket No. RM19-15-000 (Dec. 3, 2019).

47.  State Entities Comments, Docket No. RM19-15-000 (Dec. 3, 2019) (filed on behalf of Massachusetts Attorney General, Delaware Attorney General, District of Columbia Attorney General, Maryland Attorney General, Michigan Attorney General, New Jersey Attorney General, North Carolina Attorney General, Oregon Attorney General, New Jersey Board of Public Utilities, Rhode Island Division of Public Utilities and Carriers); NARUC Comments, Docket No. RM19-15-000 (Dec. 3, 2019); NARUC Supplemental Comments, Docket No. AD16-16-000 (Oct. 17, 2018); see also NOPR, 168 FERC ¶ 61,184, (NOPR published in Federal Register).

48.  Public Interest Organizations Request for Rehearing at 8, 43-60; Solar Energy Industries Request for Rehearing and/or Clarification at 2-4, 4-6, 8-9, 42-45.

49.  Solar Energy Industries Rehearing Request at 4, 8-9.

50.  Id. at 6 (citing Order No. 872, 172 FERC ¶ 61,041 at P 78).

51.  Id.

52.  Public Interest Organizations Request for Rehearing at 43-45.

53.  Id. at 44-46 (citing Order No. 872, 172 FERC ¶ 61,041 at P 72).

54.  Id. at 46-60.

55.  Id. at 46 (citing Order No. 872, 172 FERC ¶ 61,041 at PP 553, 584, 587, 746).

56.  Id. at 46-47 (citing Order No. 872, 172 FERC ¶ 61,041 at P 78).

57.  Id. at 48-49 (citing Small Power Production and Cogeneration Facilities; Regulations Implementing Section 210 of the Public Utility Regulatory Policies Act of 1978, Order No. 69, 45 FR 12214 (Feb. 25,1980), FERC Stats. & Regs. ¶ 30,128, at 30,863 (cross-referenced 10 FERC ¶ 61,150), order on reh'g, Order No. 69-A, 45 FR 33958 (May 21, 1980), 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)).

58.  Id.

59.  Id. at 49-57.

60.  Id. at 49.

61.  Id. at 49-50 (citing Order No. 872, 172 FERC ¶ 61,041 at PP 43-46).

62.  Id. at 51-52 (citing Harvard Electricity Law Initiative (Harvard Electricity Law) Comments, Docket No. RM19-15-000, at 19-21 (Dec. 3, 2019); Solar Energy Industries Supplemental Comments, Docket No. AD16-16-000, at 16 (Aug. 28, 2019)).

63.  Id. at 52-53.

64.  Id. at 53.

65.  Id. at 54.

66.  Id. at 55.

67.  Id. at 56.

68.  Id. at 57.

69.  Id. at 58-59.

70.  Id. at 59-60.

71.  In subsequent sections of this order, we address Solar Energy Industries' concerns that the PURPA Regulations, as revised, fail to encourage QFs due to the specific revisions (1) allowing states to set avoided energy costs using variable energy rates; (2) expanding the one-mile rule; and (3) lowering the threshold for presumptive nondiscriminatory access for facilities in competitive wholesale markets from 20 MW to 5 MW. See infra sections III.B.4, III.C, and III.F.

72.  See Public Interest Organizations Request for Rehearing at 46 (footnote omitted) (“There is significant space provided within the confines of the limitations Congress established to encourage QFs. FERC's reasoning that because it cannot encourage QFs by exceeding the bounds set by Congress it need not fully encourage QFs within the bounds of the statute fails to give effect to Congress' command to encourage QFs. The Commission can, and must, issue rules that support QF development while complying with the other statutory requirements and limits on the form of that support.”).

73.  Order No. 872, 172 FERC ¶ 61,041 at P 359 (citing 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)).

74.  See Public Interest Organizations Request for Rehearing at 37-39.

75.  Order No. 872, 172 FERC ¶ 61,041 at PP 232-360.

76.  In addition, the Commission in Order No. 872 kept intact the regulations issued to overcome the barriers to QFs identified in Order No. 69. Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,863; see also Order No. 872, 172 FERC ¶ 61,041 at PP 10, 28-41, 78.

77.  Technical Conference Tr. at 143-44 (Commissioner Kristine Raper, Idaho Commission).

78.  See Order No. 872, 172 FERC ¶ 61,041 at PP 30-32.

79.  See FERC v. Miss., 456 U.S. 742, 767 (1982) (internal quotations omitted) (stating that PURPA is a “program of cooperative federalism that allows the States, within limits established by federal minimum standards, to enact and administer their own regulatory programs, structured to meet their own particular needs”).

80.  See 18 CFR 366.3(a)(1).

81.  See, e.g., GRE 314 East Lyme LLC, 171 FERC ¶ 61,199 (2020); Branch Street Solar Partners, LLC, 169 FERC ¶ 61,269 (2019); Zeeland Farm Servs., Inc., 163 FERC ¶ 61,115 (2018); Minwind I, 149 FERC ¶ 61,109 (2014); Beaver Falls Mun. Auth., 149 FERC ¶ 61,108 (2014).

82.  16 U.S.C. 824a-3(b).

83.  16 U.S.C. 824a-3(b)(1)-(2).

84.  16 U.S.C. 824a-3(b).

85.  16 U.S.C. 824a-3(d) (emphasis added).

86.  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.”).

87.  18 CFR 292.304(d)(1).

88.  18 CFR 292.304(d)(2)(i)-(ii); see also FLS Energy, Inc., 157 FERC ¶ 61,211, at P 21 (2016) (FLS) (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.

89.  18 CFR 292.304(d)(2)(i).

90.  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).

91.  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.”).

92.  Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,880.

93.  NOPR, 168 FERC ¶ 61,184 at PP 32-33.

94.  Order No. 872, 172 FERC ¶ 61,041 at P 101.

95.  Id. P 124.

96.  Id. P 151.

97.  See id. P 153 (citing 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); Offer Caps in Markets Operated by Regional Transmission Organizations and Independent System Operators, Order No. 831, 81 FR 87770 (Dec. 5 2016), 157 FERC ¶ 61,115, at P 7 (2016), order on reh'g and clarification, Order No. 831-A, 82 FR 53403 (Nov. 16, 2017), 161 FERC ¶ 61,156 (2017))).

98.  Id. P 152.

99.  Union of Concerned Scientists Comments, Docket No. RM19-15-000, at 3-8 (Nov. 15, 2019).

100.  NIPPC, CREA, REC, and OSEIA Comments, Docket No. RM19-15-000, at 52 (Dec. 3, 2019).

101.  Public Interest Organizations Comments, Docket No. RM19-15-000, at 52-64 (Dec. 3, 2019).

102.  Order No. 872, 172 FERC ¶ 61,041 at PP 155-56.

103.  Solar Energy Industries Comments, Docket No. RM19-15-000, at 27-28 (Dec. 3, 2019).

104.  Order No. 872, 172 FERC ¶ 61,041 at P 158.

105.  NIPPC, CREA, REC, and OSEIA Comments, Docket No. RM19-15-000, at 53 (Dec. 3, 2019).

106.  Order No. 872, 172 FERC ¶ 61,041 at P 160.

107.  Public Interest Organizations Request for Rehearing at 60-72 (citing 18 CFR 292.304(b)(6)).

108.  Id. at 62.

109.  Id.

110.  Id. at 64 (citing Order No. 872, 172 FERC ¶ 61,041 at P 52).

111.  Id. at 66 (citing Cablevision Sys. Corp. v. FCC, 649 F.3d 695, 716 (D.C. Cir. 2011) (Cablevision); Nat'l Mining Ass'n v. Dep't of Interior, 177 F.3d 1, 6 (D.C. Cir. 1999)); Sec'y of Labor v. Keystone Coal Min. Corp., 151 F.3d 1096, 1100-01 (D.C. Cir. 1998)).

112.  Id. at 68 & n.200 (citing Public Interest Organizations Comments, Docket No. RM19-15-000, at 47-54 (Dec. 3, 2019)).

113.  Id. at 69.

114.  Id. at 69-72.

115.  See Cablevision, 649 F.3d at 716 (citing 5 U.S.C. 556(d)).

116.  See Order No. 872, 172 FERC ¶ 61,041 at PP 153, 156.

117.  See id. P 152.

118.  See AFPA v. FERC, 550 F.3d at 1183 (permitting Commission to establish rebuttable presumption via rulemaking rather than case-by-case adjudication in PURPA section 210(m) context).

119.  Order No. 872, 172 FERC ¶ 61,041 at P 153 (finding 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”) (citing NOPR, 168 FERC ¶ 61,184 at PP 44-45 (citing FERC v. Elec. Power Supply Ass'n, 136 S. Ct. 760, 768-69 (2016) (describing how LMP is typically calculated); Sacramento Mun. Util. Dist. v. FERC, 616 F.3d 520, 524 (D.C. Cir. 2010); Order No. 831, 157 FERC ¶ 61,115 at P 7).

120.  Nat'l Mining Ass'n v. U.S. Dep't of Interior, 177 F.3d at 6.

121.  See Order No. 872, 172 FERC ¶ 61,041 at PP 155-71 (discussing why LMP is presumptively an appropriate measure of avoided energy costs even if in particular circumstances it is not appropriate).

122.  See Public Interest Organizations Request for Rehearing at 71 (footnote omitted) (citing Public Interest Organizations Comments, Docket No. RM19-15-000, at 46-55 (Dec. 3, 2019)) (“[E]ven utilities that operate in organized markets acquire energy outside of the day ahead market or produce energy at variable costs that exceed the market price and sell at a loss to the day ahead market. Price suppression is thus one indicator of the larger problem that the day ahead market is not reflecting the actual cost of energy supply to utilities, which belies FERC's assumption that the LMP reflects all utilities' actual cost for all marginal energy.”).

123.  California Utilities Motion for Clarification at 1-2.

124.  Californians for Renewable Energy v. Cal. Pub. Utils. Comm'n, 922 F.3d 929 (9th Cir. 2019) (CARE v. CPUC).

125.  Cal. Pub. Utils. Comm'n, 133 FERC ¶ 61,059 (2010) (CPUC 2010), clarification and reh'g denied, 134 FERC ¶ 61,044 (2011) (CPUC 2011).

126.  California Utilities Motion for Clarification at 3-8.

127.  Id. at 3 (citing S. Cal. Edison Co., 70 FERC ¶ 61,215 (CPUC 1995 I), reconsideration denied, 71 FERC ¶ 61,269 (1995) (CPUC 1995 II)).

128.  Id. at 4 (citing CPUC 2010, 133 FERC ¶ 61,059 at P 30).

129.  Id. at 5 (citing CARE v. CPUC, 922 F.3d 929).

130.  Id. (citing Order No. 872, 172 FERC ¶ 61,041 at P 123).

131.  See new 18 CFR 292.304(d)(8)(i)(B).

132.  California Utilities Motion for Clarification at 9-10.

133.  Id. at 13-14.

134.  California Commission Answer at 4-5.

135.  Id. at 5-6.

136.  Id. at 7-9.

137.  Id. at 9-11.

138.  Id. at 11-12.

139.  The Commission in the final rule addressed arguments that QFs provide non-energy benefits. The Commission stated that such benefits may be addressed by states outside of PURPA. Because tiered QF rates result from tiered procurement not limited to QFs, and are therefore established outside of PURPA, nothing in PURPA prohibits such tiered rates. See Order No. 872, 172 FERC ¶ 61,041 at P 123; see also CPUC 2010, 133 FERC ¶ 61,059 at P 31 (“[A]lthough a state may not include a bonus or an adder in the avoided cost rate unless it reflects actual costs avoided, a state may separately provide additional compensation for environmental externalities, outside the confines of, and, in addition to the PURPA avoided cost rate, through the creation of renewable energy credits. . . .”).

140.  18 CFR 292.304(d)(2)(ii).

141.  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”).

142.  Id.

143.  Id.

144.  NOPR, 168 FERC ¶ 61,184 at P 67.

145.  16 U.S.C. 824a-3(b)(1).

146.  Order No. 872, 172 FERC ¶ 61,041 at P 253.

147.  See id. (citing Duke Energy Comments, Docket No. RM19-15-000, at 6 (Dec. 3, 2019) (Duke's QF contracts cost $4.66 billion but its “actual current avoided costs” are $2.4 billion); Idaho Power Comments, Docket No. RM19-15-000, at 10-11 (Dec. 3, 2019) (“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, Docket No. RM19-15-000, at 5 (Dec. 3, 2019) (“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 (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); Edison Electric Institute (EEI) Supplemental Comments, Docket No. AD16-16-000, attach. A at 3-4 (June 25, 2018) (“On August 1, 2014, a 10-year fixed price contract at the Mid-Columbia wholesale power market trading hub was priced at $45.87/MWh. On June 30, 2016, the same contract was priced as $30.22/MWh, a decline of 34% in less than two years. However, over the next 10 years, PacifiCorp has a legal obligation to purchase 51.9 million MWhs under its PURPA contract obligations at an average price of $59.87/MWh. The average forward price curve for the Mid-Columbia trading hub during the same period is $30.22/MWh, or 50% below the average PURPA contract price that PacifiCorp will pay. The additional price required under long-term fixed contracts will cost PacifiCorp's customers $1.5 billion above current forward market prices over the next 10 years.”); Comm'r Kristine Raper, Idaho Commission Comments, Docket No. AD16-16-000, at 3-4 (June 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).”)).

