172 FERC ¶ 61,041

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Parts 292 and 375

[Docket Nos. RM19-15-000 and AD16-16-000; Order No. 872]

Qualifying Facility Rates and Requirements

Implementation Issues Under the Public Utility Regulatory Policies Act of 1978

(Issued July 16, 2020)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Final rule.

SUMMARY: In this Order, the Federal Energy Regulatory Commission issues its final 

rule approving certain revisions to its regulations implementing sections 201 and 210 of 

the Public Utility Regulatory Policies Act of 1978 (PURPA). These changes will enable 

the Commission to continue to fulfill its statutory obligations under sections 201 and 210 

of PURPA.

DATES: This rule will become effective [INSERT DATE 120 DAYS AFTER THE 

DATE OF PUBLICATION IN THE FEDERAL REGISTER].

FOR FURTHER INFORMATION CONTACT:

Lawrence R. Greenfield (Legal Information)

Office of the General Counsel

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-6415

lawrence.greenfield@ferc.gov
Docket Nos. RM12

-1-000 and RM13-9-000- 2 -

Helen Shepherd (Technical Information)

Office of Energy Market Regulation

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-6176

helen.shepherd@ferc.gov

Thomas Dautel (Technical Information)

Office of Energy Policy and Innovation

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-6196

thomas.dautel@ferc.gov

SUPPLEMENTARY INFORMATION:
172 FERC ¶ 61,041

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Neil Chatterjee, Chairman;

 Richard Glick, Bernard L. McNamee,

and James P. Danly.

Qualifying Facility Rates and Requirements

Implementation Issues Under the Public Utility 

Regulatory Policies Act of 1978

Docket Nos. RM19-15-000

AD16-16-000

Order No. 872

FINAL RULE

(Issued July 16, 2020)

TABLE OF CONTENTS

Paragraph Numbers

I. Introduction ..................................................................................................................... 1.

II. Overview........................................................................................................................ 5.

A. The Commission’s PURPA Regulations, as revised by this Final Rule, Continue to 

Encourage the Development of QFs within the Requirements of PURPA’s Statutory 

Limitations ..................................................................................................................... 6.

1. Avoided Cost Cap on QF Rates........................................................................... 13.

2. Limitation on Small Power Production Facilities Located at the Same “Site” ... 17.

3. Termination of Purchase Obligation for QFs With Nondiscriminatory Access to 

Certain Competitive Markets................................................................................... 18.

4. Final Rule’s Updating of the PURPA Regulations ............................................. 20.

B. The Final Rule Ensures that the Commission’s Implementation of PURPA 

Continues to Benefit QFs, Purchasing Electric Utilities, and Electric Consumers ..... 28.

C. The Commission is Not Eliminating Fixed Rate Pricing for QFs, But Rather is 

Giving States the Flexibility to Require the Same Variable Energy Rate/Fixed Capacity 

Rate Construct that Applies Throughout the Electric Industry.................................... 35.

D. The Rate Changes Implemented by this Final Rule Put QF Rates on the Same 

Footing as Electric Utility Rates and Are Not Discriminatory.................................... 39.

E. The PURPA Compliance Issues Raised by Some Commenters Are Outside the 

Scope of this Rulemaking Proceeding ......................................................................... 42.
Docket Nos. RM19-15-000 and AD16-16-000 - 2 -

III. Background................................................................................................................. 47.

A. Passage of PURPA in 1978 and the Commission’s Promulgation of its PURPA 

Regulations in 1980...................................................................................................... 47.

B. Circumstances Leading to the Commission’s Re-evaluation of the PURPA 

Regulations and the Issuance of the NOPR................................................................. 51.

C. Summary of Changes to the PURPA Regulations Implemented by this final rule. 56.

IV. Discussion .................................................................................................................. 67.

A. General Legal Standards Under PURPA ................................................................ 67.

1. Encouragement of QFs........................................................................................ 68.

a. Comments........................................................................................................ 68.

b. Commission Determination ............................................................................ 70.

2. Discrimination ..................................................................................................... 79.

a. Comments........................................................................................................ 79.

b. Commission Determination ............................................................................ 82.

3. Unlawful Delegation and the Role of Nonregulated Electric Utilities................ 89.

a. Comments........................................................................................................ 89.

b. Commission Determination ............................................................................ 93.

B. QF Rates.................................................................................................................. 96.

1. Overview.............................................................................................................. 96.

2. Use of Competitive Market Prices to Set As-Available Avoided Cost Rates... 103.

a. NOPR Proposal ............................................................................................. 104.

b. Comments...................................................................................................... 107.

c. Commission Determination........................................................................... 114.

3. LMP as a Permissible Rate for Certain As-Available Avoided Cost Rates...... 124.

a. NOPR Proposal ............................................................................................. 124.

b. Comments...................................................................................................... 129.

i. Comments in Opposition ........................................................................... 129.

(a) Utilizing Western EIM to Establish Avoided Costs........................... 137.

ii. Comments in Support............................................................................... 138.

(a) Utilizing Western EIM to Establish Avoided Costs........................... 145.

iii. Comments in Support with Requested Modifications/Clarifications...... 146.

c. Commission Determination........................................................................... 151.

i. Arguments Against the NOPR Proposal ................................................... 155.

ii. Requests for Modification or Clarification of the NOPR......................... 173.

iii. Western EIM ........................................................................................... 177.

4. Use of Market Hub Prices as a Permissible Rate for Certain As-Available QF 

Energy Sales .......................................................................................................... 180.

a. NOPR Proposal ............................................................................................. 180.

b. Comments...................................................................................................... 182.

i. Comments in Support ................................................................................ 182.

ii. Comments in Opposition.......................................................................... 184.

iii. Commission Determination..................................................................... 189.
Docket Nos. RM19-15-000 and AD16-16-000 - 3 -

c. Proposed Modifications................................................................................. 195.

i. Comments.................................................................................................. 195.

ii. Commission Determination...................................................................... 200.

5. Use of Formulas Based on Natural Gas Prices to Establish a Permissible Rate for 

Certain As-Available QF Energy Sales................................................................. 203.

a. NOPR Proposal ............................................................................................. 203.

b. Comments...................................................................................................... 206.

c. Commission Determination........................................................................... 211.

6. Permitting the Energy Rate Component of a Contract to be Fixed at the Time of 

the LEO Using Forecasted Values of the Estimated Stream of Market Revenues217.

a. Comments...................................................................................................... 219.

b. Commission Determination .......................................................................... 227.

7. Providing for Variable Energy Rates in QF Contracts...................................... 232.

a. Background.................................................................................................... 232.

b. NOPR Proposal ............................................................................................. 234.

c. General Comments on the NOPR Proposal .................................................. 245.

i. Comments in Support of NOPR Proposal................................................. 245.

ii. Comments in Opposition to NOPR Proposal........................................... 248.

iii. Commission Determination..................................................................... 253.

d. Whether the Current Approach Has Resulted in Payments to QFs in Excess of 

Avoided Costs................................................................................................... 265.

i. Comments in Support of NOPR Proposal................................................. 265.

ii. Comments in Opposition to NOPR Proposal........................................... 272.

iii. Commission Determination..................................................................... 283.

e. Whether the Proposed Change Would Violate the Statutory Requirement that 

the PURPA Regulations Encourage QFs.......................................................... 294.

i. Comments.................................................................................................. 294.

ii. Commission Determination...................................................................... 295.

f. Discrimination................................................................................................ 297.

i. Comments in Support of NOPR Proposal................................................. 297.

ii. Comments in Opposition to NOPR Proposal........................................... 298.

iii. Commission Determination..................................................................... 302.

g. Effect of Variable Energy Rates on Financing ............................................. 304.

i. Comments in Support of the NOPR Proposal ........................................... 304.

ii. Comments in Opposition to the NOPR Proposal ..................................... 312.

iii. Commission Determination..................................................................... 335.

h. Other Claimed Benefits of Fixed Avoided Cost Energy Rates..................... 350.

i. Comments.................................................................................................. 350.

ii. Commission Determination...................................................................... 351.

i. Potential Modifications to NOPR Proposal ................................................... 354.

i. Comments.................................................................................................. 354.

ii. Commission Determination...................................................................... 357.

8. Consideration of Competitive Solicitations to Determine Avoided Costs........ 361.
Docket Nos. RM19-15-000 and AD16-16-000 - 4 -

a. NOPR Proposal ............................................................................................. 361.

b. Comments...................................................................................................... 368.

i. Comments in Opposition ........................................................................... 368.

ii. Comments in Support............................................................................... 375.

iii. Comments Requesting Modifications/Clarifications.............................. 383.

(a) Requests for Clarification and/or Separate Proceedings .................... 383.

(b) Requests Regarding Proposed Criteria ............................................... 390.

(c) Other Requests.................................................................................... 400.

c. Commission Determination........................................................................... 411.

i. Requests for Clarification and/or Separate Proceedings........................... 415.

ii. Proposed Criteria ...................................................................................... 420.

iii. Other Requests......................................................................................... 439.

C. Relief from Purchase Obligation in Competitive Retail Markets......................... 442.

1. NOPR Proposal.................................................................................................. 442.

2. Comments.......................................................................................................... 444.

3. Commission Determination............................................................................... 456.

D. Evaluation of Whether QFs are at Separate Sites................................................. 458.

1. Rebuttable Presumption of Separate Sites......................................................... 458.

a. NOPR Proposal ............................................................................................. 458.

b. Commission Determination .......................................................................... 466.

c. Need for Reform............................................................................................ 470.

i. Comments.................................................................................................. 470.

ii. Commission Determination...................................................................... 472.

d. Site Definition ............................................................................................... 473.

i. Comments.................................................................................................. 473.

ii. Commission Determination...................................................................... 476.

e. Distance Between Facilities .......................................................................... 482.

i. Comments.................................................................................................. 482.

ii. Commission Determination...................................................................... 490.

f. Factors............................................................................................................ 497.

i. Comments.................................................................................................. 497.

ii. Commission Determination...................................................................... 508.

g. Exemptions.................................................................................................... 512.

i. Comments.................................................................................................. 512.

ii. Commission Determination...................................................................... 514.

2. Electrical Generating Equipment....................................................................... 515.

a. NOPR Proposal ............................................................................................. 515.

b. Comments...................................................................................................... 518.

c. Commission Determination........................................................................... 521.

E. QF Certification Process........................................................................................ 525.

1. NOPR Proposal.................................................................................................. 525.

2. Comments.......................................................................................................... 530.

3. Commission Determination............................................................................... 547.
Docket Nos. RM19-15-000 and AD16-16-000 - 5 -

F. Corresponding Changes to the FERC Form No. 556 ............................................ 570.

1. NOPR Proposal.................................................................................................. 570.

2. Comments.......................................................................................................... 577.

3. Commission Determination............................................................................... 584.

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

Markets....................................................................................................................... 597.

1. PURPA Section 210(m) Implementation .......................................................... 597.

a. NOPR Proposal ............................................................................................. 597.

b. Comments in Opposition............................................................................... 602.

i. Insufficient Evidentiary Support ............................................................... 603.

ii. Administrative Burden and Complex Market Rules................................ 611.

c. Comments in Support.................................................................................... 614.

d. Comments Requesting Modifications/Clarifications.................................... 617.

e. Commission Determination........................................................................... 624.

2. Reliance on RFPs and Liquid Market Hubs to Terminate Purchase Obligation 

Under PURPA Section 210(m).............................................................................. 648.

a. NOPR Discussion.......................................................................................... 648.

b. Comments...................................................................................................... 651.

i. Comments in Opposition ........................................................................... 651.

ii. Comments in Support............................................................................... 655.

c. Commission Determination........................................................................... 659.

H. Legally Enforceable Obligation ............................................................................ 663.

1. NOPR Proposal.................................................................................................. 663.

2. Comments.......................................................................................................... 666.

a. Comments in Opposition............................................................................... 666.

b. Comments in Support.................................................................................... 673.

c. Comments Requesting Modification............................................................. 676.

i. Studies........................................................................................................ 677.

ii. Commercial Viability ............................................................................... 679.

iii. Financial Viability................................................................................... 681.

iv. Rejecting QF Purchases and Expanded Curtailment Rights................... 683.