148.  Order No. 872, 172 FERC ¶ 61,041 at PP 254-55.

149.  Id. P 256.

150.  Id. P 258 (citing Conf. Rep. at 98 (emphasis added) (“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.”)).

151.  Under the approach adopted in the 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, the Commission permitted states to adopt a pricing approach that best fits their circumstances, including adopting the pricing approach described by the PURPA Conference Report to address the circumstances described by the PURPA Conference Report. Id. P 260 n.409.

152.  Id. P 260.

153.  Id. P 261 (citing Harvard Electricity Law Comments, Docket No. RM19-15-000, at 29 (Dec. 3, 2019) (citing Freehold Cogeneration Ass'n v. Bd. of Regulatory Comm'rs of State of N.J., 44 F.3d 1178, 1193 (3d Cir. 1995) (Freehold Cogeneration); Smith Cogeneration Mgmt. v. Corp. Comm'n, 863 P.2d 1227, 1227 (Okla. 1993) (Smith Cogeneration))).

154.  Id. (citing Smith Cogeneration, 863 P.2d at 1241 (emphasis added) (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”); Freehold Cogeneration, 44 F.3d at 1193 (emphasis added) (relying on Smith Cogeneration analysis that “that PURPA and FERC regulations preempted the State Commission rule”)).

155.  Id. P 262.

156.  Id. P 263.

157.  Id. P 264 (citing Harvard Electricity Law Comments, Docket No. RM19-15-000, at 23 (Dec. 3, 2019) (citing API, 461 U.S. at 414)).

158.  Id.

159.  Id. P 283 (citing Duke Comments, Docket No. RM19-15-000, at 6 (Dec. 3, 2019); Idaho Power Comments, Docket No. RM19-15-000, at 10-11 (Dec. 3, 2019); Portland General Comments, Docket No. RM19-15-000, at 5 (Dec. 3, 2019); NOPR, 168 FERC ¶ 61,184 at P 64 n.101).

160.  Id.

161.  Id. P 284 (citing Harvard Electricity Law Comments, Docket No. RM19-15-000, at 24 (Dec. 3, 2019) (citing Vaclav Smil, Energy at the Crossroads: Global Perspectives and Uncertainties, Mass. Inst. Tech., 2003, at 121, 145-49)).

162.  Id.

163.  Id. P 285.

164.  Id. P 286 (citing Duke Comments, Docket No. RM19-15-000, at 6 (Dec. 3, 2019); Idaho Power Comments, Docket No. RM19-15-000, at 10-11 (Dec. 3, 2019); Portland General Comments, Docket No. RM19-15-000, at 5 (Dec. 3, 2019); NOPR, 168 FERC ¶ 61,184 at 64 n.101).

165.  Id. P 287 (citing Public Interest Organizations Comments, Docket No. RM19-15-000, at 47-50 (Dec. 3, 2019)).

166.  Id.

167.  Id. P 288 (citing Electricity Consumers Resource Council, American Chemistry Council, and American Forest and Paper Association (ELCON) Comments, Docket No. RM19-15-000, at 22 (Dec. 3, 2019); North Carolina Commission Staff Comments, Docket No. RM19-15-000, at 2-3 (Dec. 3, 2019); NIPPC, CREA, REC, and OSEIA Comments, Docket No. RM19-15-000, at 31 (Dec. 3, 2019); Public Interest Organizations Comments, Docket No. RM19-15-000, at 40, 43 (Dec. 3, 2019); Solar Energy Industries Comments, Docket No. RM19-15-000, at 36-38 (Dec. 3, 2019)).

168.  Id.

169.  Id. P 289 (citing Public Interest Organizations Comments, Docket No. RM19-15-000, at 40-41 (Dec. 3, 2019)).

170.  Id. The Commission stated that 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 Commission described prices for Mid-C as ranging 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. Id.

171.  Id.

172.  Id. PP 290-91.

173.  Id. P 291.

174.  Id. P 292 (citing SC Solar Alliance Comments, Docket No. RM19-15-000, at 7 (Dec. 3, 2019)).

175.  Id. (citing 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, Docket No. RM19-15-000 (Dec. 3, 2019))).

176.  Id. (citing Horii Test. 593:21-22).

177.  Id.

178.  Id. P 293.

179.  EPSA Request for Rehearing at 10.

180.  Public Interest Organizations Request for Rehearing at 9, 84.

181.  Solar Energy Industries Request for Rehearing and/or Clarification at 19.

182.  EPSA Request for Rehearing at 10.

183.  Public Interest Organizations Request for Rehearing at 84.

184.  Id. at 85.

185.  Id.

186.  Id. at 86.

187.  Id. at 86-87.

188.  Id. at 87.

189.  Id. at 87-90.

190.  Id. at 9, 90.

191.  Id. at 90.

192.  Id. at 91-92.

193.  EPSA Request for Rehearing at 14.

194.  Id. at 15 (citing 18 CFR 292.305(b)).

195.  Id. at 14-15.

196.  Solar Energy Industries Request for Rehearing and/or Clarification at 20.

197.  Id. at 21-23.

198.  Id. at 23.

199.  See, e.g., Motor Vehicle Mfrs. Assn. of United States, Inc. v. State Farm Mut. Automobile Ins. Co., 463 U.S. 29, 42 (1983) (“An agency changing its course by rescinding a rule is obligated to supply a reasoned analysis for the change”).

200.  FCC v. Fox Television Stations, Inc., 556 U.S. 502, 516 (2009).

201.  See Order No. 872, 172 FERC ¶ 61,041 at PP 285-92.

202.  See id. P 287 (footnote omitted) (“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. 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”).

203.  See, e.g., Public Interest Organizations Request for Rehearing at 85.

204.  See Order No. 872, 172 FERC ¶ 61,041 at P 290.

205.  Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,880.

206.  16 U.S.C. 824a-3; see also Indep. Energy Producers Ass'n, Inc. v. Cal. Pub. Utils. Comm'n, 36 F.3d 848, 850 (9th Cir. 1994) (“Section 210(b) requires that Commission to promulgate regulations that ensure that the rates for these purchases `shall be just and reasonable to the electric consumers of the electric utility and in the public interest.' However, these rates may not exceed the incremental cost to the utility of purchasing alternative energy.”); Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380, 384 (5th Cir. 2014) (“While Congress sought to promote energy generation by Qualifying Facilities, it did not intend to do so at the expensive of the American consumer. PURPA thus strikes a balance between these two interests . . . PURPA requires utilities to purchase power generated by Qualifying Facilities, but also mandates that the rates that utilities pay for such power `shall be just and reasonable to the electric consumers of the electric utility and in the public interest.' ”); Conn. Valley Elec. Co. v. FERC, 208 F.3d 1037, 1045 (D.C. Cir. 2000) (“PURPA expressly requires the Commission to balance the interests of consumers against those of producers. . . . ”); see also Swecker v. Midland Power Co-op, 807 F.3d 883, 884 (8th Cir. 2015) (citing legislative history that PURPA is “not intended to require the rate payers of a utility to subsidize cogenerators or small power producers”).

207.  EPSA Request for Rehearing at 15.

208.  See Public Interest Organizations Request for Rehearing at 87 (“FERC conflates short-run market prices with utilities' energy supply costs. . . . [T]he latter includes costs of supply other than the day ahead market and that impose costs above the market price”).

209.  Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,865; see also id. at 30,881-82 (also defining energy as “non-firm power” that entails “the cost of operating [the seller's] generating units and administration”).

210.  Id. at 30,865; see also id. at 30,881-82 (also defining capacity as “firm” power that entails “payments for the cost of fuel and operating expenses, and also for the fixed costs associated with the construction of generating units needed to provide power at the purchaser's discretion.”).

211.  See 18 CFR 292.304(e); see also Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,865 (“If a qualifying facility offers energy of sufficient reliability and with sufficient legally enforceable guarantees of deliverability to permit the purchasing electric utility to avoid the need to construct a generating unit, to build a smaller, less expensive plant, or to reduce firm power purchases from another utility, then the rates for such a purchase will be based on the avoided capacity and energy costs.”).

212.  As explained in the final rule, electric utilities almost always are required to pass decreases in energy costs through to their retail customers, whereas QFs with fixed energy contract rates are not obligated to reduce their rates as avoided energy costs decline. Order No. 872, 172 FERC ¶ 61,041 at P 122.

213.  Order No. 872, 172 FERC ¶ 61,041 at P 295.

214.  Id. P 296.

215.  Id.

216.  Id. P 302.

217.  Id. P 303.

218.  Solar Energy Industries Request for Rehearing and/or Clarification at 10.

219.  Id. at 10-11.

220.  Id. at 42.

221.  Id. at 43.

222.  Id. at 43-44.

223.  Northwest Coalition Request for Rehearing at 8 (citing Order No. 872, 172 FERC ¶ 61,041 at P 232).

224.  Id.

225.  Id. at 9-10 (citing Order No. 872, 172 FERC ¶ 61,041 (Glick, Comm'r, dissenting in part, at P 13)).

226.  Id. at 11.

227.  EPSA Request for Rehearing at 5.

228.  Id. at 6.

229.  Id.

230.  Id.

231.  Id.

232.  Id. at 6-7.

233.  Id. at 7-8.

234.  Id. at 8-9.

235.  Id. at 9-10.

236.  Id. at 16.

237.  Id. at 17.

238.  Public Interest Organizations Request for Rehearing at 9, 92.

239.  Id. at 92-93.

240.  Id. at 10, 92.

241.  Id. at 94-95.

242.  Id. at 94 (citing FTC v. Burton, 363 U.S. 536, 550 (1960); Burton v. District of Columbia, 153 F. Supp. 3d 13, 67 (D.D.C. 2015)).

243.  Id. (citing 16 U.S.C. 824a-3(b)).

244.  Id. at 10, 95.

245.  Id. at 95-96 & n.280 (citing National Association of Regulatory Utility Commissioners, Electric Utility Cost Allocation Manual, at 49-59 (July 1992)).

246.  Id. at 96-97.

247.  Id. at 96.

248.  Id. at 97 (citing FPC v. Sierra Pac. Power Co., 350 U.S. 348 (1956); United Gas Pipe Line Co. v. Mobile Gas Serv. Corp., 350 U.S. 332 (1956)).

249.  Id. at 97-98 (citing Town of Norwood v. FERC, 962 F.2d 20, 21, 24 (D.C. Cir. 1992)).

250.  Id. at 10, 98.

251.  Id. at 98-99.

252.  Northwest Coalition Request for Rehearing at 12.

253.  Id. at 13.

254.  Id. at 14 (citing Envtl. Action v. FERC, 939 F.2d 1057, 1061-62 (D.C. Cir. 1991) (Environmental Action)).

255.  Id. (citing Environmental Action, 939 F.2d at 1062).

256.  Id.

257.  Id. at 14-15.

258.  See supra PP 42-43.

259.  Order No. 872, 172 FERC ¶ 61,041 at PP 35-41, 336-45.

260.  Id. PP 85-88 (citing API, 461 U.S. at 414; Conf. Rep. at 97-98).

261.  Conf. Rep. at 97-98 (emphasis added).

262.  API, 461 U.S. at 414.

263.  We note that this situation of the variable energy avoided cost rate not changing significantly over time would also address rehearing arguments that the final rule impedes QF financeability.

264.  See Windham Solar, 157 FERC ¶ 61,134, at P 4 (2016) (“[S]ection 292.304(d)(2) of the Commission's regulations addresses the option to sell energy or capacity pursuant to a legally enforceable obligation over a specified term” and “provides (at the QF's option) for pricing based on either avoided costs calculated at the time of delivery or at the time the obligation is incurred.”).

265.  Solar Energy Industries Request for Rehearing and/or Clarification at 42.

266.  See 18 CFR 292.303(a)(1)-(2), (d) (QFs have right to sell to directly and indirectly interconnected utilities).

267.  See Northwest Coalition Request for Rehearing at 19; Public Interest Organizations Request for Rehearing at 44-46.

268.  16 U.S.C. 824a-3(b).

269.  See In re W. States Wholesale Nat. Gas Antitrust Litig., 715 F.3d 716, 731 (9th Cir. 2013) (Western States Wholesale Natural Gas Antitrust Litigation) (“[S]tatutory provisions should not be read in isolation, and the meaning of a statutory provision must be consistent with the structure of the statute of which it is a part.”), aff'd sub nom. Oneok, Inc. v. Learjet, Inc., 575 U.S. 373 (2015); Brazos Elec. Power Co-op. v. FERC, 205 F.3d 235, 250 (5th Cir. 2000) (Brazos) (“[I]f PURPA speaks clearly on the precise issue in question, that plain meaning must govern; however, if PURPA's application to a particular issue is ambiguous, FERC's interpretation will be upheld so long as it is a `permissible construction' of the statute.”).

270.  Northwest Coalition Request for Rehearing at 13-14 (citing Environmental Action, 939 F.2d at 1061-62).

271.  Environmental Action, 939 F.2d at 1061.

272.  Environmental Action, 939 F.2d at 1061-62.

273.  Public Interest Organizations Request for Rehearing at 94 & n.279 (“Under PURPA, Congress provided that discrimination is determined based on how the specific purchasing utility treats QFs compared to how it treats one or more similarly situated non-QFs, including the utility's own generation.”).

274.  See, e.g., Morgantown Energy Assocs. v. Pub. Serv. Comm'n of W. Virginia, No. 2:12-CV-6327, 2013 WL 5462386, at *25 (S.D. W. Va. Sept. 30, 2013) (discrimination under PURPA is measured “with respect to a similarly situated non-QF”); Pioneer Wind Park I, LLC, 145 FERC ¶ 61,215, at P 37 (2013) (curtailment of QFs compared to utility resources is discriminatory under PURPA); Entergy Servs. Inc. Gen. Coal. v. Entergy Servs., Inc., 103 FERC ¶ 61,125, at PP 27-29 (2003) (finding utility discriminated against QFs compared to other independent generators when it imposed certain fees on QFs but not on other generators)).

275.  See API, 461 at 413 (emphasis added) (“[T]he full-avoided-cost rule plainly satisfies the nondiscrimination requirement. . . . [W]e would be reluctant to infer that Congress intended the terms `just and reasonable,' which are frequently associated with cost-of-service utility ratemaking, . . . to adopt a cost-of-service approach in the very different context of cogeneration and small power production by nontraditional facilities. The legislative history confirms, moreover, that Congress did not intend to impose traditional ratemaking concepts on sales by qualifying facilities to utilities.”); Conf. Rep. at 97-98 (emphasis added) (“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.”).

276.  Order No. 872, 172 FERC ¶ 61,041 at P 38 (citing Town of Norwood, 962 F.2d at 21, 24).

277.  Town of Norwood, 962 F.2d at 21.

278.  16 U.S.C. 824a-3(b) (emphasis added) (“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.”); see also Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,866 (“If the Commission required electric utilities to base their rates for purchases from a qualifying facility on the high capital or capacity cost of a base load unit and, in addition, provided that the rate for the avoided energy should be based on the high energy cost associated with a peaking unit, the electric utilities' purchased power expenses would exceed the incremental cost of alternative electric energy, contrary to the limitation set forth in the last sentence of section 210(b).”).

279.  Cf. Western States Wholesale Natural Gas Antitrust Litigation, 715 F.3d at 731 (“[S]tatutory provisions should not be read in isolation, and the meaning of a statutory provision must be consistent with the structure of the statute of which it is a part.”); Brazos, 205 F.3d at 250 (“[I]f PURPA speaks clearly on the precise issue in question, that plain meaning must govern; however, if PURPA's application to a particular issue is ambiguous, FERC's interpretation will be upheld so long as it is a `permissible construction' of the statute.”).

280.  Order No. 872, 172 FERC ¶ 61,041 at P 335.

281.  Id. P 336.

282.  Id. at P 337.

283.  See id. P 338 (citing Solar Energy Industries Comments, Docket No. RM19-15-000, at 28 (Dec. 3, 2019); NIPPC, CREA, REC, and OSEIA Comments, Docket No. RM19-15-000, at 29, 46 (Dec. 3, 2019); Harvard Electricity Law Comments, Docket No. RM19-15-000, at 22, 25-27 (Dec. 3, 2019); Public Interest Organizations Comments, Docket No. RM19-15-000, at 6-7, 33-35 (Dec. 3, 2019)).

284.  Id. P 339.

285.  Id. P 340.

286.  Id. P 341 (citing 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.”). The Commission noted that, 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. Id. P 341 n.550.

287.  See id. P 342 (citing Harvard Electricity Law Comments, Docket No. RM19-15-000, at 26 (Dec. 3, 2019); Public Interest Organizations Comments, Docket No. RM19-15-000, at 33-34 (Dec. 3, 2019); Solar Energy Industries Comments, Docket No. RM19-15-000, at 30 (Dec. 3, 2019)).

288.  See id. (citing NIPPC, CREA, REC, and OSEIA Comments, Docket No. RM19-15-000, at 42-43 (Dec. 3, 2019)).

289.  See id. P 343.

290.  Id. P 344 (citing NIPPC, CREA, REC, and OSEIA Comments, Docket No. RM19-15-000, at 43 (Dec. 3, 2019)).

291.  See id. (citing Conf. Rep. at 97-98 (stating that the “risk in proceeding forward in the [QF] enterprise is not guaranteed to be recoverable”); 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”)).

292.  Id. P 345 (citing NIPPC, CREA, REC, and OSEIA Comments, Docket No. RM19-15-000, at 45-46 (Dec. 3, 2019); Resources for the Future Comments, Docket No. RM19-15-000, at 6-7 (Dec. 2, 2019); Solar Energy Industries Comments, Docket No. RM19-15-000, at 30 (Dec. 3, 2019)).

293.  Id. P 346 (citing Public Interest Organizations Comments, Docket No. RM19-15-000, at 33-34 (Dec. 3, 2019) (citing NOPR, 168 FERC ¶ 61,184 at P 70 n.114)).

294.  Id. P 347 (citing CARE Comments, Docket No. RM19-15-000, at 4 n.7 (Dec. 3, 2019); EPSA Comments, Docket No. RM19-15-000, at 12 (Dec. 3, 2019)).

295.  Id. (citing 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.”)).

296.  Id. P 349 (citing NOPR, 168 FERC ¶ 61,184 at 5 n.5; Idaho Commission Comments, Docket No. RM19-15-000, at 4 (Dec. 3, 2019) (allowing states to set variable QF energy avoided costs “would allow states to consider longer term contracts without putting ratepayers at risk”)).

297.  Id. The Commission did not find that variable avoided cost energy rates would be appropriate only if they cause states to require longer term contracts, and the Commission did not adopt the suggestion made by certain commenters that the Commission order states to require longer contract terms. See id. P 349 n.566 (citing NIPPC, CREA, REC, and OSEIA Comments, Docket No. RM19-15-000, at 47-48 (Dec. 3, 2019); Public Interest Organizations Comments, Docket No. RM19-15-000, at 6-7 (Dec. 3, 2019); sPower Comments, Docket No. RM19-15-000, at 11 (Dec. 3, 2019)).

298.  Id. P 349.

299.  Public Interest Organizations Request for Rehearing at 9, 72.

300.  Id. at 73-74.

301.  Id. at 74-75.

302.  Id. at 75-76.

303.  Id. at 76-78.

304.  Id. at 78.

305.  Id. at 78-79.

306.  Id. at 9, 78-79.

307.  Id. at 79-82.

308.  Id. at 82-83.

309.  Id. at 83 (citing Harvard Electricity Law Comments, Docket No. RM19-15-000, at 17-19 (Dec. 3, 2019)).

310.  Id. (citing Harvard Electricity Law Comments, Docket No. RM19-15-000, at 17-19 (Dec. 3, 2019)).

311.  Solar Energy Industries Request for Rehearing and/or Clarification at 9, 12.

312.  Id. at 9.

313.  Id. at 10.

314.  Id. at 12.

315.  Id. at 12-13.

316.  Id. at 14.

317.  Id. at 14-15 (citing Power Plants are Not Built on Spec, 2014 Update, American Public Power Association (Oct. 2014), https://hepg.hks.harvard.edu/​files/​hepg/​files/​94_​2014_​power_​plant_​study.pdf?​m=​1523366757).

318.  Id. at 16.

319.  Id.

320.  Id. at 16-17.

321.  Id. at 18.

322.  Northwest Coalition Request for Rehearing at 4-5.

323.  Id. at 5 (citing Transmission Access Pol'y Grp. v. FERC, 225 F.3d 667, 688 (D.C. Cir. 2000)).

324.  Id. (citing PPL Wallingford Energy LLC v. FERC, 419 F.3d 1194, 1198 (D.C. Cir. 2005) (PPL Wallingford); Ne. Md. Waste Disposal Auth. v. EPA, 358 F.3d 936, 949 (D.C. Cir. 2004)).

325.  Id. at 16-17.

326.  Conf. Rep. at 97-98 (emphasis added).

327.  See Order No. 872, 172 FERC ¶ 61,041 at PP 30-31, 35-41, 336-345.

328.  Finadvice Comments, Docket No. RM19-15-000, at 2 (Dec. 3, 2019); see also Ohio Commission Energy Advocate Comments, Docket No. RM19-15-000, at 3-4 (Dec. 3, 2019 (“[O]rganized wholesale markets such as PJM have successfully attracted new supplies and ensured resource adequacy through a combination of fixed capacity rates and variable energy rates such as the Commission is proposing here. Fixing both the energy and the capacity components of the QF power sales contract is not necessary to attract new resources or to appropriately compensate qualifying facilities.”).

329.  See Order No. 872, 172 FERC ¶ 61,041 at P 340.

330.  Cf. Environmental Action, 939 F.2d at 1064 (“[I]t is within the scope of the agency's expertise to make such a prediction about the market it regulates, and a reasonable prediction deserves our deference notwithstanding that there might also be another reasonable view.”).

331.  See Order No. 872, 172 FERC ¶ 61,041 at P 345 (footnote omitted) (“[T]he 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. 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.”).

332.  Public Interest Organizations Request for Rehearing at 73-74.

333.  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.

334.  Solar Energy Industries Request for Rehearing and/or Clarification at 11.

335.  See 18 CFR 292.302.

336.  See Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,868 (“[I]n order to be able to evaluate the financial feasibility of a cogeneration or small power production facility, an investor needs to be able to estimate, with reasonable certainty, the expected return on a potential investment before construction of a facility. This return will be determined in part by the price at which the qualifying facility can sell its electric output. Under 292.304 of these rules, the rate at which a utility must purchase that output is based on the utility's avoided costs, taking into account the factors set forth in paragraph (e) of that section. Section 292.302 of these rules is intended by the Commission to assist those needing data from which avoided costs can be derived.”).

337.  While we do not require this here, states may choose to require that rates are on file.

338.  See FERC v. Miss., 456 U.S. at 751 (“[A] state commission may comply with the statutory requirements [of PURPA section 210] by issuing regulations, by resolving disputes on a case-by-case basis, or by taking any other action reasonably designed to give effect to FERC's rules.”).

339.  See 18 CFR 292.304(c).

340.  NOPR, 168 FERC ¶ 61,184 at P 82.

341.  Regulations Governing Bidding Programs, 53 FR 9324 (Mar.22, 1988), 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, 53 FR 9331 (Mar.22, 1988), FERC Stats. & Regs. ¶ 32,457 (1988) (cross-referenced at 42 FERC ¶ 61,324) (ADFAC NOPR).

342.  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).

343.  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).

344.  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).

345.  NOPR, 168 FERC ¶ 61,184 at P 86.

346.  Id. P 87 (citing Allocation of Capacity on New Merchant Transmission Projects and New Cost-Based, Participant-Funded Transmission Projects, 142 FERC ¶ 61,038 (2013)).

347.  Id. (citing Hydrodynamics, 146 FERC ¶ 61,193 at P 32 n.70 (citing Bidding NOPR, FERC Stats. & Regs. ¶ 32,455 at 32,030-42)). The Commission noted 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. Id. P 87 n.135 (citing Hydrodynamics, 146 FERC ¶ 61,193 at P 35 (referencing 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.”))).

348.  Id.

349.  Id. (citing 18 CFR 292.304(e); Windham Solar, 157 FERC ¶ 61,134 at PP 5-6).

350.  Id.

351.  Id. P 88. 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. Id. P 88 n.137.

352.  Order No. 872, 172 FERC ¶ 61,041 at P 411.

353.  Id. P 412.

354.  Id. P 427.

355.  Id. P 414.

356.  Id. P 428.

357.  Id. P 416.

358.  Id. P 421.

359.  The Commission stated that 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.”).

360.  Order No. 872, 172 FERC ¶ 61,041 at P 422.

361.  Id. P 423.

362.  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.”).