3. Commission Determination............................................................................... 684.

V. Information Collection Statement ............................................................................. 697.

VI. Environmental Analysis........................................................................................... 702.

A. Comments.............................................................................................................. 703.

B. Commission Determination................................................................................... 710.

1. No EIS or EA is Required ................................................................................. 712.

a. There is no Project that Defines the Scope and Limits of QF Development 712.

b. A Categorical Exclusion Applies.................................................................. 720.

i. Changes that are Clarifying in Nature ....................................................... 721.

ii. Changes that are Corrective in Nature...................................................... 722.

iii. Changes that are Procedural in Nature .................................................... 727.
Docket Nos. RM19-15-000 and AD16-16-000 - 6 -

2. The NEPA Analysis for Promulgation of the Original PURPA Regulations in 

1980 Cannot be Replicated Here ........................................................................... 728.

3. This Proceeding Does Not Trigger Any ESA Consultation Requirement ........ 737.

VII. Regulatory Flexibility Act Certification ................................................................. 743.

VIII. Document Availability .......................................................................................... 750.

IX. Effective Dates and Congressional Notification ...................................................... 753.
Docket Nos. RM19-15-000 and AD16-16-000 - 7 -

I. Introduction

1. In this Order, the Federal Energy Regulatory Commission (Commission) issues its 

final rule approving certain revisions to its regulations (PURPA Regulations)1

implementing sections 201 and 210 of the Public Utility Regulatory Policies Act of 1978 

(PURPA).

2

 

2. On September 19, 2019, the Commission issued a notice of proposed rulemaking 

(NOPR) proposing to modify its PURPA Regulations.3

 Those regulations were promulgated 

in 1980 and have been modified in only specific respects since then. Approximately

130 separate comments were submitted in response to the NOPR,4 several of which were 

submitted on behalf of multiple parties. In total, over 1,600 pages of comments were 

submitted, and in addition thousands of pages of exhibits were attached to the comments. 

The entities that filed comments are listed in Appendix A. This final rule addresses 

comments received in response to the NOPR. 

3. We largely adopt the NOPR proposals. However, this final rule makes certain 

modifications to the NOPR proposals, as further discussed below.

1 18 CFR pt. 292 (2019). In connection with the revisions to the PURPA 

Regulations, the Commission also is revising its delegation of authority to Commission 

staff in 18 CFR pt. 375. 

2 16 U.S.C. 796(17)-(18), 824a-3.

3 Qualifying Facility Rates and Requirements Implementation Issues Under the 

Public Utility Regulatory Policies Act of 1978, 168 FERC ¶ 61184 (2019) (NOPR).

4 See Appendix for list of commenters. 
Docket Nos. RM19-15-000 and AD16-16-000 - 8 -

4. Given the Commission’s expressed intent in the NOPR to propose revisions to the 

PURPA Regulations that more closely adhere to the goals and terms of PURPA,5 we 

considered comments regarding whether these proposals are consistent with the 

requirements of PURPA. Based on that review and further consideration, we adopt the 

following changes to the proposals in the NOPR, among certain others described below: 

• we establish a rebuttable presumption, rather than a per se rule, that locational 

marginal prices (LMPs) may reflect a purchasing electric utility’s avoided 

energy costs; 

• we provide that any competitive solicitations used to establish avoided capacity 

costs must adhere to the Commission’s Allegheny6 standard for evaluating 

competitive solicitations; 

• we do not adopt the proposed rule permitting states with retail competition to 

allow relief from the purchase obligation but instead clarify that the 

Commission’s existing PURPA Regulations already require that states, to the 

extent practicable, must account for reduced loads in setting QF capacity rates; 

• we clarify terminology we used in the NOPR relating to the determination of 

whether small power production facilities are separate facilities to focus not on 

whether they are separate facilities, but rather to mirror the statutory language 

and thus focus on whether they are at “the same site”; 

• we clarify in the regulations that protests may be made to initial selfcertifications and applications for Commission certification, but only to selfrecertifications and applications for Commission recertification making 

substantive changes to the existing certification; 

• we identify additional factors that can be considered for small power production 

qualifying facilities (QFs) located more than one but less than 10 miles apart, 

such as evidence of shared control systems, common permitting and land 

leasing, and shared step-up transformers; 

5 NOPR, 168 FERC ¶ 61,184 at P 31. 

6 Allegheny Energy Supply Co., LLC, 108 FERC ¶ 61,082, at P 18 (2004)

(Allegheny).
Docket Nos. RM19-15-000 and AD16-16-000 - 9 -

• we revise the regulations to lower the rebuttable presumption of small power 

production QFs’ nondiscriminatory access to 5 MW, rather than 1 MW as 

proposed in the NOPR, and include factors that a small power production QF 

sized greater than 5 MW could rely on to rebut the presumption that it has

nondiscriminatory access to markets defined in PURPA sections 210(m)(1); and

• we revise the proposed requirements to establish a legally enforceable 

obligation (LEO) to provide that with regard to the issue of obtaining permits, 

QFs need only have applied for all required permits, instead of being required to 

have already obtained those permits.

II. Overview

5. Before discussing each of the individual changes to the PURPA Regulations 

adopted herein, this final rule first addresses certain overall themes raised in the comments 

on the NOPR, both those supporting the NOPR and those opposing. 

A. The Commission’s PURPA Regulations, as revised by this Final Rule, 

Continue to Encourage the Development of QFs within the 

Requirements of PURPA’s Statutory Limitations 

6. PURPA section 210(a) requires that the Commission prescribe rules that it 

determines necessary to encourage the development of qualifying small power production 

facilities and cogeneration facilities. 

7. The bulk of the criticism of the Commission’s proposed rule changes is based on a

widespread misunderstanding, as reflected in the comments on the NOPR, that PURPA 

and the PURPA Regulations were intended to encourage QF development without any 

limit, and that the rule changes proposed in the NOPR improperly reduce or even

eliminate encouragement in contravention of the statute. Those commenters opposing the 

NOPR proposals argue that the Commission has determined, in contravention of the 

statute, that there no longer is a need to encourage QFs, or eliminated any provision that
Docket Nos. RM19-15-000 and AD16-16-000 - 10 -

provides such encouragement.7 Many of the commenters supporting the changes 

proposed in the NOPR applaud the Commission for eliminating what they argue amounts 

to an improper subsidy of QFs.

8

8. Neither side is correct about either what PURPA and the current PURPA 

Regulations require, or the basis for the changes to the PURPA Regulations proposed in 

the NOPR. 

9. As an initial matter, PURPA was not a directive to the Commission to encourage 

QF development without limitation. Indeed, as explained below, Congress included 

several limitations in PURPA. By reading the statute as a whole, and the PURPA 

Regulations as a whole as revised by this final rule, it is clear that the PURPA Regulations 

continue to encourage the development of QFs consistent with PURPA.9

10. We also emphasize that we do not by this final rule change other elements to the 

Commission’s existing PURPA Regulations that continue to encourage QF development. 

These elements include, but are not limited to, rules that: (1) require electric utilities to 

provide backup electric energy to QFs on a non-discriminatory basis and at just and 

7 See, e.g., Biological Diversity Comments at 14; ConEd Development Comments 

at 2; Harvard Electricity Law Comments at 4; New England Small Hydro Comments at 4; 

NIPPC, CREIA, REC, and OSEIA Comments at 3, 21, 28; Public Interest Organizations 

Comments at 9, 39; Solar Energy Industries Comments at 4; Southeast Public Interest 

Organizations Comments at 17.

8 See Competitive Enterprise Institute Comments at 3; Progressive Policy Institute 

Comments at 1-2; SBE Council Comments at 2; Mr. Moore Comments at 1-2.

9 16 U.S.C. 824a-3(a).
Docket Nos. RM19-15-000 and AD16-16-000 - 11 -

reasonable rates; (2) require electric utilities to interconnect with QFs; and (3) provide 

exemptions to QFs from many provisions of the Federal Power Act (FPA) and state laws

governing utility rates and financial organization.10 These provisions encourage the 

development of QFs by relieving them of certain regulatory burdens otherwise imposed on 

sellers of power and ensure they can operate their facilities. Moreover, we stress that, 

besides the changes to the PURPA Regulations regarding applications to terminate a 

purchasing electric utility’s mandatory purchase obligation under PURPA section 210(m) 

(see infra section IV.G), nothing in this final rule eliminates QFs’ rights to sell electric 

energy or capacity as provided under PURPA.

11. As discussed in greater detail below, while PURPA provided for the 

encouragement of cogeneration and small power production, PURPA also provided that 

the Commission could not prescribe a rule that provided for “a rate which exceeds the 

incremental cost to the electric utility of alternative electric energy.”11 Furthermore, 

PURPA requires the Commission to “insure” that the resulting rates “shall be just and 

reasonable to the electric consumers of the electric utility and in the public interest[.]”12 

Likewise, while PURPA provided for the encouragement of small power production, 

10 See 18 CFR 292.303(c), 292.305, 292.601-02.

11 Compare id. with 16 U.S.C. 824a-3(b).

12 16 U.S.C. 824a-3(b)(1).
Docket Nos. RM19-15-000 and AD16-16-000 - 12 -

PURPA also limited the facilities which could be encouraged to those facilities with no 

more than 80 MW power production capacity at the same site.

13

12. Nothing in the text of PURPA requires the establishment of a subsidy for QFs. 

This point was confirmed in the Conference Report accompanying PURPA’s passage: 

“The provisions of this section are not intended to require the rate payers of a utility to 

subsidize cogenerators or small power producers.”14 Congress thus structured PURPA 

both specifically to give effect to its intent that QFs not be subsidized and also to impose 

other mandatory limits on the Commission’s ability to encourage QFs that are relevant to 

this final rule, as briefly summarized below.

1. Avoided Cost Cap on QF Rates

13. PURPA section 210(b) sets out the standards governing the rates purchasing 

utilities must pay to QFs.15 Sections 210(b)(1) and (b)(2) provide that QF rates “shall be 

just and reasonable to the electric consumers of the electric utility and in the public 

interest” and “shall not discriminate against qualifying cogenerators or qualifying small 

power producers.”16 After establishing these standards, Congress then placed, in the final 

sentence of section 210(b), a cap on the level of the rates utilities could be required to pay 

QFs: “No such rule prescribed under subsection (a) shall provide for a rate which exceeds 

13 Compare 16 U.S.C. 824a-3(a) with 16 U.S.C. 796(17)(A)(ii).

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

15 16 U.S.C. 824a-3(b).

16 Id.
Docket Nos. RM19-15-000 and AD16-16-000 - 13 -

the incremental cost to the electric utility of alternative electric energy.”17 As the 

Conference Report for PURPA 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.18

14. This upper limit on QF rates established in section 210(b), equal to a purchasing 

utility’s incremental costs, commonly called “avoided costs,” implements Congress’s

intent that QFs not be subsidized. It ensures that the purchasing utility cannot be required 

to pay more for power purchased from a QF than it would otherwise pay to generate the 

power itself or to purchase power from a third party. 

15. Consistent with the statutory standard, when the Commission issued its PURPA 

Regulations in 1980, it set the rates for QFs at, but not above, the statutorily defined 

incremental or avoided cost of alternative electric energy.

19 The PURPA Regulations 

17 Id. (emphasis added). The statute defines an electric utility’s “incremental costs” 

as “the cost to the electric utility of the electric energy which, but for the purchase from 

such cogenerator or small power producer, such utility would generate or purchase from 

another source.” 16 U.S.C. 824a-3(d); see also 18 CFR 292.101(b)(6) (implementing 

same and defining such “incremental costs” as “avoided costs”).

18 Conf. Rep. at 98 (emphasis added). 

19 Compare 16 U.S.C. 824a-3(b) & (d) with 18 CFR 292.101(b)(6), 292.304(a)(2)

& (b)(2).
Docket Nos. RM19-15-000 and AD16-16-000 - 14 -

applied this limitation generally to QF rates, without distinguishing between as-available 

energy20 and the fixed energy and capacity rate option applicable to long-term contracts or 

other legally enforceable obligations.