363.  See Xcel Comments, Docket No. RM19-15-000, at 2-3, 9-10 (Dec. 3, 2019).

364.  Order No. 872, 172 FERC ¶ 61,041 at P 424.

365.  Allegheny Energy, 108 FERC ¶ 61,082 at P 18.

366.  Order No. 872, 172 FERC ¶ 61,041 at P 431.

367.  Id. P 432.

368.  Id. P 435.

369.  Id. P 437.

370.  See 18 CFR 292.304(c).

371.  Northwest Coalition Request for Rehearing at 39.

372.  Id. at 40 (citing 16 U.S.C. 824a-3(a)(2)).

373.  Id.

374.  Id. at 40-41.

375.  Id. at 41.

376.  Id. at 41-42 (citing Winding Creek Solar LLC v. Peterman, 932 F.3d at 865).

377.  Id. at 42.

378.  Id.

379.  Id.

380.  Id. at 43 (citing Hydrodynamics, 146 FERC ¶ 61,193 at P 33).

381.  Id. (citing Windham Solar, 156 FERC ¶ 61,042, at P 5 (2016) (Windham Solar)).

382.  Id. (citing Windham Solar, 156 FERC ¶ 61,042 at P 5).

383.  Id. at 43-44.

384.  Id. at 44.

385.  Id.

386.  Id. (citing NIPPC, CREA, REC, and OSEIA Comments, Docket No. RM19-15-000, at 13-25, 66-67 (Dec. 3, 2019)).

387.  Id. at 44-45.

388.  Id. at 45.

389.  Id. at 46.

390.  Id.

391.  Id.

392.  Id. (citing Order No. 872, 172 FERC ¶ 61,041 at P 440).

393.  Id. at 46-47.

394.  Mr. Mattson Motion for Time, Reconsideration, and Request Answers at 1.

395.  Id. at 1.

396.  Id. at 1.

397.  Public Interest Organizations Rehearing Request at 10.

398.  Id. at 100.

399.  Id.

400.  Id.

401.  Id. at 101.

402.  In Hydrodynamics, which the Commission quoted in Windham Solar, the Commission found relevant the fact that the Montana Commission's competitive solicitation were not held at regular intervals. See Hydrodynamics, 146 FERC ¶ 61,193 at P 32 (emphasis added) (“[W]e find 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 particularly where, as here, such competitive solicitations are not regularly held.”); id. P 33 (emphasis added) (“The Montana Rule creates, as well, a practical disincentive to amicable contract formation because a utility may refuse to negotiate with a QF at all, and yet the Montana Rule precludes any eventual contract formation where no competitive solicitation is held.”); Windham Solar, 156 FERC ¶ 61,042 at P 5 (citing Hydrodynamics, 146 FERC ¶ 61,193 at PP 32-33).

403.  See Order No. 872, 172 FERC ¶ 61,041 at PP 421-23.

404.  See City of Ketchikan, 94 FERC at 62,061.

405.  See supra PP 194-196; see also Order No. 872, 172 FERC ¶ 61,041 at P 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.”).

406.  See Order No. 872, 172 FERC ¶ 61,041 at P 363 (describing NOPR as citing Hydrodynamics, 146 FERC ¶ 61,193 at PP 31-35).

407.  See id. P 416.

408.  Northwest Coalition Request for Rehearing at 45 (citing NIPPC, CREA, REC, OSEIA Comments, Docket No. RM19-15-000 at 67 (Dec. 3, 2019)).

409.  Order No. 872, 172 FERC ¶ 61,041 at P 435.

410.  Id.

411.  See Allegheny Energy, 108 FERC ¶ 61,082 at P 22 (“[A]n independent third party should design the solicitation, administer bidding, and evaluate bids prior to the company's selection.”).

412.  See Order No. 872, 172 FERC ¶ 61,041 at P 432 (stating that a report must “(1) [identify] the winning bidders; (2) [include] a copy of any reports issued by the independent evaluator; and (3) [demonstrate] that the solicitation program was implemented without undue preference for the interests of the purchasing utility or its affiliates”).

413.  See id. P 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.”).

414.  See id. P 430.

415.  See id. P 422.

416.  Mr. Mattson Motion for Time, Reconsideration, and Request Answers at 1.

417.  See 18 CFR 292.301(b)(1).

418.  See 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.”)).

419.  Public Interest Organizations Comments at 99-101.

420.  See new 18 CFR 292.304(c)(8)(iii) (emphasis added); see also Order No. 872, 172 FERC ¶ 61,041 at P 422 (“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.”).

421.  Order No. 872, 172 FERC ¶ 61,041 at P 466.

422.  Id. P 467.

423.  Id. P 468.

424.  Id. P 472.

425.  Public Interest Organizations Request for Rehearing at 128 (citing Order No. 872, 172 FERC ¶ 61,041 at P 471).

426.  Id. at 128.

427.  Solar Energy Industries Request for Rehearing and/or Clarification at 5, 26.

428.  Id. at 26.

429.  Public Interest Organizations Request for Rehearing at 121.

430.  Id. at 122.

431.  Solar Energy Industries Request for Rehearing and/or Clarification at 26.

432.  Order No. 872, 172 FERC ¶ 61,041 at P 470 (citing APPA Comments, Docket No. RM19-15-000, at 21 (Dec. 3, 2019); Center for Growth and Opportunity Comments, Docket No. RM19-15-000, at 5-6 (Dec. 3, 2019); Consumers Energy Comments, Docket No. RM19-15-000, at 4 (Dec. 3, 2019); East River Comments, Docket No. RM19-15-000, at 1-2; EEI Comments, Docket No. RM19-15-000, at 43 (Dec. 3, 2019); ELCON Comments, Docket No. RM19-15-000, at 35 (Dec. 3, 2019); Governor Brad Little, Idaho Comments, Docket No. RM19-15-000, at 1 (Dec. 3, 2019); Idaho Commission Comments, Docket No. RM19-15-000, at 5-7 (Dec. 3, 2019); Idaho Power Comments, Docket No. RM19-15-000, at 13 (Dec. 3, 2019); Missouri River Energy Comments, Docket No. RM19-15-000, at 5 (Dec. 3, 2019); Stephen Moore Comments, Docket No. RM19-15-000, at 2 (Dec. 3, 2019); Northern Laramie Range Alliance Comments, Docket No. RM19-15-000, at 2 (Dec. 3, 2019); NorthWestern Comments, Docket No. RM19-15-000, at 9 (Dec. 3, 2019); NRECA Comments, Docket No. RM19-15-000, at 14-15 (Dec. 3, 2019); Portland General Comments, Docket No. RM19-15-000, at 14 (Dec. 3, 2019)).

433.  Idaho Commission Comments, Docket No. AD16-16-000, at 8-9 (Nov. 7, 2016); see also Technical Conference Tr. at 34-35 (Commissioner Paul Kjellander, Idaho Commission).

434.  Idaho Commission Comments, Docket No. AD16-16-000, at 9-11 (Nov. 7, 2016).

435.  Technical Conference Tr. at 35-36 (Commissioner Paul Kjellander, Idaho Commission).

436.  EEI Comments, Docket No. RM19-15-000, at 43 (Dec. 3, 2019) (citing N. Laramie Range All., 138 FERC ¶ 61,171 (2012)); Xcel Comments, Docket No. AD16-16-000, at 11 (Nov. 7, 2016); see also EEI Comments, Docket No. RM19-15-000, at 43 (Dec. 3, 2019) (citing Beaver Creek II, 160 FERC ¶ 61,052 (2017)); Xcel Comments, Docket No. AD16-16-000, at 11 (Nov. 7, 2016) (citing DeWind Novus, LLC, 139 FERC ¶ 61,201 (2012)).

437.  Order No. 872, 172 FERC ¶ 61,041 at P 491.

438.  Id.

439.  See id. P 466, 491.

440.  16 U.S.C. 824a-3(a).

441.  16 U.S.C. 796(17)(A).

442.  Order No. 872, 172 FERC ¶ 61,041 at P 490.

443.  Id. P 491.

444.  Id.

445.  Id. P 492 n.769 (quoting 18 CFR 292.204(a)(2)(i)).

446.  Id. (citing 18 CFR 292.204(a)(3)).

447.  Id. P 492 (citing 18 CFR 292.204(a)(3)).

448.  Public Interest Organizations Request for Rehearing at 106.

449.  Id. at 124 (citing Solar Energy Industries Comments, Docket No. RM19-15-000, at 62 (Dec. 3, 2019); North Carolina DOJ Comments, Docket No. RM19-15-000, at 3-4 (Dec. 3, 2019); SC Solar Alliance Comments, Docket No. RM19-15-000, at 17 (Dec. 3, 2019); North Carolina Commission Staff Comments, Docket No. RM19-15-000, at 6 (Dec. 3, 2019); Borrego Solar Comments, Docket No. RM19-15-000, at 3-5 (Dec. 3, 2019)).

450.  Id. (citing Motor Vehicles Mfrs. Ass'n v. State Farm Mut. Auto. Inst. Col, 463 U.S. at 43).

451.  Id. at 125.

452.  Solar Energy Industries Request for Rehearing and/or Clarification at 29.

453.  Public Interest Organizations Request for Rehearing at 120.

454.  Id. at 106-07.

455.  Id. at 132.

456.  Id. at 107.

457.  Id. at 107-08 & n.312.

458.  Id. at 108 n.312.

459.  Id. at 107-09 & n.312.

460.  Id. at 108-09 n.312 (citing Order No. 872, 172 FERC ¶ 61,041 at P 492 n.769).

461.  Id.

462.  Northwest Coalition Request for Rehearing at 54 (citing Order No. 872, 172 FERC ¶ 61,041 at P 483); Public Interest Organizations Request for Rehearing at 109; Solar Energy Industries Request for Rehearing and/or Clarification at 27, 29.

463.  Public Interest Organizations Request for Rehearing at 109-10.

464.  16 U.S.C. 796(17)(A)(ii).

465.  Order No. 872, 172 FERC ¶ 61,041 at P 491. See also id. P 466.

466.  Id. P 491. See also id. P 466.

467.  16 U.S.C. 796(17)(A)(ii).

468.  Public Interest Organizations state that “[t]here is nothing in the record to show that [10] miles is a rational or appropriate threshold for determining whether QFs are at the `same site.' ” We correct Public Interest Organizations' statement by noting that affiliated small power production facilities 10 miles or more apart are irrebuttably presumed to be at separate sites and facilities between one mile and 10 miles are rebuttably presumed to also be separate sites. Order No. 872, 172 FERC ¶ 61,041 at P 466.

469.  Id. P 491.

470.  See CP Kelco Oy v. United States, 37 ITRD 1093 (Ct. Int'l Trade 2015) (“[T]his threshold is a line in the sand: Commerce might have picked a different number to effectuate the statute's purpose, with reasonable results . . . Yet because the agency's choice does not run afoul of the statute and is not arbitrary, the court will defer to Commerce despite the possibility of alternatives.”). See also U.S. Steel Grp. v. United States, 96 F.3d 1352, 1362 (Fed. Cir. 1996) (“So long as the Commission's analysis does not violate any statute and is not otherwise arbitrary and capricious, the Commission may perform its duties in the way it believes most suitable.”); Mid Continent Nail Corp. v. United States, 34 C.I.T. 512, 520-21 (2010) (finding, in response to contentions that the Commission's definitions of statutory terms were “seemingly random values,” that the numbers in the Commission's definitions did not violate the statute and were not otherwise arbitrary and capricious where the they are applied reasonably). Cf. Int'l Soc. for Krishna Consciousness, Inc. v. McAvey, 450 F. Supp. 1265, 1269 (S.D.N.Y. 1978) (“choosing any fixed number would seem arbitrary, yet necessary in order to strike a balance between the competing interests.”); AFPA v. FERC, 550 F.3d at 1183 (permitting Commission to establish rebuttable presumption via rulemaking rather than case-by-case adjudication in PURPA section 210(m) context).

471.  Order No. 872, 172 FERC ¶ 61,041 at P 491.

472.  Id. P 492 (citing 18 CFR 292.204(a)(3)).

473.  Windfarms, Ltd., 13 FERC ¶ 61,017 (1980).

474.  Pinellas County, Florida, 50 FERC ¶ 61,269 (1990).

475.  See El Dorado Cty. Water Agency, 24 FERC ¶ 61,280, at 61,577 (1983) (El Dorado) (“Under the rule, hydroelectric facilities using the same impoundment as a water source and located within one mile of each other are considered part of the same site.”); Small Power Production and Cogeneration Facilities—Qualifying Status, Order No. 70, 45 FR 17995 (Mar. 20, 1980), FERC Stats. & Regs. ¶ 30,134, at 30,943 (1980) (cross-referenced at 10 FERC ¶ 61,230) (“Hydroelectric facilities . . . are considered to be located at the same site only if the facilities use water from the same impoundment for power generation. The Commission views this additional provision for hydroelectric facilities as necessary because use of the one-mile rule alone might discourage the development of facilities on separate waterways which are within one mile of each other.”) (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) (emphasis added).

476.  See Order No. 872, 172 FERC ¶ 61,041 at P 495.

477.  Id.

478.  Id. P 508.

479.  Id. P 509.

480.  Id. P 510.

481.  Id. P 511.

482.  Solar Energy Industries Request for Rehearing and/or Clarification at 30.

483.  Id. at 26, 31-32 (citing El Dorado, 24 FERC at 61,578).

484.  Id. at 31.

485.  Id. at 30-31.

486.  Public Interest Organizations Request for Rehearing at 103 (citing MCI Telecommunications Corp. v. Am. Tel. & Tel. Co., 512 U.S. 218, 229 (1994)).

487.  Id. (citing The American Heritage Dictionary of the English Language 55 (3d ed. 1992)).

488.  Id. at 103-04.

489.  Id. at 105.

490.  Id. at 104 (citing Summit Petroleum Corp. v. U.S. EPA, 690 F.3d 733, 742 (6th Cir. 2012)).

491.  Solar Energy Industries Request for Rehearing and/or Clarification at 31.

492.  Id.

493.  Id.

494.  Public Interest Organizations Request for Rehearing at 111.

495.  Id. at 124-25 (citing Order No. 872, 172 FERC ¶ 61,041 at PP 501-09).

496.  Id. at 126 (citing Southeast Public Interest Organizations Comments, Docket No. RM19-15-000, at 34 (Dec. 3, 2019); SC Solar Alliance Comments, Docket No. RM19-15-000, at 17 (Dec. 3, 2019)).

497.  Id. (citing Southeast Public Interest Organizations Comments, Docket No. RM19-15-000, at 34 (Dec. 3, 2019); SC Solar Alliance Comments, Docket No. RM19-15-000, at 17-18 (Dec. 3, 2019)).

498.  Id. (citing Southeast Public Interest Organizations Comments, Docket No. RM19-15-000, at 35 (Dec. 3, 2019); SC Solar Alliance Comments, Docket No. RM19-15-000, at 18 (Dec. 3, 2019); North Carolina DOJ Comments, Docket No. RM19-15-000, at 7-8 (Dec. 3, 2019)).

499.  Id. at 127 (citing Southeast Public Interest Organizations Comments, Docket No. RM19-15-000, at 35 (Dec. 3, 2019)).

500.  Id.

501.  Id.

502.  Solar Energy Industries Request for Rehearing and/or Clarification at 26.

503.  Id. at 27, 30 (citing Windfarms, Ltd., 13 FERC at 61,032).

504.  Id. at 27.

505.  Id. at 34.

506.  Public Interest Organizations Request for Rehearing at 110 (citing Order No. 872, 172 FERC ¶ 61,041 at PP 480, 510).

507.  16 U.S.C. 796(17)(A)(ii).

508.  Id.

509.  Order No. 70, FERC Stats. & Regs. ¶ 30,134 at 30,939; see also 18 CFR 292.204(a)(1).

510.  El Dorado, 24 FERC at 61,577-78.

511.  Order No. 872, 172 FERC ¶ 61,041 at P 554.

512.  Id. P 550.

513.  Id. P 469.

514.  Public Interest Organizations Request for Rehearing at 126 (citing Southeast Public Interest Organizations Comments, Docket No. RM19-15-000, at 34 (Dec. 3, 2019); SC Solar Alliance Comments, Docket No. RM19-15-000, at 17 (Dec. 3, 2019)). See also Order No. 872, 172 FERC ¶ 61,041 at P 501.

515.  Public Interest Organizations Request for Rehearing at 127 (citing Southeast Public Interest Organizations Comments, Docket No. RM19-15-000, at 35 (Dec. 3, 2019)).

516.  Order No. 872, 172 FERC ¶ 61,041 at P 511.

517.  Southeast Public Interest Organizations Comments, Docket No. RM19-15-000, at 35 (Dec. 3, 2019).

518.  Order No. 872, 172 FERC ¶ 61,041 at P 509.

519.  See id.

520.  Id. P 547.

521.  Id. P 548.

522.  Id. P 550.

523.  Id. P 552.

524.  Id. P 553.

525.  Id. P 554.

526.  Id. P 556.

527.  Id. P 560.

528.  Id. P 563.

529.  Id. P 565.

530.  Id. P 567.

531.  Solar Energy Industries Request for Rehearing and/or Clarification at 33 (citing 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 8 (2010)).

532.  Id. at 28 (citing Revised Regulations Governing Small Power Production and Cogeneration Facilities, Order No. 671, 114 FERC ¶ 61,102, at P 83, order on reh'g, Order No. 671-A, 115 FERC ¶ 61,225 (2006)).

533.  Id. at 34.

534.  Public Interest Organizations Request for Rehearing at 116.

535.  Id.

536.  Id. (citing Order No. 872, 172 FERC ¶ 61,041 at PP 485, 539-42, 577-83).

537.  Id. at 127-29.

538.  Id. at 117 (citing Order No. 872, 172 FERC ¶ 61,041 at P 587).

539.  Id. at 129 (citing Solar Energy Industries Comments, Docket No. RM19-15-000, at 52 (Dec. 3, 2019)).

540.  Id. at 122.

541.  Id. at 122-23; Solar Energy Industries Request for Rehearing and/or Clarification at 28.

542.  Public Interest Organizations Request for Rehearing at 123.

543.  We note that the current filing fee for a petition for declaratory order is $30,060.

544.  Solar Energy Industries Request for Rehearing and/or Clarification at 28.

545.  Public Interest Organizations Request for Rehearing at 106.

546.  Id. at 107, 112.

547.  Solar Energy Industries Request for Rehearing and/or Clarification at 33.

548.  Id.

549.  Id. at 26.

550.  Northwest Coalition Request for Rehearing at 6.

551.  Id. at 53.

552.  Id. at 53-55; see also Public Interest Organizations Request for Rehearing at 132.

553.  Northwest Coalition Request for Rehearing at 55.

554.  Id. at 55.

555.  Id. at 55.

556.  Public Interest Organizations Request for Rehearing at 115.

557.  Id.

558.  Northwest Coalition Request for Rehearing at 53; Public Interest Organizations Request for Rehearing at 132.

559.  Public Interest Organizations Request for Rehearing at 133 (citing FCC v. Fox Television Stations, Inc., 556 U.S. 502, 515 (2009)).

560.  Id. at 115.

561.  Id.

562.  Northwest Coalition Request for Rehearing at 55 (citing Bowen v. Georgetown Univ. Hosp., 488 U.S. 204, 208-09 (1988)).

563.  Id.

564.  Id. at 55-56 (citing 18 CFR 292.205(d)).

565.  Id. at 56 (citing Order No. 671, 114 FERC ¶ 61,102 at P 115).

566.  Id. (citing Order No. 671, 114 FERC ¶ 61,102 at P 115).

567.  Id. (citing NIPPC, CREA, REC, and OSEIA Comments, Docket No. RM19-15-000, at 76 (Dec. 3, 2019)).

568.  Id. (citing PPL Wallingford, 419 F.3d at 1198).

569.  Public Interest Organizations Request for Rehearing at 130 (citing Southeast Public Interest Organizations Comments, Docket No. RM19-15-000, at 29-33 (Dec. 3, 2019); SC Solar Alliance Comments, Docket No. RM19-15-000, at 18 (Dec. 3, 2019); North Carolina DOJ Comments, Docket No. RM19-15-000, at 8 (Dec. 3, 2019)).

570.  Id. at 130-31 (citing Southeast Public Interest Organizations Comments, Docket No. RM19-15-000, at 31 (Dec. 3, 2019)).

571.  Id. at 131.

572.  Id. at 131-32.

573.  Solar Energy Industries Request for Rehearing and/or Clarification at 34.

574.  Id. at 35.

575.  Id.

576.  Id.

577.  Id. (citing Zond-PanAero Windsystem Partners I, 76 FERC ¶ 61,137 (1996)).

578.  Id. at 36.

579.  Solar Energy Industries Comments, Docket No. RM19-15-000, at 51 (Dec. 3, 2019).

580.  See Order No. 872, 172 FERC ¶ 61,041 at P 560.

581.  Public Interest Organizations Request for Rehearing at 127-29; see Solar Energy Industries Request for Rehearing and/or Clarification at 34.

582.  18 CFR 292.207(d), which the final rule renumbered to 18 CFR 292.207(f).

583.  Item 8a of the Form No. 556 effective prior to the final rule required an applicant to “[i]dentify any facilities with electrical generating equipment located within 1 mile of the electrical generating equipment of the instant facility . . .” Section 292.207(d) of the Commission's regulations, which the final rule renumbered to 18 CFR 292.207(f), 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. While the requirement, prior to the final rule, that a small power production QF update its Form No. 556 with the updated information of its affiliated small power production facilities one mile or less away, is not explicit, we believe that this requirement is the logical result of the intersection of the above.

584.  See supra note 583.

585.  See supra note 583.

586.  If a small power production QF that was certified prior to the effective date of this final rule is required to recertify due to a material change to its own facility, then at that time it will be required to identify affiliates less than 10 miles from the applicant facility.

587.  We note that we are maintaining the final rule's alternative option for rooftop solar PV developers to file their recertification applications. See Order No. 872, 172 FERC ¶ 61,041 at P 560.

588.  Id. P 495.

589.  Id. P 550.

590.  Public Interest Organizations Request for Rehearing at 130 (citing Southeast Public Interest Organizations Comments, Docket No. RM19-15-000, at 29-33 (Dec. 3, 2019); SC Solar Alliance Comments, Docket No. RM19-15-000, at 18 (Dec. 3, 2019); North Carolina DOJ Comments, Docket No. RM19-15-000, at 8 (Dec. 3, 2019)).

591.  Id. at 107, 112.

592.  Order No. 872, 172 FERC ¶ 61,041 at P 533 & n.877.

593.  Id. P 286 n.797.

594.  See id. P 553.

595.  See 16 U.S.C. 824a-3(a).

596.  Order No. 872, 172 FERC ¶ 61,041 at P 511.

597.  16 U.S.C. 796(17)(A).

598.  The Commission notes that if the Commission issues an order in response to a self-certification that is protested, or in response to an application for Commission certification, the order issued by the Commission will continue to be a declaratory order which determines whether or not a project, as described by the applicant and protester, meets the technical and ownership standards for QFs, and serves only to establish eligibility for benefits of PURPA.

599.  Order No. 872, 172 FERC ¶ 61,041 at P 554.

600.  Id. P 527.

601.  Id. P 514.

602.  Id. P 550.

603.  Furthermore, no commenter has explained how and why applying the new rules to new recertifications make them retroactive rules.

604.  Northwest Coalition Request for Rehearing at 55.

605.  16 U.S.C. 824a-3(n).

606.  See Order No. 872, 172 FERC ¶ 61,041 at P 584.

607.  18 CFR 292.207(d), which the final rule renumbered to 292.207(f).

608.  Order No. 872, 172 FERC ¶ 61,041 at P 586.

609.  See Order No. 872, 172 FERC ¶ 61,041 at P 587.

610.  Public Interest Organizations Request for Rehearing at 117 (citing Order No. 872, 172 FERC ¶ 61,041 at P 587).

611.  See Order No. 872, 172 FERC ¶ 61,041 at P 587. The majority of QFs choose the less burdensome option to self-certify pursuant to 18 CFR 292.207(a), by filing a Form No. 556. An application for Commission certification pursuant to 18 CFR 292.207(b) also requires filing the Form No. 556, but applicants for Commission certification typically additionally prepare a written petition arguing why the Commission should grant QF status.

612.  Commission Information Collection Activities (FERC-556); Comment Request; Extension, Docket No. IC19-16-000, at 5 (issued May 15, 2019).

613.  Order No. 688, 117 FERC ¶ 61,078 at P 72; Order No. 688-A, 119 FERC ¶ 61,305 at PP 94-96; N. States Power Co., 151 FERC ¶ 61,110, at PP 31-36 (2015); PPL Elec. Utilities Corp., 145 FERC ¶ 61,053, at PP 21-24 (2013).

614.  Order No. 688, 117 FERC ¶ 61,078 at PP 74, 76; Order No. 688-A, 119 FERC ¶ 61,305 at P 103.

615.  Order No. 872, 172 FERC ¶ 61,041 at P 629.

616.  Id. P 624.

617.  Id. (citing 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)).

618.  Id. PP 626-29 (citing 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.”)).

619.  Order No. 872, 172 FERC ¶ 61,041 at P 627 (citing 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.”)).

620.  Id. PP 628-29 (citing Order No. 688, 117 FERC ¶ 61,078 at P 76; Order No. 688-A, 119 FERC ¶ 61,305 at PP 96-97).

621.  Id. P 629.

622.  Id. P 630 (citing Small Generator Interconnection Agreements and Procedures, Order No. 792, 78 FR 73240 (Dec. 5, 2013), 145 FERC ¶ 61,159, at P 103 (2013), clarifying, Order No. 792-A, 146 FERC ¶ 61,214 (2014)).