21 In either case, though, the PURPA Regulations 

essentially capped the rate paid to QFs at the purchasing electric utility’s avoided costs.22

16. Order No. 69, in which the Commission promulgated the PURPA Regulations,23

makes clear that the Commission also recognized that allowing the option for a fixed 

energy and capacity rate option for long-term contracts or other legally enforceable 

obligations could result in a rate that, at times, exceeded incremental or avoided cost of 

alternative electric energy. The Commission acknowledged in this regard that some 

commenters had asserted that, “if the avoided cost of energy at the time it is supplied is 

less than the price provided in the contract or obligation, the purchasing utility would be 

20 18 CFR 292.304(d)(1).

21 18 CFR 292.304(d)(2) (providing QFs the right to elect avoided costs calculated 

at the time of delivery or avoided costs calculated at the time the obligation is incurred). 

In this final rule, we refer to the QF’s option for avoided costs calculated at the time the 

obligation is incurred as the fixed energy and capacity rate option. 18 CFR 292.304(d)(2).

22 The regulations, however, also allowed both for negotiated rates that differed 

from the rates that would otherwise be applicable, see 18 CFR 292.301(b), and for rates to 

be set based on estimates of avoided costs even though such rates might differ from 

avoided costs at the time of delivery. See 18 CFR 292.304(b)(5).

23 Small Power Production and Cogeneration Facilities; Regulations Implementing 

Section 210 of the Public Utility Regulatory Policies Act of 1978, Order No. 69, FERC 

Stats. & Regs. ¶ 30,128, at 30,880 (cross-referenced 10 FERC ¶ 61,150), order on reh’g, 

Order No. 69-A, FERC Stats. & Regs. ¶ 30,160 (1980) (cross-referenced at 11 FERC 

¶ 61,166), aff’d in part & vacated in part sub nom. Am. Elec. Power Serv. Corp. v. FERC, 

675 F.2d 1226 (D.C. Cir. 1982), rev’d in part sub nom. Am. Paper Inst., Inc. v. Am. Elec. 

Power Serv. Corp., 461 U.S. 402 (1983) (API).
Docket Nos. RM19-15-000 and AD16-16-000 - 15 -

required to pay a rate for purchases that would subsidize the qualifying facility at the 

expense of the utility's other ratepayers.”24 In response, the Commission stated that it 

“recognize[d] this possibility, but is cognizant that in other cases, the required rate will 

turn out to be lower than the avoided cost at the time of purchase.”25 The Commission 

concluded that any over- and under-recoveries compared to avoided cost “will balance 

out” and, based on this conclusion, found that the fixed energy and capacity rate option 

applicable to long-term contracts or other legally enforceable obligations did not violate 

the statutory cap.26 But, to be clear, the option the Commission implemented in 1980 was 

not based on any determination by the Commission that the rates in QF contracts may

routinely exceed avoided costs in the ordinary course of events in order to encourage QFs.

2. Limitation on Small Power Production Facilities Located at the 

Same “Site”

17. Another way in which Congress set boundaries on the Commission’s ability to 

encourage development of QFs was to define small power production facilities, one of the 

categories of generators that under the statute is to be encouraged. The definition of small 

power production facilities applies to almost all renewable resources that wish to be QFs, 

requiring that those facilities have “a power production capacity which, together with any 

other facilities located at the same site (as determined by the Commission), is not greater 

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

25 Id.

26 Id.
Docket Nos. RM19-15-000 and AD16-16-000 - 16 -

than 80 megawatts.”27 In order to comply with this statutory requirement that the capacity 

of all small power production facilities “located at the same site” cannot exceed 80 MW, 

the Commission is required to define what constitutes a “site.” The Commission 

determined in 1980 that, essentially, those facilities that are owned by the same or 

affiliated entities and using the same energy resource should be deemed to be at the same 

site “if they are located within one mile of the facility for which qualification is sought.”28 

This definition, known as the “one-mile rule,” interpreted Congress’s limitation of 80 MW 

located at the same site to apply to just those affiliated small power production qualifying 

facilities located within one mile of each other.

3. Termination of Purchase Obligation for QFs With 

Nondiscriminatory Access to Certain Competitive Markets 

18. Finally, Congress amended PURPA in 2005 to further limit the statute. Congress 

amended PURPA section 210 to add section 210(m), which provides for termination of 

the requirement that an electric utility enter into a new obligation or contract to purchase 

from a QF if the QF has nondiscriminatory access to certain defined types of markets.29 

This amendment reflected Congress’s judgment that non-discriminatory access to these 

markets provided adequate encouragement for those QFs. 

19. Congress directed the Commission to implement this requirement, which it did in 

Order No. 688. In that order, the Commission identified certain markets in which utilities 

27 16 U.S.C. 796(17)(A)(ii).

28 18 CFR 292.204(a)(ii).

29 See 16 U.S.C. 824a-3(m).
Docket Nos. RM19-15-000 and AD16-16-000 - 17 -

would no longer be subject to the PURPA mandatory purchase obligation under PURPA 

section 210(m) because certain QFs have nondiscriminatory access to such markets.30 

Although not required in the new PURPA section 210(m), the Commission established a 

rebuttable presumption that a QF with a net power production capacity at or below 20 

MW does not have nondiscriminatory access to such markets.31 In creating this rebuttable 

presumption, the Commission found persuasive arguments that some QFs may not have 

nondiscriminatory access to markets in light of their small size. 

4. Final Rule’s Updating of the PURPA Regulations 

20. In this final rule, we are amending the PURPA Regulations, principally with regard 

to the three statutory provisions described above, i.e.: (1) the avoided cost cap on QF 

rates; (2) the 80 MW limitation applicable to the combined capacity of affiliated small 

power production QFs located at the same site; and (3) the termination of the mandatory 

purchase obligation for QFs with nondiscriminatory access to certain markets. Contrary 

to commenters’ assertions that the Commission has determined that it no longer is 

necessary to encourage QFs and therefore that the Commission is making these changes in 

an impermissible attempt to undo PURPA,32 we are modifying the PURPA Regulations 

30 New PURPA Section 210(m) Regulations Applicable to Small Power Production 

and Cogeneration Facilities, Order No. 688, 117 FERC ¶ 61,078, at PP 9-12 (2006), order 

on reh’g, Order No. 688-A, 119 FERC ¶ 61,305 (2007), aff’d sub nom. Am. Forest & 

Paper Ass’n v. FERC, 550 F.3d 1179 (D.C. Cir. 2008).

31 18 CFR 292.309(d)(1).

32 Biomass Power Comments at 2; Biological Diversity at 12; EPSA Comments at 

6 (“[T]he NOPR changes ‘would effectively gut’ PURPA.”); NIPPC, CREA, REC, and 

OSEIA Comments at 28-29; Public Interest Groups Comments at 25 (“[T]he changes 
Docket Nos. RM19-15-000 and AD16-16-000 - 18 -

based on demonstrated changes in circumstances since the current PURPA Regulations 

were first adopted to ensure that the regulations continue to comply with PURPA’s 

statutory requirements established by Congress. 

21. For example, as explained in more detail below, the Commission’s expectation

expressed in 1980 that over- and under-recovery in rates compared to avoided cost “will 

balance out”33 was critical to the Commission’s determination in 1980 that the fixed 

energy and capacity rate option applicable to long-term contracts or other legally 

enforceable obligations did not violate the statutory avoided cost cap on QF rates. 

However, record evidence now demonstrates that this expectation no longer is necessarily 

accurate. The Commission’s change to the PURPA Regulations adopted in this final rule, 

giving states the ability to require variable energy rates in long-term contracts or other 

legally enforceable obligations, allows the states to better ensure that QF rates are at, but 

do not exceed, the statutory maximum rate established by Congress.

22. This change is important for purposes of compliance with PURPA’s statutory 

mandates. As explained below, setting QF rates at avoided costs allows the Commission 

to comply with the statutory goals of encouraging QFs and providing for 

nondiscriminatory rates while at the same time ensuring that such rates are just and 

reasonable to consumers and do not subsidize QFs. The record shows that on some 

proposed in the NOPR will gut PURPA-mandated measures to encourage QF 

development.”); Solar Energy Industries Comments at 8-14.

33 Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,880.
Docket Nos. RM19-15-000 and AD16-16-000 - 19 -

occasions long-term fixed QF rates were well above actual avoided costs, thereby causing 

consumers to subsidize those QFs in contravention of PURPA and the Commission’s 

expectations. 

23. Similarly, the changes implemented by the Commission in this final rule to the onemile rule are intended to better ensure compliance with the statutory requirement that 

small power production facilities located at the same site cannot exceed 80 MW. And, 15

years after Congress added PURPA section 210(m), because the Commission can now 

make the determination, described below, that smaller QFs have non-discriminatory 

access to RTO/ISO markets, an update to the rebuttable presumption regarding nondiscriminatory access to those markets is appropriate to better ensure compliance with the 

statute.

24. Some commenters incorrectly assert that the final rule impermissibly revises the 

PURPA Regulations in a way that no longer encourages QFs. PURPA section 210(a) 

provides not simply that the Commission is to prescribe rules that encourage QFs, but 

rather that the Commission is to “prescribe, and from time to time thereafter revise, such 

rules as it determines necessary to encourage” QFs. Carrying out Congress’s directive to 

“from time to time thereafter revise” the rules is at the heart of what the Commission is 

doing in this final rule. Consistent with this directive, the Commission is considering 

revisions to “such rules as it determines necessary to” encourage QFs in light of current 

industry circumstances.34 

34 We view the revisions to our rules implementing PURPA that we adopt in this 

final rule as consistent with Congress’s explicit directive that the Commission “from time 
Docket Nos. RM19-15-000 and AD16-16-000 - 20 -

25. The changes adopted in this final rule result from the need for the PURPA 

Regulations to continue to comply with the directives Congress established when it 

enacted PURPA in 1978, and then again when Congress amended PURPA in 2005. These

changes are not based on any determination by the Commission that the encouragement 

directed by PURPA is no longer needed. The question of whether QFs should continue to 

be encouraged or not remains a question for Congress. 

26. Moreover, PURPA also requires the Commission to insure that the rates for QF

purchases be “just and reasonable to the electric consumers of the electric utility and in the 

public interest[.]”35 The obligation to encourage is also limited by the requirement that,

“No such rule prescribed under subsection (a) [the encouragement provision] shall provide 

for a rate which exceeds the incremental cost to the electric utility of alternative electric 

energy.”36

27. We recognize that some of the comments opposing the NOPR may have been 

influenced by the Commission’s recitation in the Background section of the NOPR of the 

broad changes in circumstances since the PURPA Regulations were first promulgated 40 

years ago, including the discovery of significant new natural gas reserves, the evolution of 

the electric industry to include a significant independent power presence, the 

to time thereafter [to] revise” the rules. We do not view Congress as intending that the 

Commission only ever consider the circumstances that existed in the late 1970s and not 

current circumstances, 40 years later. 

35 16 U.S.C. 824a-3(b).

36 16 U.S.C. 824a-3(b).
Docket Nos. RM19-15-000 and AD16-16-000 - 21 -

establishment of organized competitive markets, and the advances in renewable energy 

technologies.37 We clarify that the Commission referenced this general background 

information in the NOPR primarily to explain why it decided to re-evaluate its PURPA 

Regulations at all and as Congress said we should, and not necessarily to support the 

individual proposals included in the NOPR. The facts we rely on to propose specific 

changes, which include some, but not all, of those background facts, were cited in the 

specific sections of the NOPR describing those proposed changes. And the facts on which 

we rely to promulgate the specific changes in this final rule again are cited in the specific 

sections describing those changes.

B. The Final Rule Ensures that the Commission’s Implementation of 

PURPA Continues to Benefit QFs, Purchasing Electric Utilities, and 

Electric Consumers

28. The final rule implements additional changes consistent with PURPA that also are 

designed to benefit QFs, purchasing utilities, and electric consumers. The changes to the 

PURPA Regulations adopted in this final rule will enable the Commission to continue 

satisfying the statutory requirement that the Commission promulgate rules to encourage 

QF development consistent with PURPA’s requirements. Claims to the contrary by 

commenters to the effect that the “proposals are uniformly biased against QF 

development”38 have no merit.