623.  Id. P 631.

624.  Id. P 632 (citing Elec. Storage Participation in Mkts. Operated by Reg'l Transmission Orgs. and Indep. Sys. Operators, 83 FR 9580 (Mar. 6, 2018), Order No. 841, 162 FERC ¶ 61,127, at P 265 (2018)).

625.  Id. P 633 (citing Elec. Participation in Mkts Operated by Reg'l Transmission Orgs and Indep. Sys. Operators, 157 FERC ¶ 61,121, at P 129 (2016) (footnote omitted) (“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.”)).

626.  Id. P 634 (referencing Allco Comments, Docket No. RM19-15-000, at 17-19 (Dec. 3, 2019); Advanced Energy Economy Comments, Docket No. RM19-15-000, at 10-11 (Dec. 3, 2019); DC Commission Comments, Docket No. RM19-15-000, at 5 (Dec. 3, 2019); Public Interest Organizations Comments, Docket No. RM19-15-000, at 89-90 (Dec. 3, 2019); Solar Energy Industries Comments, Docket No. RM19-15-000, at 45-49 (Dec. 3, 2019)).

627.  Order No. 688-A, 119 FERC ¶ 61,305 at P 97.

628.  Order No. 872, 172 FERC ¶ 61,041 at P 635.

629.  Id. P 636.

630.  Id. P 639 (referencing Advanced Energy Economy Comments, Docket No. RM19-15-000, at 6 (Dec. 3, 2019) (citing FCC v. Fox Television, 556 U.S. at 515)).

631.  FCC v. Fox Television, 556 U.S. at 515.

632.  Order No. 872, 172 FERC ¶ 61,041 at P 638.

633.  Id. P 640.

634.  Id. P 641.

635.  Id. P 642.

636.  Id.

637.  Id. P 643.

638.  Id. P 644.

639.  Public Interest Organizations Request for Rehearing and Clarification at 136-37 (citing 5 U.S.C. 556(d); Nat'l Min. Ass'n v. Babbitt, 172 F.3d 906, 910 (D.C. Cir. 1999); United Scenic Artists v. NLRB, 762 F.2d 1027, 1034 (D.C. Cir. 1985)); Northwest Coalition Request for Rehearing at 47-48; Solar Energy Industries Request for Rehearing and/or Clarification at 38-41.

640.  Public Interest Organizations Request for Rehearing at 136 (citing 16 U.S.C. 824a-3(m)(3)).

641.  Solar Energy Industries Request for Rehearing and/or Clarification at 38-39; Public Interest Organizations Request for Rehearing and Clarification at 40.

642.  Public Interest Organizations Request for Rehearing at 138-140.

643.  Id. at 138-39.

644.  Id. at 140.

645.  Id. at 139; Northwest Coalition Request for Rehearing at 49-50.

646.  Northwest Coalition Request for Rehearing at 50; Public Interest Organizations Request for Rehearing at 137-140.

647.  Northwest Coalition Request for Rehearing at 49; Public Interest Organizations Request for Rehearing at 139.

648.  Northwest Coalition Request for Rehearing at 51-52; Public Interest Organizations Request for Rehearing at 140.

649.  Northwest Coalition Request for Rehearing at 52-53.

650.  One Energy Request for Rehearing and Clarification at 5-7.

651.  Id. at 7.

652.  Id. at 8-9.

653.  Public Interest Organizations Request for Rehearing at 143-44.

654.  Order No. 872, 172 FERC ¶ 61,041 at PP 629-633.

655.  Id. P 632 (citing Order No. 841, 162 FERC ¶ 61,127 at P 265).

656.  Id. PP 630-31.

657.  Id. P 632.

658.  Order No. 841, 162 FERC ¶ 61,127 at P 272.

659.  See Participation of Distributed Energy Resource Aggregations in Markets Operated by Regional Transmission Organizations and Independent System Operators, Order No. 2222, 172 FERC ¶ 61,247 (2020). While Order No. 2222 will not become effective until after the effective date of the rulemaking in the instant proceeding and applies only to Commission-jurisdictional RTOs/ISOs, we find it appropriate to mention it here to provide another example of the greater opportunities for small power producer participation in organized electric markets.

660.  Order No. 872, 172 FERC ¶ 61,041 at P 640.

661.  Id. P 641.

662.  Id. PP 640, 642.

663.  AFPA v. FERC, 550 F.3d at 1183.

664.  Public Interest Organizations Request for Rehearing at 136 (citing 16 U.S.C. 824a-3(m)(3)).

665.  See NOPR, 168 FERC ¶ 61,184 at P 127.

666.  See Order No. 872, 172 FERC ¶ 61,041 at PP 628-33.

667.  See id. P 627.

668.  Id. PP 641-42.

669.  Id.

670.  Id. PP 641, 643.

671.  Id.

672.  Id. PP 641, 644.

673.  Id. P 641.

674.  Id.

675.  Id. P 684.

676.  Id.

677.  Id. P 685.

678.  Id. P 687.

679.  Id. P 688.

680.  Id.

681.  Id. P 689 (citing FLS, 157 FERC ¶ 61,211 at P 26 (stating that requiring signed interconnection agreement as prerequisite to LEO is inconsistent with PURPA Regulations)).

682.  Id. (citing 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)).

683.  Id. (citing Grouse Creek Wind Park, LLC, 142 FERC ¶ 61,187, at P 40 (2013)).

684.  Id. (citing Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d at 400).

685.  Id. (citing Power Resource Group, Inc. v. Public Utility Comm'n of Texas, 422 F.3d 231 (5th Cir. 2005)).

686.  Id. P 690.

687.  Id. P 695 (citing 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)).

688.  Id. (citing 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”)).

689.  Id.

690.  Public Interest Organizations Request for Rehearing at 145.

691.  Id. at 147-49.

692.  Mr. Mattson Motion for Time, Reconsideration, and Request Answers at 2.

693.  Order No. 872, 172 FERC ¶ 61,041 at P 684.

694.  Id. P 690.

695.  Id. P 694.

696.  See id. P 34 (citing examples of state-established prerequisites to obtaining LEOs that are inconsistent with PURPA Regulations because they hinder QF financing).

697.  Id. P 689 (citing FLS, 157 FERC ¶ 61,211 at P 26 (stating that requiring signed interconnection agreement as prerequisite to LEO is inconsistent with PURPA Regulations)).

698.  Id. (citing Murphy Flat Power, LLC, 141 FERC ¶ 61,145 at P 24 (finding that requiring a signed and executed contract with an electric utility as a prerequisite to a LEO is inconsistent with PURPA Regulations)).

699.  Id. (citing Grouse Creek Wind Park, LLC, 142 FERC ¶ 61,187 at P 40).

700.  Id. (citing Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d at 400 (requiring that only QFs capable of providing firm power are entitled to an LEO)).

701.  Id. (citing Power Resource Group, Inc. v. Pub. Util. Comm'n of Texas, 422 F.3d 231, 237-39 (5th Cir. 2005) (requiring that only QFs capable of delivering power within 90 days are entitled to an LEO)).

702.  Id. P 684.

703.  Id. P 687 (emphasis added).

704.  44 U.S.C. 3501-21.

705.  See 5 CFR 1320.11.

706.  There were no rehearing requests related to the estimated burden changes for the FERC-912 (PURPA Section 210(m) Notification Requirements Applicable to Cogeneration and Small Power Production Facilities; OMB Control No. 1902-0237), so it is not addressed further.

707.  The figures in this table reflect estimated changes to the current OMB-approved inventory for the Form No. 556 (approved by the Office of Management and Budget (OMB) on November 18, 2019). As of October 21, 2020, the Paperwork Reduction Act (PRA) packages for the reporting requirements in the final rule in Docket Nos. RM19-15 and AD16-16 are still pending review at OMB.

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 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.)

708.  Not required to file.

709.  In the 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.

710.  Public Interest Organizations Request for Rehearing at 129.

711.  Id. (citing Solar Energy Industries Comments, Docket No. RM19-15-000, at 52 (Dec. 3, 2019)).

712.  Id. at 129-30.

713.  Order No. 872, 172 FERC ¶ 61,041 at PP 552-56.

714.  Ares EIF Management, LLC Comments, Docket No. RM19-15-000, at 6 (Dec. 2, 2019); Borrego Solar Systems, Inc. Comments, Docket No. RM19-15-000, at 4 (Dec. 3, 2019); Consolidated Edison Development, Inc. Comments, Docket No. RM19-15-000, at 5 (Nov. 15, 2019); Public Interest Organizations Comments, Docket No. RM19-15-000, at 97-98 (Dec. 3, 2019); Solar Energy Industries Comments, Docket No. RM19-15-000, at 51-52, 54, 57-58 (Dec. 3, 2019); South Carolina Solar Business Alliance Comments, Docket No. RM19-15-000, at 15-18 (Dec. 3, 2019); Southern Environmental Law Center, et al. Comments, Docket No. RM19-15-000, at 29, 35 (Dec. 3, 2019); sPower Development Company, LLC Comments, Docket No. RM19-15-000, at 14 (Dec. 3, 2019).

715.  For example, in the NOPR, the Commission estimated that a small power production facility greater than 1 MW, but less than one mile from an affiliated facility, that submits a self-certification would not change the annual burden or cost. However, the Commission in the final rule estimated that such a small power production facility would need two additional hours to complete the Form No. 556; thus, the total annual burden hours and cost per response for this category would increase by two hours and by $166. Moreover, in the NOPR, the Commission estimated that a small power production facility greater than 1 MW, and greater than 10 miles from an affiliated facility, that submits an application for Commission certification would not change the annual burden or cost. However, Commission in the final rule estimated that such a small power production facility would need six additional hours to complete the Form No. 556; thus, the total annual burden hours and cost per response for this category would increase by six hours and by $498.

716.  See Data Collection for Analytics and Surveillance and Market-Based Rate Purposes, Order No. 860, 168 FERC ¶ 61,039 (2019) (adopting rules concerning data collection for public utilities with market-based rates).

717.  Solar Energy Industries Comments, Docket No. RM19-15-000, at 57-58 (Dec. 3, 2019).

718.  See Data Collection for Analytics and Surveillance and Market-Based Rate Purposes, Notice of Proposed Rulemaking, 156 FERC ¶ 61,045, at P 52 (2016).

719.  18 CFR 292.207(d), which the final rule renumbered to 18 CFR 292.207(f).

720.  Public Interest Organizations Request for Rehearing at 127-29; see Solar Energy Industries Request for Rehearing and/or Clarification at 34.

721.  See supra note 583.

722.  If a small power production QF that was certified prior to the effective date of this final rule is required to recertify due to a material change to its own facility, then at that time it will be required to identify affiliates less than 10 miles from the applicant facility.

723.  We note that we are maintaining the final rule's alternative option for rooftop solar PV developers to file their recertification applications. See Order No. 872, 172 FERC ¶ 61,041 at P 560.

724.  See supra note 583.

725.  Order No. 872, 172 FERC ¶ 61,041 at P 699.

726.  Id. P 698.

727.  Id.

728.  Id. P 699.

729.  Commission Information Collection Activities (FERC-556); Comment Request; Extension, Docket No. IC19-16-000 (issued May 15, 2019).

730.  Order No. 872, 172 FERC ¶ 61,041 at P 699.

731.  Id. P 698.

732.  Id. P 699.

733.  Id.

734.  Id. P 698.

735.  Id. P 699.

736.  Id.

737.  Id.

738.  Commission Information Collection Activities (FERC-556); Comment Request; Extension, Docket No. IC19-16-000 (issued May 15, 2019).

739.  Order No. 872, 172 FERC ¶ 61,041 at P 699.

740.  Id.

741.  Id.

742.  Id. P 698.

743.  Id. P 699.

744.  Id.

745.  Id.

746.  Id. P 699 n.1050.

747.  Id. P 699.

748.  Id.

749.  Id. P 710 (citing 42 U.S.C. 4332(C)); 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)).

750.  40 CFR 1502.4 (2019).

751.  40 CFR 1508.9.

752.  40 CFR 1508.4.

753.  Order No. 872, 172 FERC ¶ 61,041 at PP 710, 715.

754.  Id. PP 728-36.

755.  Id. P 720.

756.  Id. P 711.

757.  Id. P 716 (citing Vt. Yankee Nuclear Power Corp. v. Nat. Res. Def. Council, Inc., 435 U.S. 519, 534 (1978)).

758.  Id. (citing N. Plains Res. Council v. Surface Transp. Board, 668 F.3d 1067, 1078-79 (9th Cir. 2011) (citation omitted)).

759.  Id. (citing Concerned About Trident v. Rumsfeld, 555 F.2d 817, 830 (D.C. Cir. 1976) (citation omitted)).

760.  Id. (citing Sierra Club v. U.S. Dep't of Energy, 867 F.3d 189, 198 (D.C. Cir. 2017) (emphasis in original) (citation omitted)).

761.  Id. (citing 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”)).

762.  Id. P 717.

763.  Id. P 712 (citing Ctr. for Biological Diversity v. Ilano, 928 F.3d 774 at 780) (9th Cir. 2019).

764.  Id.

765.  Id. See also Northcoast Ent. Ctr. v. Glickman, 136 F.3d 660, 668 (9th Cir. 1998) (citing Kleppe v. Sierra Club, 427 U.S. 390 (1976) (explaining that NEPA does not require agency to complete environmental analysis where environmental effects are speculative or hypothetical)).

766.  Id. P 713.

767.  Id. P 714.

768.  Id. P 715.

769.  Id. P 718.

770.  Id.

771.  Id. P 719.

772.  Northwest Coalition Request for Rehearing at 56-57; Public Interest Organizations Request for Rehearing at 15-16.

773.  Northwest Coalition Request for Rehearing at 61 n.222.

774.  Id. at 58.

775.  Id. at 58-59.

776.  Public Interest Organizations Request for Rehearing at 20, 26 (emphasis added) (citing Sierra Club v. Froehlke, 534 F.2d 1289, 1296 (8th Cir. 1976); Scientists' Institute for Public Information, Inc. v. AEC, 481 F.2d 1079, 1092, 1098 (D.C. Cir. 1973); Jicarilla Apache Tribe of Indians v. Morton, 471 F.2d 1275, 1280 n.11 (9th Cir. 1973); Citizens Against Toxic Sprays, Inc. v. Bergland, 428 F. Supp. 908, 922 (D. Or. 1977)).

777.  Id. at 21 (citing NOPR, 168 FERC ¶ 61,184 at P 155).

778.  Id.

779.  Id. at 22 (citing Mid States Coal. for Progress v. Surface Transp. Bd., 345 F.3d 520, 549-50 (8th Cir. 2003); Scientists' Inst. For Public Info., Inc. v. AEC, 481 F.2d at 1088-89).

780.  Northwest Coalition Request for Rehearing at 60-61 (citing American Bird Conservancy, Inc. v. FCC, 516 F.3d 1027, 1033-34 (D.C. Cir. 2008)).

781.  Public Interest Organizations Request for Rehearing at 24 (citing National Parks & Conservation Ass'n v. Babbitt, 241 F.3d 722, 732 (9th Cir. 2001)).

782.  Id. (citing Seattle Audubon Soc'y v. Mosley, 798 F. Supp. 1494, 1497 (W.D. Wash. 1992)).

783.  Id. at 24-25 (citing 40 CFR 1502.22(b)(3)-(b)(4)).

784.  Northwest Coalition Request for Rehearing at 57 (citing LaFlamme v. FERC, 852 F.2d 389, 397 (9th Cir. 1988)); Public Interest Organizations Request for Rehearing at 17 (citing Greenpeace Action v. Franklin, 14 F.3d 1324, 1332 (9th Cir. 1992)).

785.  Northwest Coalition Request for Rehearing at 59-60; Public Interest Organizations Request for Rehearing at 30.

786.  Public Interest Organizations Request for Rehearing at 31 (citing Ctr. for Biological Diversity v. Ilano, 928 F.3d at 781).

787.  Id. at 34.

788.  Northwest Coalition Request for Rehearing at 60.

789.  Id.

790.  Order No. 872, 172 FERC ¶ 61,041 at PP 717-719. We note that CEQ issued a final rule, Update to the Regulations Implementing the Procedural Provisions of the National Environmental Policy Act, 85 FR 43,304 (July 16, 2020) (to be codified at 40 CFR pts. 1500-08, 1515-18), which became effective as of September 14, 2020. The final rule replaces the requirement for agency consideration of “direct, indirect, and cumulative effects” of a proposed action, with agency consideration of environmental effects “that are reasonably foreseeable and have a reasonably close causal relationship.” 40 CFR 1508.1(g). CEQ explains that agencies should not consider effects that are “remote in time, geographically remote, or the result of a lengthy causal chain.” Under this standard, the mere fact that an effect might not occur “but for” the project is not sufficient to trigger a NEPA analysis; rather, there must be a “reasonably close causal relationship” between the proposed action and the effect, “analogous to proximate cause in tort law.” Update to the Regulations Implementing the Procedural Provisions of the National Environmental Policy Act, 85 FR at 43,343.

791.  Id.

792.  Id. P 717. (emphasis added).

793.  Mid States Coal. for Progress v. Surface Transp. Bd., 345 F.3d 520.

794.  Id. (emphasis in original).

795.  Scientists' Institute for Public Information, Inc. v. AEC, 481 F.2d 1079.

796.  Id.

797.  Order No. 872, 172 FERC ¶ 61,041 at PP 718-19.

798.  Northwest Coalition Request for Rehearing at 57 (citing LaFlamme v. FERC, 852 F.2d at 397); Public Interest Organizations Request for Rehearing at 17 (citing Greenpeace Action v. Franklin, 14 F.3d at 1332).

799.  Foundation for N. Am. Wild Sheep v. USDA, 681 F.2d 1172, 1177-78 (9th Cir. 1982).

800.  Order No. 872, 172 FERC ¶ 61,041 at PP 717-19, 731-36.

801.  LaFlamme v. FERC, 852 F.2d at 389.

802.  Id. at 397 (finding that substantial questions were raised about potential “significant environmental degradation [of a hydropower project] due to both its site-specific impact on recreational use and visual quality and its cumulative impact[s]”).

803.  Greenpeace Action v. Franklin, 14 F.3d 1324.

804.  Id. at 1327.

805.  Id. at 1333.

806.  Id. (emphasis added). Plaintiffs in this case also cited several cases to support its claim that the very existence of uncertainty mandates the preparation of an EIS. However, the court noted that because the cases cited “deal not with whether an impact statement should be prepared, but with what information should be included in an impact statement after it has been judged necessary, they do not stand for the proposition that the existence of uncertainty mandates the preparation of an impact statement.” Id. at 1334 n.11.

807.  Northwest Coalition Request for Rehearing at 59.

808.  Public Interest Organizations Request for Rehearing at 34.

809.  See Order No. 872, 172 FERC ¶ 61,041 at P 716 (citing N. Plains Res. Council v. Surface Transp. Board, 668 F.3d at 1078-79; Concerned About Trident v. Rumsfeld, 555 F.2d at 830).

810.  Id. P 714.

811.  National Parks & Conservation Ass'n v. Babbitt, 241 F.3d 722, 732 (9th Cir. 2001) (emphasis added).

812.  We also disagree with Public Interest Organizations' assertion that because the Commission is faced with incomplete or unavailable information, the CEQ regulations state the Commission must include in an EIS a summary of existing credible scientific evidence that is relevant to evaluating the reasonably foreseeable impacts of a proposed action. Public Interest Organizations Request for Rehearing at 23-24 (citing 40 CFR 1502.22(b)(3)-(b)(4)). This regulation is inapplicable to the final rule, as it contemplates that an EIS has been prepared, and that there are reasonably foreseeable impacts for which existing credible scientific evidence may be relevant (emphasis added). The Commission did not prepare an EIS because there are no reasonably foreseeable impacts for the reasons discussed in the final rule and herein.

813.  National Parks & Conservation Ass'n v. Babbitt, 241 F.3d 732.

814.  Ctr. for Biological Diversity v. Ilano, 928 F.3d at 781.

815.  Id. at 780 (quoting Northcoast Envtl. Ctr. v. Glickman, 136 F.3d at 668).

816.  Order No. 872, 172 FERC ¶ 61,041 at P 733.

817.  Id. P 716 (citing Dep't of Transp. v. Pub. Citizen, 541 U.S. at 767; Metro. Edison Co. v. People Against Nuclear Energy, 460 U.S. at 774).

818.  Ctr. for Biological Diversity, 928 F.3d at 781 (citing Northcoast Envtl. Ctr. v. Glickman, 136 F.3d at 668).

819.  See Order No. 872, 172 FERC ¶ 61,041 at PP 733-35.

820.  Id. P 720 (citing 18 CFR 380.4(a)(2)(ii)). The exclusion applies to a fourth type of rule, the promulgation of regulations “that do not substantially change the effect of . . . regulations being amended.” Further, although not challenged on rehearing, the final rule noted two revisions that are procedural in nature: The revision to procedures that apply to QF certification and the revision to the Commission's Form No. 556, used by QFs seeking certification. Id. P 727.

821.  Id. P 721.

822.  Id. P 722.

823.  Id. P 723.

824.  Id. P 724.

825.  Id.

826.  Id. P 725.

827.  Id.

828.  Id. P 726.

829.  Id.

830.  Id.

831.  Northwest Coalition Request for Rehearing at 62; Public Interest Organizations Request for Rehearing at 36 (citing 18 CFR 380.4(b)(1)).

832.  Northwest Coalition Request for Rehearing at 62; Public Interest Organizations Request for Rehearing at 36 (citing 18 CFR 380.4(b)(1)).

833.  40 CFR 1508.4.

834.  18 CFR 380.4(b)(ii).

835.  Order No. 872, 172 FERC ¶ 61,041 at P 716.

836.  18 CFR 380.4.

837.  Northwest Coalition Request for Rehearing at 62-63; Public Interest Organizations Request for Rehearing at 35.

838.  Northwest Coalition Request for Rehearing at 63.

839.  Id. We address in section III.B.5 above Northwest Coalition's challenge to the competitive solicitation framework itself.

840.  Id.

841.  Id. at 63-64.

842.  Id. at 64.

843.  Id. at 63 (quoting Order No. 872, 172 FERC ¶ 61,041 at P 722).

844.  Id. at 63-64 (citing Order No. 872, 172 FERC ¶ 61,041, Glick, Comm'r, dissenting in part at P 26).

845.  Public Interest Organizations Request for Rehearing at 35-36.

846.  Id. at 35.

847.  Id. at 41 (citing 40 CFR 1501.7).

848.  Id. (citing 40 CFR 1508.21).

849.  Id.

850.  Northwest Coalition Request for Rehearing at 62-64.

851.  Id. at 63. We address in section III.B.5 above Northwest Coalition's challenge to the competitive solicitation framework itself.

852.  E.g., Hydrodynamics, 146 FERC ¶ 61,193 at PP 31-35; City of Ketchikan, 94 FERC ¶ 61,293 at 62,061; Bidding NOPR, FERC Stats. & Regs. ¶ 32,455 at 32,030-42.

853.  See Order No. 872, 172 FERC ¶ 61,041 at P 430 (citing Allegheny Energy, 108 FERC ¶ 61,082 at P 18).

854.  Id. PP 283, 723.

855.  Id. P 283.

856.  Id.

857.  40 CFR 1501.7 (“As soon as practicable after its decision to prepare an environmental impact statement and before the scoping process the lead agency shall publish a notice of intent” to prepare an EIS). Moreover, CEQ guidance addressing whether scoping applies to EAs, states that where an EA is being prepared, “useful information might result from early participation . . . in a scoping process” CEQ, Forty Most Asked Questions Concerning CEQ's National Environmental Policy Act Regulations, 46 FR 18,026, Q. 13 (Mar. 17, 1981) (emphasis added).

858.  Order No. 872, 172 FERC ¶ 61,041 at P 728.

859.  Id. P 729 (citing Order No. 70-E, 46 FR 33,025, 33,026 (June 18, 1981); Small Power Production and Cogeneration Facilities—Environmental Findings; No Significant Impact and Notice of Intent To Prepare Environmental Impact Statement, 45 FR 23,661, 23,664 (Apr. 8, 1980) (Original PURPA EA)).

860.  Original PURPA EA, 45 FR at 23,664.

861.  Order No. 872, 172 FERC ¶ 61,041 at P 731.

862.  Id. P 732.

863.  Id. P 733.

864.  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).

865.  Order No. 872, 172 FERC ¶ 61,041 at P 734.

866.  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/​.

867.  Order No. 872, 172 FERC ¶ 61,041 at P 734.

868.  Id. P 735.

869.  Id. P 736.

870.  Northwest Coalition Request for Rehearing at 59; Public Interest Organizations Request for Rehearing at 26-30.

871.  Northwest Coalition Request for Rehearing at 59; Public Interest Organizations Request for Rehearing at 28 (citing Bidding NOPR, FERC Stats. & Regs. ¶ 32,455 at 32,047).