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

38 Harvard Electricity Law Comments at 1.
Docket Nos. RM19-15-000 and AD16-16-000 - 22 -

29. As an initial matter, we are not changing the determination in the PURPA 

Regulations that QF rates must equal a purchasing electric utility’s full avoided costs.

39 

As the Supreme Court noted in API, the full avoided cost rate requirement represents the 

maximum rate permitted under PURPA, and thereby provides important encouragement to 

QFs.40 The Court explained that the full avoided cost rate requirement encourages QF 

development because QFs “retain an incentive to produce energy under the full-avoidedcost rule so long as their marginal costs did not exceed the full avoided cost of the 

purchasing utility.”41 

30. In addition, several of the changes to the current PURPA Regulations implemented 

by this final rule are based expressly on a finding that they are beneficial to QFs as well as 

to purchasing utilities and ratepayers. For example, the provisions of the final rule

allowing for energy rates to be based on transparent, competitive market prices—in 

appropriate circumstances—are supported by comments submitted at the Technical 

Conference, where representatives of QFs and utilities both expressed a preference for 

39 See 18 CFR 292.304(b)(2); NOPR, 168 FERC ¶ 61,184 at P 34.

40 API, 461 U.S. at 413. PURPA does not use the terms “avoided cost” or “full 

avoided cost”; rather, PURPA uses the term “incremental cost of alternative electric 

energy.” The Commission’s regulations and subsequent decisions have used the term 

“avoided cost” to explain the Commission’s application of the “incremental cost” 

standard. The API decision and early Commission precedents referred to “full” avoided 

costs to distinguish between the Commission’s decision to set QF rates at avoided costs 

and proposals from certain parties that rates be set at something less than avoided costs. 

We continue to use the terms avoided costs and full avoided costs as being consistent with 

the statutory term incremental cost.

41 Id. at 416.
Docket Nos. RM19-15-000 and AD16-16-000 - 23 -

transparent prices for QFs.42 This conclusion is supported by the Fitch Report, cited by 

NIPPC, CREA, REC, and OSEIA, explaining how Fitch evaluates the financial strength of 

renewable energy projects. In this report, Fitch states that it gives a “stronger” evaluation 

to projects with power sales contract prices that are “indexed using simple, broad-based 

publicly available indexation formulas.”43 

31. Setting prices that are indexed using simple, broad-based publicly available 

formulas is precisely what the Commission’s changes permitting reference to competitive 

market prices will achieve. Such prices reflect avoided costs in a simpler, more 

transparent, and predictable manner than through an administrative process, which should 

encourage the development of QFs while at the same time providing benefits to utilities 

and consumers. Using transparent market prices to establish as-available avoided cost 

rates also allows QFs, utilities, and the states to avoid the expenditure of the time and 

resources involved in litigating administratively-set avoided cost rates, and allows those 

rates to automatically adjust—up and down—as avoided costs change. 

42 See American Forest & Paper Association, Comments, Docket No. AD16-16-

000, at 8 (filed June 8, 2016) (“To the extent possible, these determinations [of avoided 

costs] should not be made in a ‘black box’, but rather, as part of an open and transparent 

method and process.”); Edison Electric Institute (EEI) Comments, Docket No. AD16-16-

000, at 3 (filed June 30, 2016) (“Where transparent competitive markets with day ahead 

prices exist, there is no reason to adhere to second-best avoided cost pricing 

mechanisms.”).

43 NIPPC, CREA, REC, and OSEIA Comments at 37-38 (citing FitchRatings, 

Global Infrastructure & Project Finance, Renewable Energy Project Rating Criteria,” at 3

(Feb. 26, 2019), https://www.fitchratings.com/site/re/10061770).
Docket Nos. RM19-15-000 and AD16-16-000 - 24 -

32. Similarly, the provisions regarding competitive solicitations adopted herein were 

added at the suggestion of both NARUC and certain developers of renewable resource 

QFs, such as Solar Energy Industries. These competitive solicitations can provide a fair 

and transparent method for QFs to establish full avoided cost rates. As Solar Energy 

Industries stated in its comments, “[c]ompetitive solicitations, with adequate safeguards, 

can deliver substantial value.”44 Competitive solicitations may be an especially 

appropriate tool in those regions outside of Regional Transmission Organizations (RTOs) 

and Independent System Operators (ISOs) where there are no organized competitive 

markets where QFs can make sales.

33. Likewise, the LEO provisions adopted herein provide important benefits to QFs. 

Under the current PURPA Regulations, a LEO gives QFs the enforceable right to require 

utilities to purchase the QFs’ power at avoided cost rates.

45 This is an important right that 

contributes to a QF owner’s ability to obtain financing, especially the development 

financing needed to engage in the activities necessary to subsequently obtain construction 

44 Solar Energy Industries Comments at 38. Solar Energy Industries agreed that the 

competitive solicitation provisions proposed in the NOPR “set forth many important 

safeguards,” but recommended that additional safeguards be implemented. Those 

comments are discussed below, and we have specifically adopted Solar Energy Industries 

request made earlier in this proceeding that all competitive solicitations must be conducted 

pursuant to the Commission’s Allegheny standard. See Solar Energy Industries 

Supplemental Comments, Docket No. AD16-16-000, at 32-34 (filed Aug. 28, 2019).

45 See 18 CFR 292.304(d)(2). Although the final rule gives states the flexibility to 

require that energy rates vary over the term of the LEO and be calculated at the time of 

delivery, the final rule retains the QF’s option to choose a fixed capacity rate calculated at 

the time the LEO is established.
Docket Nos. RM19-15-000 and AD16-16-000 - 25 -

and permanent financing. However, the PURPA Regulations are silent as to when and 

how a LEO is established, which can leave QFs uncertain as to when this key right has 

been established. By providing more specific guidance as to when a LEO is established, 

the new rule creates greater certainty for QFs (and utilities) on this important element of 

QF development. 

34. Some commenters assert that the guidance provided by the Commission may make 

it more difficult to obtain a LEO.46 Their specific concerns are discussed in detail below. 

But what those commenters ignore is that, by establishing objective and reasonable statedetermined criteria limited to demonstrating commercial viability and financial 

commitment, we also are protecting QFs against onerous requirements for a LEO that 

hinder financing, such as a requirement for a utility’s execution of an interconnection 

46 See NIPPC, CREA, REC, and OSEIA Comments at 81 (“[A]ny requirement to 

demonstrate financing to create a LEO violates the fundamental rule that the utility’s 

actions should not be allowed to deny the QF a LEO because the utility could prevent 

creation of a LEO simply by refusing to sign the PPA needed to secure such financing.”); 

Public Interest Organizations Comments at 98 (“[T]he Commission’s proposal to require 

QFs to demonstrate commercial viability in order to obtain a LEO will prevent many QFs 

from ever attaining commercial viability at all. Creating a new administrative obstacle to 

QF financing in this way flies in the face of PURPA’s mandate to reduce barriers to QF 

development.”); Solar Energy Industries Comments at 41 (“Establishing higher barriers to 

a determination of ‘commercial viability’ will only lead QF developers to invest additional 

development capital and will simply weed out those smaller companies that choose not to, 

or are unable to, invest heavily in early-stage development activity before an avoided cost 

rate is known. It is unjust and unreasonable to cause QFs to invest tens of millions of 

dollars in site control, permit acquisition, interconnection, and other development costs 

simply to secure the opportunity to negotiate with the purchasing utility for a contractual 

commitment.”); Southeast Public Interest Organizations Comments at 41 (describing 

proposal as “discourag[ing] QF development since achieving some of the indicia 

suggested by the Commission often circularly requires that QF developers have already

obtained financing”).
Docket Nos. RM19-15-000 and AD16-16-000 - 26 -

agreement47 or power purchase agreement,48 or requiring that QFs file a formal complaint 

with the state commission,49 or limiting LEOs to only those QFs capable of supplying firm 

power,50 or requiring the QF to be able to deliver power in 90 days.51 By making clear in 

the PURPA Regulations that such conditions are not permitted, but describing which

prerequisites a state may impose to establish a LEO to determine which QFs are 

commercially viable and financially committed, we are providing objective criteria to 

clarify when a LEO commences, which we find will encourage the development of QFs.

C. The Commission is Not Eliminating Fixed Rate Pricing for QFs, But 

Rather is Giving States the Flexibility to Require the Same Variable 

Energy Rate/Fixed Capacity Rate Construct that Applies Throughout 

the Electric Industry

35. Another misconception reflected in several comments is that the Commission 

proposed in the NOPR to eliminate fixed rate pricing for QFs. Commenters argue that 

QFs cannot obtain financing without fixed rates, and from this they claim that the proposal 

47 See, e.g., FLS Energy, Inc., 157 FERC ¶ 61,211, at P 26 (2016) (FLS) (stating 

that requiring signed interconnection agreement as prerequisite to LEO is inconsistent 

with PURPA Regulations).

48 See, e.g., Murphy Flat Power, LLC, 141 FERC ¶ 61,145, at P 24 (2012) (finding 

that requiring a signed and executed contract with an electric utility as a prerequisite to a 

LEO is inconsistent with PURPA Regulations.

49 See, e.g., Grouse Creek Wind Park, LLC, 142 FERC ¶ 61,187, at P 40 (2013).

50 Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380, 400 (5th Cir. 2014).

51 Power Resource Group, Inc. v. Public Utility Comm’n of Texas, 422 F.3d 231, 

(5th Cir. 2005).
Docket Nos. RM19-15-000 and AD16-16-000 - 27 -

to give states the flexibility to require variable energy rates would have a devastating 

effect on future QF development.52 

36. This assertion that the Commission has eliminated fixed rates for QFs is not 

correct. The NOPR proposal (which we adopt in this final rule) gave states the flexibility,

should they choose to take advantage of this flexibility, to require that the avoided cost

energy rates in QF contracts must vary depending on avoided costs at the time of delivery 

(rather than being fixed at the time a LEO is incurred). The NOPR thus made clear: 

“under the proposed revisions to § 292.304(d), a QF would continue to be entitled to a 

contract with avoided capacity costs calculated and fixed at the time the LEO is 

incurred.”53 We are retaining in this final rule the option granted to QFs to fix their 

capacity rates for the term of their contracts at the time the LEO is incurred.

37. The fact that we are giving states the flexibility to either require QF contracts to

have fixed capacity and variable energy rates or to continue as before to provide QFs the 

option of fixed capacity and fixed energy rates – has important consequences for the 

ability of QF owners to finance their projects. The energy rates of purchasing electric 

utilities, upon which avoided cost energy rates would be based, typically reflect mainly 

the variable costs of producing energy, such as the cost of fuel and variable operations and 

52 See, e.g., Public Interest Organizations Comments at 35-38 (allowing variable 

rates will further discourage wind and solar QF development); Allco Comments at 9-11 

(without the ability to obtain a fixed long-term forecasted rate, QF solar energy 

development will not exist).

53 See NOPR, 168 FERC ¶ 61,184 at P 66. 
Docket Nos. RM19-15-000 and AD16-16-000 - 28 -

maintenance (O&M), especially for a fossil fuel generator. Meanwhile, a purchasing 

electric utility’s capacity rates, upon which avoided cost capacity rates would be based,

tend to reflect fixed costs, including the financing costs of facilities (i.e., debt repayment 

and a return on the equity invested in the facility).54 Consequently, a fixed capacity rate in 

a QF contract based on a purchasing electric utility’s capacity rates should typically be 

sufficient to recover the QF’s financing costs and should therefore continue to facilitate 

QF financing. We recognize that a QF’s financing costs may be different from the 

purchasing electric utility’s avoided costs and, therefore, the full avoided cost rate that the 

QF receives may not support the financing of a QF. But this is a consequence of how 

Congress structured PURPA, which sets rates based on the avoided costs of the 

purchasing utility rather than on the actual costs the QF incurs producing the power being 

sold.55

38. Another important aspect of the variable energy rate/fixed capacity rate construct is 

that this is the standard rate structure used throughout the electric industry for power sales 

agreements that include the sale of capacity.56 That states will be allowed to require QF 

54 See Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,865.

55 See API, 461 U.S. at 414, 415 (stating that “Congress did not intend to impose 

traditional ratemaking concepts on sales by qualifying facilities to utilities” and that QFs 

“would retain an incentive to produce energy under the full-avoided-cost rule so long as 

their marginal costs did not exceed the full avoided cost of the purchasing utility”).

56 Cf. Town of Norwood v. FERC, 962 F.2d 20, 21, 24 (D.C. Cir. 1992) (“The rate 

design before us, like most wholesale electric rates, consists of separate monthly demand 

and energy charges. The demand component is calculated to recover NEPCO’s fixed (or

capacity-related) costs, such as construction and debt service, which it incurs regardless of 

how much electricity it produces. The energy charge is designed to recover the 
Docket Nos. RM19-15-000 and AD16-16-000 - 29 -

contracts to be structured similarly to the contract structure used in the rest of the electric 

industry has important implications. In particular, this provides flexibility to states to 

ensure that the avoided cost rate will be closer to the actual rate the purchasing electric 

utility and its customers would have paid if the purchasing electric utility had generated 

this electric energy itself or purchased such electric energy from another source. 

Furthermore, the record evidence demonstrating significant amounts of non-QF generation 

facilities in operation today shows that the owners of such facilities are able to obtain 

financing based on this same variable energy rate/fixed capacity rate construct.

57 This 

represents important evidence that QFs likewise should be able to obtain financing under 

the same rate construct, especially considering that QFs benefit from the statutory right to 

sell pursuant to a mandatory purchase obligation while non-QFs do not have that right.

58

company’s variable costs, which it incurs only in the course of actually producing 

electricity; fuel is a prime example. . . . With the cost outlook constantly in flux due to 

changing economic conditions, some degree of volatility is necessary if prices are to 

signal the market accurately—as accurately, that is, as current prices can anticipate future 

costs. Price volatility alone, therefore, cannot provide a ground for overturning a marginal 

cost rate structure.”).

57 EIA, Form EIA-860 detailed data with previous form data Early Release (EIA860A/860B) (June 2, 2020), https://www.eia.gov/electricity/data/eia860/ shows 77.6 GW 

of operational QF nameplate capacity and 450.453.5 GW of operational non-QF 

independent power producer nameplate capacity as of end 2019. 

58 Some commenters raise concerns with the Commission’s reliance on the 

financing of non-QF generation facilities to support the conclusion that QFs could obtain 

financing with variable energy rate contracts, pointing out that the Commission has not 

identified any QFs that have obtained financing under this structure. The reason for this, 

however, is that QFs typically do not employ this structure because currently they are 

entitled to a fixed energy rate/fixed capacity rate construct. Accordingly, evidence 

regarding the financing of similar types of independently owned generation projects by 

non-QFs using such a construct constitutes the best and most relevant evidence of how it 
Docket Nos. RM19-15-000 and AD16-16-000 - 30 -

D. The Rate Changes Implemented by this Final Rule Put QF Rates on the 

Same Footing as Electric Utility Rates and Are Not Discriminatory

39. The fact that variable energy rate/fixed capacity rate contracts are standard in the 

electric industry also explains why, contrary to assertions made by a number of 

commenters, allowing states to require such contracts for QFs is not discriminatory.59 

QFs selling at wholesale pursuant to such contracts will be selling under the same rate 

structure employed in the power sales contracts typically used elsewhere in the electric 

industry, including by public utilities when they make sales at wholesale to each other, 

and QFs will be doing so at full avoided cost rates—the highest rates permitted under 

PURPA. 

40. It is true that electric utilities with franchised service territories that make sales at 

retail are often effectively guaranteed the recovery of their energy costs in their retail rates

by their state regulatory authorities—provided that such costs are prudently incurred. But 

the electric utilities’ retail rates are cost-based, such that their rates are set based on costs 

they actually incur to produce electricity for their customers. Importantly, moreover, the

incremental energy costs that an electric utility will recover from its retail customers at an 

would affect QF financing.

59 See, e.g., EPSA Comments at 9 (“The NOPR avoided rate proposal must 

therefore be rejected because it puts QFs at a disadvantage to utility-owned generation, in 

violation of the non-discrimination mandate under PURPA.”); Public Interest 

Organizations Comments at 51 (“[L]imiting QFs to contracts providing no price certainty 

for energy values, while non-QF generation regularly obtains fixed price contracts and 

utility-owned generation receives guaranteed cost recovery from captive ratepayers, 

constitutes discrimination.”).
Docket Nos. RM19-15-000 and AD16-16-000 - 31 -

incremental level would be the same energy costs that are used in determining the electric

utilities’ avoided costs that will, in turn, set the as-available avoided cost rates to be 

charged by QFs.

41. Thus, QF variable energy rate/fixed capacity rate contracts not only would be 

structured similarly to the standard wholesale power sales agreements used in the electric 

industry, but application of traditional cost-based ratemaking principles to sales by QFs is 

exactly what would be required in order to provide QFs with the same guaranteed cost 

recovery that applies to electric utilities. Guaranteeing QFs cost recovery is 

fundamentally inconsistent with PURPA, which sets the rate the QF is paid at the

purchasing electric utility’s avoided cost, not at the QF’s cost. Such a rate structure is not 

discriminatory.

E. The PURPA Compliance Issues Raised by Some Commenters Are 

Outside the Scope of this Rulemaking Proceeding

42. Finally, several commenters assert that certain states located outside of RTO/ISO 

markets are dominated by large integrated public utilities whose state commissions do not 

implement PURPA correctly.60 They argue that, as a consequence, there is little 

development of independent generation—QFs or otherwise—in those states. They assert 

that the proposals in the NOPR might be appropriate in states with RTO/ISO markets that 

60 American Dams Comments at 5-6; Biological Diversity Comments at 13; CA 

Cogeneration Comments at 6-7; Con Edison Comments at 2; ELCON Comments at 7-8; 

EPSA Comments at 1-2; IdaHydro Comments at 5; NIPPC, CREA, REC, and OSEIA 

Comments at 14-15; Solar Energy Industries Comments at 15-20, 24; SC Solar Alliance 

Comments at 3-4; Two Dot Wind Comments at 14-19.
Docket Nos. RM19-15-000 and AD16-16-000 - 32 -

are subject to significant competition, but would only make matters worse outside of the 

RTO/ISO markets. 

43. As explained above, several changes implemented by this final rule ensure that the 

PURPA Regulations will continue to encourage QF development. Other changes, such as 

allowing variable energy rates in QF contracts, not only ensure the PURPA Regulations 

are consistent with PURPA but also address some states’ primary concern with the current 

PURPA Regulations, i.e., the Commission’s now allowing states the flexibility to set 

variable energy rates could mitigate the states’ reluctance to implement PURPA in a way 

that better encourages development of QFs. For example, the Idaho Commission has 

indicated that its current policy of limiting QF contracts to two years is based on its 

concern about fixed QF rates, and that the ability to require variable energy rates could 

lead to longer contract terms.61 We expect that these changes could facilitate QF 

development in states where little QF capacity has been added to date.

44. Further, commenters’ claims about lack of QF development outside of the 

RTO/ISO markets appear to be overstated. For example, the most recent data from the 

U.S. Energy Information Administration (EIA) on the total amount of wind and solar QF 

capacity in each state shows that 9 of the 20 states with the greatest combined wind and 

61 See Idaho Commission Comments at 4 (stating that an energy rate established at 

the time of contract formation that provides for “revisions to the energy rate at regular 

intervals, consistent with, for example, a purchasing electric utility’s [integrated resource 

plan] to reflect updated avoided cost calculations” would allow states to consider longer 

term contracts without putting ratepayers at risk).
Docket Nos. RM19-15-000 and AD16-16-000 - 33 -

solar QF capacity are located outside of the RTO/ISO markets.62 Of these 9 states, three 

are located in the Southeast—the region asserted by commenters to be the most hostile to 

PURPA—including North Carolina, which has the highest total amount of wind and solar 

QF capacity in the country.63 Other states in the top 20 include Idaho—with the fourth 

most wind and solar QF capacity—and Oregon,

64 two states that have been criticized as 

being hostile to PURPA. EIA data also shows that five of the top 10 states in terms of 

renewable QF capacity additions from 2008-17 are located outside of the RTO/ISO 

markets, including North Carolina (with the most renewable QF capacity additions), 

Idaho, Georgia, and Oregon,65 each of which commenters have identified as being hostile 

to PURPA. 

45. But whether any individual state has or has not failed to implement the PURPA 

Regulations properly is not an issue for this final rule, which implements changes to the 

62 EIA, Form EIA-860 detailed data with previous form data (EIA-860A/860B) 

Release date (June 2, 2020), https://www.eia.gov/electricity/data/eia860/. The top 

20 states with combined QF solar and wind nameplate capacity in 2018 were:

(1) California, Texas, Minnesota, Oklahoma, Massachusetts, New Mexico, Nebraska, 

New Jersey, Michigan, New York, Illinois (all fully or partially inside RTOs/ISOs); and 

(2) North Carolina, Idaho, Utah, South Carolina, Georgia, Oregon, Colorado, Arizona, 

Wyoming(outside of RTOs/ISOs). We note that some of these states are located in both 

RTO/ISO and non-RTO/ISO regions.

63 Id. We note that five of the 20 states with the most solar capacity—perhaps a 

better measure of the Southeast Region’s PURPA compliance given the lack of wind 

resources in this region—are located in the Southeast.

64 Id.

65 See EIA, PURPA-qualifying capacity increases, but it’s still a small portion of 

added renewables (Aug. 16, 2018), 

https://www.eia.gov/todayinenergy/detail.php?id=36912. 
Docket Nos. RM19-15-000 and AD16-16-000 - 34 -

PURPA Regulations but does not modify Commission’s rules for addressing claims that 

states are not complying with the Commission’s existing PURPA Regulations. We 

promulgate this final rule based on the expectation that the states will fulfill their legal 

obligation to implement the Commission’s PURPA Regulations as revised.

66 

46. Further, although Congress required the Commission to establish the general 

parameters for establishing QF rates, Congress delegated to the states—not the 

Commission—the role to set QF rates.67 To the extent that any entity believes a state is 

failing to implement the Commission’s PURPA Regulations, PURPA section 210(h) 

provides that entity an avenue to seek relief.68 

66 16 U.S.C. 824a-3(f)(1). The same obligation to implement the Commission’s 

PURPA Regulations as revised, we note, is imposed on nonregulated electric utilities. 16 

U.S.C. 824a-3(f)(2). 

67 See 16 U.S.C. 824a-3(f)(1) (“[E]ach State regulatory authority shall, after notice 

and opportunity for public hearing, implement such rule (or revised rule) for each electric 

utility for which it has ratemaking authority.”).

68 If the Commission, in response to a petition for enforcement under PURPA 

section 210(h) against a state regulatory authority, chooses not to initiate an enforcement 

action within 60 days of the filing of the petition, the statute authorizes the petitioning 

electric utility or QF to itself initiate a suit directly against the state in U.S. District Court. 

16 U.S.C. 824a-3(h)(2)(B). The same statutory provision similarly governs petitions for 

enforcement against nonregulated electric utilities. Id. PURPA section 210(g) also 

provides for review of state regulatory authorities and nonregulated electric utilities in 

state fora. 16 U.S.C. 824a-3(g). The Commission’s policies with respect to PURPA 

enforcement are more fully set out in its Policy Statement Regarding the Commission’s 

Enforcement Role Under Section 210 of the Public Utility Regulatory Policies Act of 

1978, 23 FERC ¶ 61,304 (1983).
Docket Nos. RM19-15-000 and AD16-16-000 - 35 -

III. Background

A. Passage of PURPA in 1978 and the Commission’s Promulgation of its 

PURPA Regulations in 1980

47. PURPA was enacted in 1978 as part of a package of legislative proposals intended 

to reduce the country’s dependence on oil and natural gas, which at the time were in short 

supply and subject to dramatic price increases. PURPA sets forth a framework to 

encourage the development of alternative generation resources that do not rely on 

traditional fossil fuels (i.e., oil, natural gas and coal) and cogeneration facilities that make 

more efficient use of the heat produced from the fossil fuels that were then commonly 

used in the production of electricity. 