872.  Northwest Coalition Request for Rehearing at 59; Public Interest Organizations Request for Rehearing at 29 (citing Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, FERC Stats. & Regs. ¶ 31,036 (1996) (cross-referenced at 75 FERC ¶ 61,080 and 61 FR 21,540 (May 10, 1996)), order on reh'g, Order No. 888-A, FERC Stats. & Regs. ¶ 31,048 (cross-referenced at 78 FERC ¶ 61,220 and 62 FR 12,274 (Mar. 14, 1997)), order on reh'g, Order No. 888-B, 81 FERC ¶ 61,248 (1997) (cross-referenced at 62 FR 64,688 (Dec. 9, 1997), order on reh'g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff'd in relevant part sub nom. Transmission Access Pol'y Study Grp. v. FERC, 225 F.3d 667, aff'd sub nom. N.Y. v. FERC, 535 U.S. 1 (2002)).

873.  Public Interest Organizations Request for Rehearing at 26.

874.  Id. at 26-27 (citing Order No. 70, FERC Stats. & Regs. ¶ 30,134).

875.  Id. at 27.

876.  Id.

877.  Northwest Coalition Request for Rehearing at 59.

878.  Public Interest Organizations Request for Rehearing at 29.

879.  Northwest Coalition Request for Rehearing at 59; Public Interest Organizations Request for Rehearing at 28-29.

880.  Public Interest Organizations Request for Rehearing at 29-30.

881.  Order No. 872, 172 FERC ¶ 61,041 at P 729.

882.  Id. P 731.

883.  Id.

884.  Id. PP 731-32.

885.  Id. PP 731-34.

886.  See id. P 240.

887.  Id. P 734.

888.  Id. PP 731-32.

889.  See Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,861-96.

890.  5 U.S.C. 601-12.

891.  Order No. 872, 172 FERC ¶ 61,041 at P 748.

1.  Qualifying Facility Rates and Requirements Implementation Issues Under the Public Utility Regulatory Policies Act of 1978, Order No. 872-A, 173 FERC ¶ 61,158 (2020).

2.  Qualifying Facility Rates and Requirements Implementation Issues Under the Public Utility Regulatory Policies Act of 1978, Order No. 872, 172 FERC ¶ 61,041 (2020).

3.  Public Law 95-617, 92 Stat. 3117 (1978).

4.  See 16 U.S.C. 824a-3(a)-(b) (2018).

5.  Those concerns notwithstanding, I supported certain aspects of Order No. 872, including the revisions to the “one-mile” rule, requiring that QFs demonstrate commercial viability before securing a legally enforceable obligation, and allowing stakeholders to protest a QF's self-certification. See Order No. 872, 172 FERC ¶ 61,041 (Glick, Comm'r, dissenting in part at n.4).

6.  Public Law 109-58, 1253, 119 Stat. 594 (2005).

7.  Sept. 2019 Commission Meeting Tr. at 8.

8.  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).

9.  Supra note 6.

10.  See Solar Energy Industries Association (SEIA) Comments at 11.

11.  NOPR, 168 FERC ¶ 61,184 (Glick, Comm'r, dissenting in part at P 4).

12.  Id.

13.  Order No. 872-A, 173 FERC ¶ 61,158 at P 115; Order No. 872, 172 FERC ¶ 61,041 at PP 24, 48, 54, 67, 296, 628; NOPR, 168 FERC ¶ 61,184 at PP 4, 16, 29, 155.

14.  A QF is a cogeneration facility or a small power production facility. See 18 CFR 292.101(b)(1) (2019).

15.  16 U.S.C. 824a-3(a)-(b).

16.  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)).

17.  Order No. 872, 172 FERC ¶ 61,041 at P 253.

18.  Id. P 151.

19.  Id. P 253.

20.  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).

21.  See, e.g., ELCON Comments at 21-22 (“More variable 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).

22.  See, e.g., Public Interest Organizations Rehearing Request at 73-76; SEIA Comments at 29; North Carolina Attorney General's Office Comments at 5; ConEd Development Comments at 3; South Carolina Solar Business Association Comments at 6; sPower Comments at 11; Resources for the Future Comments at 6-7; Southeast Public Interest Organizations Comments at 9.

23.  Order No. 872-A, 173 FERC ¶ 61,158 at PP 150-151 (citing Order No. 872, 172 FERC ¶ 61,041 at P 340).

24.  See, e.g., EEI Comments at 36; sPower Comments at 12; Public Interest Organization Comments at n. 87 (fixed price contracts for non-QF generation); SEIA Rehearing Request at 14-15.

25.  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 US 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.”); SEIA Rehearing Request at 18.

26.  See, e.g., Public Interest Organizations Rehearing Request at 74-78; Northwest Coalition Rehearing Request at 28.

27.  Compare https://en.wikipedia.org/​wiki/​Hank_​Aaron with https://en.wikipedia.org/​wiki/​Tommie_​Aaron. The Commission also points to the rate structure discussed in Town of Norwood v. FERC, 962 F.2d 20, 21, 24 (D.C. Cir. 1992), “variable energy rate/fixed capacity rate construct is the standard rate structure used throughout the electric industry.” Order No. 872, 172 FERC ¶ 61,041 at P 38; see also Order No. 872-A, 173 FERC ¶ 61,158 at P 143. I do not believe that the discussion of a single contract in a single case, decided roughly thirty years ago, is substantial evidence regarding the typical financing and contractual requirements of a QF in the contemporary electricity sector.

28.  See, e.g., Order No. 872-A, 173 FERC ¶ 61,158 at PP 145-146, 172.

29.  See, e.g., Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,880 (finding that “legally enforceable obligations are intended to reconcile the requirement that the rates for purchases equal to the utilities avoided cost with the need for qualifying facilities to be able to enter into contractual commitments, by necessity, on estimates of future avoided costs” and “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.”). The Commission responds that “[i]t is not necessary to prove that all potential QFs would be able to raise useful financing.” Order No. 872-A, 173 FERC ¶ 61,158 at P 175. Talk about moving the goal posts. No one has argued that this is the Commission's burden. Rather, the argument is that the Commission's reforms may render it impossible, or nearly so, for QFs outside the organized markets to obtain the necessary financing. Order No. 872, 172 FERC ¶ 61,041 (Comm'r, Glick, dissenting in part at PP 11-12); Public Interest Organizations at 79-84. The Commission cannot skirt that point by knocking down a strawman, especially given the weight it is has historically given to the importance of financeability for QFs.

30.  See, e.g., Order No. 872-A, 173 FERC ¶ 61,158 at P 43.

31.  See id. P 174; Order No. 872, 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 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.”).

32.  See, e.g., Order No. 872, 172 FERC ¶ 61,041 at P 422 (citing to City of Ketchikan, Alaska, 94 FERC ¶ 61,293, at 62,061 (2001)).

33.  See, e.g., Electric Power Supply Association (EPSA) Rehearing Request at 13-14; Resources for the Future Comments at 6; SEIA Comments at 30; Southeast Public Interest Organizations Comments at 12.

34.  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.”).

35.  16 U.S. Code 824a-3(b)(2). Unlike provisions of the Federal Power Act, PURPA prohibits any discrimination against QFs, not just undue discrimination. See Order No. 872, 172 FERC ¶ 61,041 at P 82; see also EPSA Rehearing Request at 6; ELCON Comments at 21-22; South Carolina Solar Business Alliance Comments at 7-8; sPower Comments at 13.

36.  Order No. 872, 172 FERC ¶ 61,041 at P 40.

37.  See supra note 20; Commissioner Slaughter Comments at 4.

38.  EPSA Rehearing Request at 8-9; 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.”).

39.  Order No. 872-A, 173 FERC ¶ 61,158 at P 142.

40.  See Public Interest Organizations Rehearing Request at 94-95; Northwest Coalition Rehearing Request at 11-12.

41.  See supra note 35.

42.  Order No. 872-A, 173 FERC ¶ 61,158 at P 142 n.275.

43.  Id. PP 76-78.

44.  Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,880.

45.  Order No. 872-A, 173 FERC ¶ 61,158 at PP 84, 175.

46.  EPSA Rehearing Request at 15-16 (citing Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,880).

47.  Order No. 872 was 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., Order No. 872, 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, https://www.eia.gov/​totalenergy/​data/​browser/​ (last viewed November 18, 2020).

48.  Order No. 872, 172 FERC ¶ 61,041 at PP 151, 189, 211.

49.  See, e.g., Public Interest Organizations Rehearing Request at 69-71. These points have also been raised throughout this proceeding. Public Interest Organizations Comments at 47-49 (explaining that numerous power plants incur marginal production costs that exceed the LMP); id at 50-51 (discussing analysis from Bloomberg New Energy Finance that compares marginal production costs with LMP and finds that many vertically integrated utilities regularly incur production costs that exceed LMP); id. at 51-52 (showing that a Springfield Illinois coal-fired power plant's marginal dispatch costs exceeds LMP); id. at 52-53 (explaining that many utilities' per-net-kWh costs exceed LMP); id. at 53-54 (contending that the cost associated with long-term fixed-price contracts for nuclear plants exceed LMP even net of capacity value).

50.  Order No. 872-A, 173 FERC ¶ 61,158 at PP 63-64 (citing Cablevision Sys. Corp. v. FCC, 649 F.3d 695, 716 (D.C. Cir. 2011)).

51.  Cablevision, 649 F.3d at 716 (“`[A]n evidentiary presumption is only permissible if there is a sound and rational connection between the proved and inferred facts, and when proof of one fact renders the existence of another fact so probable that it is sensible and timesaving to assume the truth of the inferred fact.' ” (quoting Nat'l Mining Ass'n v. Dep't of Interior, 177 F.3d 1, 6 (D.C. Cir. 1999))).

52.  It is also unclear from this record whether that presumption is best characterized as a shift in the burden of production rather than the burden of persuasion. To the extent that a QF or other entity must show that LMP is not an adequate measure of avoided cost in order to rebut the presumption, then the Commission has, for all intents and purposes, shifted the burden of persuasion to those entities no matter how the Commission describes its presumption.

53.  Public Interest Organizations Rehearing Request at P 61.

54.  EPSA Rehearing Request at 13-14; Public Interest Organizations Rehearing Request at 98-99.

55.  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. 824a-3(m).

56.  Order No. 872, 172 FERC ¶ 61,041 at P 625.

57.  NOPR, 168 FERC ¶ 61,184 at P 126.

58.  Order No. 688-A, 119 FERC ¶ 61,305 at PP 96, 103.

59.  E.g., N. States Power Co., 151 FERC ¶ 61,110, at P 34 (2015).

60.  Order No. 872, 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.”); see Order No. 872-A, 173 FERC ¶ 61,158 at P 361.

61.  See Public Interest Organizations Rehearing Request at 135.

62.  Order No. 872, 172 FERC ¶ 61,041 at P 630; Order No. 872-A, 173 FERC ¶ 61,158 at P 361.

63.  Order No. 792, 145 FERC ¶ 61,159, at P 103 (2013) (“The Commission finds that the modifications . . . are just and reasonable and strike a balance between allowing larger projects to use the Fast Track Process while ensuring safety and reliability.”); see also SEIA Rehearing Request at 39-40.

64.  Order No. 872-A, 173 FERC ¶ 61,158 at P 362 (citing Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators, Order No. 841, 162 FERC ¶ 61,127 (2018), at P 272).

65.  Order No. 872, 172 FERC ¶ 61,041 at 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.”); see Order No. 872-A, 173 FERC ¶ 61,158 at P 347.

66.  Fox Television, 556 U.S. at 515; Advanced Energy Economy Comments at 6.

67.  Fox Television, 556 U.S. at 516; Advanced Energy Economy Comments at 6-7.

68.  Small Power Production and Cogeneration Facilities—Environmental Findings; No Significant Impact and Notice of Intent To Prepare Environmental Impact Statement, 45 FR 23,661 (Apr. 8, 1980).

69.  Sierra Club v. FERC, 867 F.3d 1357, 1374 (D.C. Cir. 2018) (quoting Del. Riverkeeper Network v. FERC, 753 F.3d 1304, 1310 (D.C. Cir. 2014)).

70.  Order No. 872-A, 173 FERC ¶ 61,158 at P 449.

71.  Order No. 872, 172 FERC ¶ 61,041 at P 722; Order No. 872-A, 173 FERC ¶ 61,158 at P 438.

72.  16 U.S.C. 824a-3(m).

73.  See Order No. 688, 117 FERC ¶ 61,078 at P 8.

74.  See Advanced Energy Economy Comments at 13; Industrial Energy Consumers Comments at 13-14; EPSA Comments at 16.

75.  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).

76.  See, e.g., SEIA Supplemental Comments, Docket No. AD16-16-000 (Aug. 28, 2019).

77.  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.

78.  Order No. 872, 172 FERC ¶ 61,041 at P 662.