48. To accomplish this goal, PURPA section 210(a) directs that the Commission 

“prescribe, and from time to time thereafter revise, such rules as [the Commission] 

determines necessary to encourage cogeneration and small power production,”69 including 

rules requiring electric utilities to offer to sell electricity to, and purchase electricity from, 

QFs. PURPA section 210(f) required each state regulatory authority and nonregulated 

electric utility (together, states) to implement the Commission’s rules.

49. In 1980, the Commission issued Order Nos. 69 and 70, which promulgated the 

required rules that, with limited exceptions, remain in effect today.70 The Commission 

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

70 Order No. 69, FERC Stats. & Regs. ¶ 30,128; Small Power Production and 

Cogeneration Facilities – Qualifying Status, Order No. 70, FERC Stats. & Regs. ¶ 30,134

(cross-referenced at 10 FERC ¶ 61,230), orders on reh’g, Order No. 70-A, FERC Stats. & 

Regs. ¶ 30,159 (cross-referenced at 11 FERC ¶ 61,119) and FERC Stats. & Regs. ¶ 30,160

(cross-referenced at 11 FERC ¶ 61,166), order on reh’g, Order No. 70-B, FERC Stats. & 
Docket Nos. RM19-15-000 and AD16-16-000 - 36 -

explained that, at the time of the passage of PURPA, cogenerators and small power 

producers faced three major obstacles: (1) electric utilities were not required to purchase 

these generators’ electric output or to make purchases at an appropriate rate; (2) electric 

utilities sometimes charged discriminatorily high rates for backup services; and 

(3) cogenerators and small power producers ran the risk of being considered public 

utilities themselves and thus being subject to state and federal regulation as utilities.71 

Further, at that time, there was no open access transmission and little competition in 

electric wholesale markets. Electric utilities were vertically-integrated and held dominant 

market positions. As a result of their control over transmission access, it was virtually 

impossible for third parties – whether independent power producers or other electric 

utilities – to compete with them to make sales of electricity. 

50. Given the Congressional mandate described above, the Commission determined in 

Order No. 69 to set rates for sales by QFs equal to the purchasing electric utilities’ 

avoided costs.72 The Commission also directed that electric utilities provide backup 

Regs. ¶ 30,176 (cross-referenced at 12 FERC ¶ 61,128), order on reh’g, FERC Stats. & 

Regs. ¶ 30,192 (1980) (cross-referenced at 12 FERC ¶ 61,306), amending regulations, 

Order No. 70-D, FERC Stats. & Regs. ¶ 30,234 (cross-referenced at 14 FERC ¶ 61,076),

amending regulations, Order No. 70-E, FERC Stats. & Regs. ¶ 30,274 (1981) (crossreferenced at 15 FERC ¶ 61,281). 

71 Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,863. See infra P 78 & note 

112 (addressing how the PURPA Regulations as revised continue to address these 

obstacles). 

72 18 CFR 292.304(a)(2); see API, 461 U.S. at 412-18.
Docket Nos. RM19-15-000 and AD16-16-000 - 37 -

electric energy to QFs on a non-discriminatory basis and at just and reasonable rates,73 and 

that electric utilities interconnect with QFs.74 Pursuant to section 210(e) of PURPA,75 the

Commission further provided exemptions from many provisions of the FPA and state laws 

governing utility rates and financial organization.76

B. Circumstances Leading to the Commission’s Re-evaluation of the 

PURPA Regulations and the Issuance of the NOPR

51. In the NOPR, the Commission described three important changes in the 

circumstances that had originally prompted Congress to pass PURPA in 1978. First, as 

the Commission explained, the United States has seen an unprecedented change in the 

dynamics of the natural gas market and the relevant supply and demand.77 Led by 

advancements in production technologies, primarily in accessing shale reserves, natural 

gas supplies increased dramatically.78 Further, the EIA forecasted continued supply 

73 Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,887-90; see also 18 CFR 

292.305.

74 Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,874; see also 18 CFR 292.303(c).

75 16 U.S.C. 824a-3(e).

76 Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,864; accord id. at 30,863, 

30,894-96; see also 18 CFR 292.601-.602.

77 NOPR, 168 FERC ¶ 61,184 at P 19.

78 Domestic natural gas production, which appeared to peak in the early 1970s at 21.7 

Tcf per year, increased from 18.1 Tcf in 2005 to 30.4 Tcf in 2018. EIA, Monthly Energy 

Review (Aug. 27, 2019) (in table 4.1 see column labeled “Natural Gas Production (Dry)” on 

the Annual tab of the xls version), https://www.eia.gov/totalenergy/data/monthly/. 
Docket Nos. RM19-15-000 and AD16-16-000 - 38 -

growth over the next 25 years.79 In short, as the Commission found in issuing the NOPR, 

there no longer are shortages of natural gas supply.

52. Second, the Commission found that, since 1978, the outlook for the development of 

alternatives to natural gas and oil-fired generation resources, such as renewable resources, 

has changed equally dramatically.80 The once-nascent renewables industry has grown and 

matured over the past 40 years and has only accelerated subsequent to the Energy Policy 

Act of 2005’s amendment of PURPA. The Commission noted that the cost of building 

renewable facilities has decreased substantially to the point that the cost of renewable 

resources is now or is shortly expected to approach the cost of traditional electric 

generation.81 The Commission also recognized that renewable resources (including 

79 EIA’s forecast showed supplies increasing to nearly 40 Tcf by 2035 and 43 Tcf 

by 2050. EIA, Annual Energy Outlook 2018, at tbl.13 (Jan. 24, 2019) (in table see row 

labeled “Dry Gas Production” under the reference case) (Annual Energy Outlook 2019), 

https://www.eia.gov/outlooks/aeo/data/browser/#/?id=13-

AEO2019&cases=ref2018&sourcekey=0. 

80 NOPR, 168 FERC ¶ 61,184 at P 20.

81 Id. (citing EIA, Updated Capital Cost Estimates for Utility Scale Electricity 

Generating Plants, https://www.eia.gov/analysis/studies/powerplants/capitalcost/; EIA, 

Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual 

Energy Outlook 2019 (Feb. 2019), 

https://www.eia.gov/outlooks/aeo/pdf/electricity_generation.pdf; Lawrence Berkeley 

National Lab, Wind Technologies Market Report, https://emp.lbl.gov/wind-technologiesmarket-report/). However, EIA has cautioned against directly comparing the costs of 

dispatchable and nondispatchable generation: 

Because load must be continuously balanced, generating units 

with the capability to vary output to follow demand 

(dispatchable technologies) generally have more value to a 

system than less flexible units (nondispatchable technologies) 

such as those using intermittent resources to operate. The 
Docket Nos. RM19-15-000 and AD16-16-000 - 39 -

hydro) provide a significant share of the electricity currently generated in the United 

States,82 that most renewable resources today are not QFs,83 and that 65 percent of 

capacity additions in 2019 were expected to come from renewable resources.84 

53. Third, the introduction of QFs as competing sources of electricity to the incumbent 

electric utilities has led to the development of significant non-QF independent power 

LCOE values for dispatchable and non-dispatchable 

technologies are listed separately in the tables because 

comparing them must be done carefully.

EIA, Levelized Cost and Levelized Avoided Cost of New Generation Resources in the 

Annual Energy Outlook 2019, at 2 (Feb. 2019), 

https://www.eia.gov/outlooks/archive/aeo19/pdf/electricity_generation.pdf.

82 NOPR, 168 FERC ¶ 61,184 at P 21 (citing EIA, August 2019 Monthly Energy 

Review at Figure 7.2a, https://www.eia.gov/totalenergy/data/monthly; Office of Energy 

Projects, Energy Infrastructure Update For July 2019 at 4 (July 2019), 

https://www.ferc.gov/legal/staff-reports/2019/july-energy-infrastructure.pdf).

83 NOPR, 168 FERC ¶ 61,184 at P 22.

84 Id. (citing EIA, Today in Energy, New electric generating capacity in 2019 will 

come from renewables and natural gas (Jan. 10, 2019), 

https://www.eia.gov/todayinenergy/detail.php?id=37952 (Form EIA-860M, Preliminary 

Monthly Electric Generator Inventory). 
Docket Nos. RM19-15-000 and AD16-16-000 - 40 -

production.85 In addition, RTOs and ISOs have developed competitive wholesale electric 

markets that serve roughly two-thirds of electricity consumers in the United States.86

54. In PURPA section 210(a), Congress directed not only that the Commission 

prescribe regulations, but that the Commission revise those regulations “from time to time

thereafter.”87 The Commission determined in the NOPR that, in light of these dramatic 

changes in circumstances since the passage of PURPA, it was appropriate to review the 

PURPA Regulations to determine whether changes to those regulations were warranted

consistent with our statutory mandate.

88 

55. After identifying these three important changes in the industry that have taken 

place since 1980, we further identified evidence demonstrating that overestimations of 

85 NOPR, 168 FERC ¶ 61,184 at P 25. The Commission cited to data showing that 

that net generation of energy by non-utility owned renewable resources in the United 

States escalated from 51.7 TWh in 2005 when EPAct 2005 was passed, to 340 TWh in 

2018. This also included significant growth in non-utility renewable resources in states 

outside of RTOs. For example, net generation by non-utility renewable resources in the 

region defined by EIA as the Mountain State region increased from 3.6 TWh in 2005 to 

19.5 TWh in 2012, and to 42.5 TWh in 2018. Pacific Northwest (Oregon and 

Washington) net non-utility generation from renewable resources increased from 1.5 TWh 

in 2005, to 8.7 TWh in 2012, and to 10.6 TWh in 2018. In the Southeast region of the 

country, non-utility renewable resources saw a lesser increase from 2.6 TWh in 2005 to 

2.7 TWh in 2012, but expanded to 6.5 TWh in 2018. NOPR, 168 FERC ¶ 61,184 at P 27

(citing data taken from EIA’s Electricity Data Browser, 

www.eia.gov/electricity/data/browser (select net generation, other renewables, 

independent power producers)).

86 ISO/RTO Council, The Role of ISOs and RTOs, https://isorto.org.

87 16 U.S.C. 824a-3(a).

88 16 U.S.C. 824a-3(b).
Docket Nos. RM19-15-000 and AD16-16-000 - 41 -

avoided cost have not been balanced by underestimations, and that this trend may persist 

with the general decline in the cost of electricity.89

C. Summary of Changes to the PURPA Regulations Implemented by this 

final rule

56. We now are revising our PURPA Regulations based on the record of this 

proceeding, including comments submitted in the technical conference in Docket No. 

AD16-16-000 (Technical Conference),

90 the record evidence cited in the NOPR, and the 

comments submitted in response to the NOPR. These changes, including modifications to 

the proposals made in the NOPR, are summarized below.91 

89 See NOPR, 168 FERC ¶ 61,184 at P 30. Evidence submitted in response to the 

NOPR shows that, as a result, customers may be paying more than avoided costs. See 

infra PP 265 (“Duke Energy claims that, among the factors contributing to this 

overpayment of $2.26 billion for the remainder of these QF contracts, the primary factor 

has been the requirement to offer fixed avoided cost energy rates during a period of 

rapidly declining energy prices”), 268 (“Massachusetts DPU argues that a 10-year, fixed 

energy rate based on current New England wholesale energy market prices is highly likely 

to diverge from actual energy market prices over the ten-year contract term and could 

significantly harm ratepayers”).

90 Supplemental Notice of Technical Conference, Implementation Issues Under the 

Public Utility Regulatory Policies Act of 1978, Docket No. AD16-16-000 (May 9, 2016). 

The Technical Conference covered such issues as: (1) various methods for calculating 

avoided cost; (2) the obligation to purchase pursuant to a LEO; (3) application of the onemile rule; and (4) the rebuttable presumption the Commission has adopted under PURPA 

section 210(m) that QFs 20 MW and below do not have nondiscriminatory access to 

competitive organized wholesale markets.

91 In its post-NOPR comments, Bloom Energy requested that the Commission 

“[u]pdate the definition of ‘useful thermal energy output’ of a topping-cycle cogeneration 

facility to reflect the commercialization of solid oxide fuel cells that produce heat for the 

industrial purpose of producing hydrogen, a fuel that the fuel cells use to generate 

electricity.” Bloom Energy Comments at 2. We do not take action on this request in this 

proceeding because we do not view this proposal as a logical outgrowth of the NOPR.
Docket Nos. RM19-15-000 and AD16-16-000 - 42 -

57. First, we grant states the flexibility to require that energy rates (but not capacity 

rates) in QF power sales contracts and other LEOs92 vary in accordance with changes in 

the purchasing electric utility’s as-available avoided costs at the time the energy is 

delivered. Under this change, if a state exercises this flexibility, a QF no longer would 

have the ability to elect to have its energy rate be fixed, but would continue to be entitled 

to a fixed capacity rate for the term of the contract or LEO.

93 

58. Second, we grant states additional flexibility to allow QFs to have a fixed energy 

rate, but to provide that such state-authorized fixed energy rate can be based on projected 

energy prices during the term of a QF’s contract based on the anticipated dates of delivery. 

59. Third, we grant states flexibility to set “as-available” QF energy rates as follows: 

We are establishing a rebuttal presumption, rather than a per se rule as proposed in the 

NOPR, that the LMP established in the organized electric markets defined in 18 CFR 

292.309(e), (f), or (g) represents the as-available avoided costs of electric utilities located 

92 The Commission has held that a LEO can take effect before a contract is 

executed and may not necessarily be incorporated into a contract. JD Wind 1, LLC, 129 

FERC ¶ 61,148, at P 25 (2009), reh’g denied, 130 FERC ¶ 61,127 (2010) (“[A] QF, by 

committing itself to sell to an electric utility, also commits the electric utility to buy from 

the QF; these commitments result either in contracts or in non-contractual, but binding, 

legally enforceable obligations.”). For ease of reference, however, references herein to a 

contract also are intended to refer to a LEO that is not incorporated into a contract.

93 Moreover, any state—whether located in regions where energy prices are 

competitively based or whether located in regions where they are not—would be 

permitted to require that the fixed energy rate established at the time of the contract 

include provisions, established at the time the contract is established, providing for 

revisions to the energy rate at regular intervals, consistent with, for example, a purchasing 

electric utility’s integrated resource plan, to reflect updated avoided cost calculations.
Docket Nos. RM19-15-000 and AD16-16-000 - 43 -

in these markets.

94 So long as this presumption is not rebutted, a state can at its option 

establish as-available energy avoided cost rates for QFs selling to such electric utilities at

the LMP. With respect to QFs selling to electric utilities located outside of the organized 

electric markets defined in 18 CFR 292.309(e), (f), or (g), states have the option to set asavailable energy avoided cost rates at competitive prices from liquid market hubs or 

calculated from a formula based on natural gas price indices and specified heat rates, 

provided that the states first determine that such prices represent the purchasing electric 

utilities’ avoided costs. The states would have the flexibility to choose to adopt one or 

more of these options or to continue setting QF rates under the standards long established 

in the PURPA Regulations.

60. Fourth, states would have the flexibility to set energy and capacity rates pursuant to 

a competitive solicitation process conducted pursuant to transparent and nondiscriminatory procedures consistent with the Commission’s Allegheny standard, 

described in this final rule. 

61. Fifth, we do not adopt the proposed rule permitting states with retail competition to 

allow relief from the purchase obligation. We instead clarify in this final rule that the 

Commission’s existing PURPA Regulations already require that states, to the extent 

practicable, must account for reduced loads in setting QF capacity rates.

94 These are the markets operated by Midcontinent Independent System Operator, 

Inc. (MISO); PJM Interconnection, L.L.C. (PJM); ISO New England Inc. (ISO-NE); New 

York Independent System Operator, Inc. (NYISO); Electric Reliability Council of Texas 

(ERCOT); California Independent System Operator, Inc. (CAISO); and Southwest Power 

Pool, Inc. (SPP).
Docket Nos. RM19-15-000 and AD16-16-000 - 44 -

62. Sixth, we modify the Commission’s “one-mile rule” for determining whether 

generation facilities are considered to be at the same site for purposes of determining 

qualification as a qualifying small power production facility. Specifically, we allow 

electric utilities, state regulatory authorities, and other interested parties to show that 

affiliated small power production facilities that use the same energy resource and are more 

than one mile apart and less than 10 miles apart actually are at the same site (with 

distances one mile or less apart still irrebuttably at the same site, and distances 10 miles or 

more apart irrebuttably at separate sites). We also allow a small power production facility

seeking QF status to provide further information in its certification (whether a selfcertification or an application for Commission certification) or recertification (whether a 

self-recertification or an application for Commission recertification) to defend 

preemptively against subsequent challenges, by identifying factors affirmatively

demonstrating that its facility is indeed at a separate site from other affiliated small power 

production qualifying facilities. We further add a definition of the term “electrical 

generating equipment” to the PURPA Regulations to clarify how the distance between 

facilities is to be calculated. 

63. Seventh, we allow an entity to challenge an initial self-certification or selfrecertification without being required to file a separate petition for declaratory order and to 

pay the associated filing fee. However, we clarify in this final rule that such protests may 

be made to new certifications (both self-certifications and applications for Commission 

certification) but to only self-recertifications and applications for Commission 

recertifications making substantive changes to the existing certification.
Docket Nos. RM19-15-000 and AD16-16-000 - 45 -

64. Eighth, we revise the Commission’s regulations implementing PURPA section 

210(m), which provide for the termination of an electric utility’s obligation to purchase 

from a QF with nondiscriminatory access to certain markets. Currently, there is a 

rebuttable presumption that QFs with a net capacity at or below 20 MW do not have 

nondiscriminatory access to such markets. We update the rebuttable presumption for 

small power production facilities (but not cogeneration facilities) from 20 MW to 5 MW

and, in this final rule, revise the regulations to include examples of factors, among others, 

that QFs may argue show that they lack nondiscriminatory access to such markets.

65. Finally, we clarify that a QF must demonstrate commercial viability and a financial 

commitment to construct its facility pursuant to objective and reasonable state-determined 

criteria before the QF is entitled to a contract or LEO. States may not impose any 

requirements for a LEO other than a showing of commercial viability and a financial 

commitment to construct the facility. We also clarify in this final rule that, to the extent 

that the permitting factor is relied upon, a QF need only show that it has applied for all 

required permits and paid all applicable fees, and not that it has obtained such permits.

66. As explained in detail in the relevant sections below, these changes will enable the 

Commission to continue to fulfill its statutory obligations under sections 201 and 210 of 

PURPA. We emphasize that these changes are effective prospectively for new contracts 

or LEOs and for new facility certifications and recertifications filed on or after the 

effective date of this final rule; we do not by this final rule permit disturbance of existing 

contracts or LEOs or existing facility certifications.
Docket Nos. RM19-15-000 and AD16-16-000 - 46 -

IV. Discussion 

A. General Legal Standards Under PURPA

67. Several comments were submitted regarding: (1) the requirement in PURPA 

section 210(a) that “the Commission shall prescribe, and from time to time thereafter 

revise, such rules as it determines necessary to encourage cogeneration and small power 

production”; and (2) the requirement in PURPA section 210(b) that rates paid by 

purchasing utilities to QFs “shall not discriminate against qualifying cogenerators or 

qualifying small power producers.”95 In addition, a claim was made that the Commission 

has unlawfully delegated its authority to the states. These comments apply to several of 

the revisions implemented by this final rule and therefore are discussed prior to the 

discussion of specific revisions implemented herein. 

1. Encouragement of QFs 

a. Comments 

68. Commenters make two general arguments regarding the statutory requirement that 

the Commission’s PURPA Regulations should encourage QFs. First, they note that the 

statutory requirement that the PURPA Regulations encourage QFs is mandatory and that 

the Commission has no discretion to determine that such encouragement no longer is 

necessary. Harvard Electricity Law states that “Congress’[s] mandate to encourage QFs is 

not contingent on industry conditions and does not expire.”96 Further, they assert, “[t]he 

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

96 Harvard Electricity Law Comments at 1.
Docket Nos. RM19-15-000 and AD16-16-000 - 47 -

Commission may not overwrite Congress’s instruction to issue rules that it ‘determines 

necessary to encourage cogeneration and small power production.’”97 Public Interest 

Organizations similarly object to the NOPR as violating the encouragement requirement 

because, they assert, the NOPR “reflect[s] a belief that the current rules support too much 

QF development and a desire to reduce the incentives in current rules for QF 

development.”98 NIPPC, CREA, REC, and OSEIA assert that “[t]he Commission cannot 

take it upon itself to change the underlying policy directives to encourage QFs.”99

69. Public Interest Organizations advance a second general argument based on the 

encouragement requirement, arguing that “[t]o amend the rules, the Commission must first 

determine that the actual changes it proposes increase development and utilization of 

QFs.” 100 Similarly, Allco attacks the NOPR on the grounds that “the proposed changes 

do not encourage QF generation.”101 

b. Commission Determination 

70. We agree with commenters that PURPA does not provide discretion to the 

Commission to determine whether QFs should be encouraged. That is a determination left 

to Congress, and we have not premised this final rule on a belief that QFs should not be 

97 Id. at 4 (quoting PURPA section 210(a)).

98 Public Interest Organizations Comments at 10.

99 NIPPC, CREA, REC, and OSEIA Comments at 29.

100 Public Interest Organizations Comments at 11.

101 Allco Comments at 8.
Docket Nos. RM19-15-000 and AD16-16-000 - 48 -

encouraged. However, the requirement that the Commission promulgate regulations 

necessary to encourage QFs is not unbounded. Instead, as noted briefly earlier, there are 

statutory limitations on the extent that the PURPA Regulations can encourage QFs.

71. First, PURPA section 210(b) sets out standards with which the Commission must 

comply in setting QF rates. The last sentence of PURPA section 210(b) sets out an upper 

limit on such rates. “No such rule prescribed under subsection (a) shall provide for a rate 

which exceeds the incremental cost to the electric utility of alternative electric energy.”102 

72. If there were any doubt from the statutory language that incremental costs (avoided 

costs) are intended to be a hard cap on QF rates, such doubt is dispelled by the Conference 

Report to PURPA, which provided: “This limitation on the rates which may be required 

in purchasing from a cogenerator or small power producer is meant to act as an upper 

limit on the price at which utilities can be required under this section to purchase electric 

energy.”103 The Conference Report also described the reason for the avoided cost cap on 

102 Furthermore, PURPA section 210(b)(1) requires that QF rates be “just and 

reasonable to the electric consumers of the electric utility and in the public interest.” 16 

U.S.C. 824a-3(b)(1). Although the exact scope of the “just and reasonable to the electric 

consumers” criterion has never been addressed explicitly, the Supreme Court held in API

that the requirement in the PURPA Regulations that QF rates be set at full avoided costs 

does not violate this criterion. API, 461 U.S. at 415-16. This “just and reasonable to the 

electric consumers” criterion likely would be violated if the Commission were to allow a 

rate above the purchasing electric utility’s avoided costs.

103 Conf. Rep. at 98 (emphasis added). 
Docket Nos. RM19-15-000 and AD16-16-000 - 49 -

QF rates. “The provisions of this section are not intended to require the rate payers of a 

utility to subsidize cogenerators or small power produc[er]s.”104 

73. Therefore, PURPA section 210(b) imposes an important limit on the Commission’s 

ability to encourage QFs by imposing an upper boundary on the rates at which QFs may 

require electric utilities to purchase their electric energy. The Commission cannot require 

QF rates that exceed the avoided costs of the purchasing electric utility.

105

74. Second, another way in which Congress limited the Commission’s ability to 

encourage QFs was to define small power production facilities, the PURPA category 

applicable to almost all renewable resources that wish to be QFs, as having “a power 

production capacity which, together with any other facilities located at the same site (as 

determined by the Commission), is not greater than 80 megawatts.”106 The statutory 80 

MW limitation, as well as any definition of “the same site” that may be established by the 

Commission, will of necessity have an effect on the encouragement of QFs, because it will 

limit the capacity of QFs both ab initio and also for those located at the same site to 80 

MW.

75. Third, Congress amended PURPA section 210 to add section 210(m), which 

provides for termination of the requirement that an electric utility enter into a new 

obligation or contract to purchase from a QF if the QF has nondiscriminatory access to 

104 Id. (emphasis added). 

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

106 16 U.S.C. 796(17)(A)(ii).
Docket Nos. RM19-15-000 and AD16-16-000 - 50 -

certain defined types of markets.107 We interpret this amendment as reflecting Congress’s

judgment that these markets provide adequate encouragement for those QFs having 

nondiscriminatory access to such markets. To the extent that a party asserts that the 

termination of the purchase obligation for QFs with nondiscriminatory access to these 

markets discourages QFs, that party’s argument is not with the Commission, but rather 

with Congress. PURPA section 210(m) obligates the Commission to grant any request to 

terminate a utility’s obligation to purchase from a QF with nondiscriminatory access to the 

specified markets.108

76. Finally, we disagree with any suggestion that a rule originally adopted in 1980 

cannot be changed once adopted, or that our revised regulations cannot be different in how 

they encourage QFs than the regulations the Commission issued in 1980.

109 For one 

thing, as explained above, PURPA itself includes certain limitations on the Commission’s 

ability to encourage QFs, and a provision in the final rule intended to comply with these 

statutory limitations cannot be found to violate PURPA even if such a provision 

individually does not affirmatively encourage QFs to the same degree now as in 1980. As

explained herein, we do not seek, through this final rule, to cease encouraging the 

development of QFs. Instead, this final rule is intended to ensure that the Commission is 

107 See 16 U.S.C. 824a-3(m).

108 Id. (“[N]o electric utility shall be required to enter into a new contract or 

obligation to purchase electric energy from a [QF] if the Commission finds that the [QF] 

has nondiscriminatory access to [specified markets].”).

109 See 18 U.S.C. 824a-3(a).
Docket Nos. RM19-15-000 and AD16-16-000 - 51 -

compliant with the statute in how it does encourage the development of QFs. In doing so, 

the Commission may end up encouraging QF development differently from the current 

PURPA Regulations, but the Commission’s regulations continue to encourage QF 

development, as contemplated by PURPA.

77. Many of the commenters’ assertions seem to be based on a reading of the statute 

that requires that every individual change made to the PURPA Regulations in isolation 

must individually encourage QFs notwithstanding the statute’s provisions. But, as 

discussed above, Congress established boundaries in PURPA that must be considered, 

such as the “cap” on incremental costs; just and reasonable rates for electric customers; 

the 80 MW limit; and whether QFs have nondiscriminatory access to markets. 

Furthermore, the statutory requirement to encourage QF development applies to the 

PURPA Regulations – “such rules as [the Commission] determines necessary” – as a 

whole.110 

78. In that regard, we find that the Commission’s PURPA Regulations as a whole when 

modified by this final rule continue to encourage the development of QFs, consistent with 

PURPA. The PURPA Regulations in particular, continue to require that QF rates be set at 

full avoided costs, a provision the Supreme Court described as “provid[ing] the maximum 

incentive for the development of cogeneration and small power production.”111 In 

addition, this final rule retains provisions of the PURPA Regulations adopted in 1980 that 

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

111 API, 461 U.S. at 418.
Docket Nos. RM19-15-000 and AD16-16-000 - 52 -

provide encouragement through other means recognized by the Supreme Court in FERC v. 

Miss.

112 (e.g., certain regulatory relief,113 interconnection provisions,114 and requirements 

that utilities sell power to QFs that will enable QFs to continue operations).

115 Moreover, 

several of the changes implemented by this final rule also provide additional 

encouragement for QFs as described in more detail below.

2. Discrimination 

a. Comments

79. Commenters opposing the proposals in the NOPR also cite to the statutory 

requirement in PURPA section 210(b)(1) that QF rates “shall not discriminate against” 

QFs. EPSA asserts that “[n]otably, this standard is more restrictive than the [FPA’s]

prohibition against ‘unduly discriminatory’ rates.”116 Public Interest Organizations state 

that “[i]n other statutes, prohibiting price discrimination without the modifiers 

‘unreasonable’ or ‘undue,’ means any difference in price for the same commodity.”117

112 456 U.S. 742, 750-51 (1982) (holding that Congress “felt that two problems 

impeded the development of nontraditional generating facilities: (1) traditional electricity 

utilities were reluctant to purchase power from, and to sell power to, the nontraditional

facilities, and (2) the regulation of these alternative energy sources by state and federal 

utility authorities imposed financial burdens upon the nontraditional facilities and thus 

discouraged their development” (internal citations omitted)).

113 18 CFR 292.601-02.

114 18 CFR 292.303(c).

115 18 CFR 292.305.

116 EPSA Comments at 8. 

117 Public Interest Organizations Comments at 47 (citing FTC v. Anheuser - Busch, 
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80. In discussing the requirement that QF rates not be discriminatory, some

commenters compare the treatment afforded to QFs under the NOPR with the rate 

treatment applicable to public utilities. For example, NIPPC, CREA, REC, and OSEIA 

point out that “[u]tilities can rate-base long-term investments, thereby ensuring that they 

can recover their capital investments plus an authorized return, and then also recover their 

actual operating costs under traditional cost-of-service ratemaking.”118 By contrast,

Harvard Electricity Law asserts, “QFs do not have the same ability that the electric 

utilities have to ‘rate base’ their facilities and, thereby, guarantee capital recovery.”119

81. Based on this difference between utilities and QFs, commenters allege that certain

aspects of the NOPR are discriminatory, including those provisions of the NOPR 

regarding the use of LMPs and other competitive rates to set as-available energy rates,120

Inc., 363 U.S. 536, 549 (1960)).

118 NIPPC, CREA, REC, and OSEIA Comments at 36; see also IdaHydro 

Comments at 11; Industrial Energy Consumers Comments at 12-13; SC Solar Alliance 

Comments at 5-10; Solar Energy Industries Comments at 33, 36-38.

119 Harvard Electricity Law Comments at 28.

120 See, e.g., Public Interest Organizations Comments at 64 (stating that the use of 

competitive prices to set as-available energy avoided cost rates is discriminatory because 

non-QF generators are not limited to competitive prices and utilities can, and regularly do, 

pay effective prices for energy that exceed the price determined by competitive prices).
Docket Nos. RM19-15-000 and AD16-16-000 - 54 -

to allow for variable energy rates in QF contracts,121 and to allow avoided costs to be set 

through competitive solicitations (i.e., requests for proposals (RFPs)).

122

b. Commission Determination 

82. As an initial matter, we agree with EPSA that the statutory requirement in PURPA 

section 210(b)(1) that QF rates “shall not discriminate against” QFs is more restrictive 

than the FPA’s prohibition against ‘unduly discriminatory’ rates.123 However, the avoided 

cost cap on QF rates that limits the Commission’s ability to encourage QFs, discussed 

above, also applies to the Commission’s ability to address these claims of discrimination 

under PURPA. PURPA section 210(b) makes clear that “[n]o such rule prescribed under 

subsection (a) shall provide for a rate which exceeds the incremental cost to the electric 

utility of alternative electric energy.”124 

121 See, e.g., EPSA Comments at 9 (“The NOPR avoided rate proposal must 

therefore be rejected because it puts QFs at a disadvantage to utility-owned generation, in 

violation of the non-discrimination mandate under PURPA.”); Public Interest 

Organizations Comments at 51 (“[L]imiting QFs to contracts providing no price certainty 

for energy values, while non-QF generation regularly obtains fixed price contracts and 

utility-owned generation receives guaranteed cost recovery from captive ratepayers, 

constitutes discrimination.”).

122 See, e.g., Allco Comments at 12 (stating that allowing a state commission to use 

a competitive solicitation price is simply giving another tool to a state commission to kill 

QF projects).

123 EPSA Comments at 8. 

124 Furthermore, as noted above, PURPA section 210(b)(1) requires that QF rates 

also be “just and reasonable to the electric consumers of the electric utility and in the 

public interest.” See supra note 102.
Docket Nos. RM19-15-000 and AD16-16-000 - 55 -

83. We are retaining in this final rule the requirement that QF rates be set at a 

purchasing utility’s full avoided costs. The Supreme Court held in API that “the fullavoided-cost rule plainly satisfies the nondiscrimination requirement.”125 Although the 

Court did not provide a detailed explanation for this holding, the reasoning is apparent. If 

the purchasing utility is paying the same rate to a QF for power that it otherwise would 

have paid for incremental power, by definition such a rate could not be discriminatory. 

But even if it were possible to posit a situation where the payment of a full avoided cost 

rate to a QF somehow were discriminatory, the Commission nevertheless would be 

prohibited by PURPA section 210(b) from requiring a rate to be paid to the QF that is

above the full avoided costs of the purchasing electric utility.

84. For the same reasons, Public Interest Organizations are mistaken when they assert 

that, without the modifiers “unreasonable” or “undue,” any difference in price for the 

same commodity violates PURPA.

126 So long as a QF’s rate is set at the purchasing 

utility’s full avoided cost, the QF’s rate should be the same as the rate the purchasing 

utility otherwise would be paying or the cost it would be incurring, and such a rate would 

not be discriminatory. And, in any event, as noted above, the Commission cannot require 

a rate that is any higher. 

125 API, 461 U.S. at 413.

126 Public Interest Organizations Comments at 47 (citing FTC v. Anheuser - Busch, 

Inc., 363 U.S. at 549).
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85. With respect to comparisons between QFs, with no guarantee of cost recovery, and 

electric utilities, which if they have a franchised service territory and sell at retail in that 

territory are effectively guaranteed the opportunity to seek to recover prudently-incurred 

costs in their retail rates, we observe that Congress acknowledged this difference when 

enacting PURPA. As emphasized in the PURPA Conference Report:

The conferees recognize that cogenerators and small power 

producers are different from electric utilities, not being 

guaranteed a rate of return on their activities generally or on 

the activities vis a vis the sale of power to the utility and 

whose risk in proceeding forward in the cogeneration or small 

power production enterprise is not guaranteed to be 

recoverable.

127

86. In recognizing this difference and yet not seeking to eliminate it, Congress also 

made clear its intent not to treat QFs like electric utilities in this regard:

It is not the intention of the conferees that [QFs] become 

subject. . . to the type of examination that is traditionally given 

to electric utility rate applications to determine what is the just 

and reasonable rate that they should receive for their electric 

power.128

87. Based on this legislative history, the Supreme Court concluded in API that,

“Congress did not intend to impose traditional ratemaking concepts on sales by qualifying 

facilities to utilities.”129 But application of traditional cost-based ratemaking principles to 

sales by QFs is exactly what would be required in order to provide QFs with the same 

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

128 Id. at 97.

129 API, 461 U.S. at 414.
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guaranteed cost recovery that applies to electric utilities. Also, guaranteeing QFs cost 

recovery is fundamentally inconsistent with PURPA, which sets the rate the QF is paid at 

the utility’s avoided cost, not at the QF’s cost. 

88. It therefore is clear that Congress did not intend for the PURPA nondiscrimination 

criterion to require that QF rates be set in a way that guarantees recovery of a QF’s own 

costs, even as Congress recognized that franchised electric utilities selling at retail 

typically do have such guarantees for their own costs. Congress thus withheld from the 

Commission the authority to provide to QFs the same opportunity to recover costs at retail 

that franchised electric utilities have to recover their costs at retail; it was done by 

Congress intentionally and cannot be impermissibly discriminatory.130

3. Unlawful Delegation and the Role of Nonregulated Electric 

Utilities

a. Comments 

89. Allco argues that PURPA section 210(f) requires states to “implement” the

Commission’s rules, and that those rules cannot redelegate the Commission’s authority. 

Allco claims that the statutory requirement to implement the Commission’s rules cannot 

simply be a façade for delegating broad authority to states to undercut PURPA’s directive 

that QF small power production must be encouraged. Allco concludes that Congress 

intended for the Commission to adopt actual rules rather than “a menu of factors” that 

130 See 16 U.S.C. 824a-3(a) (rules Commission is directed to prescribe “may not 

authorize a [QF] to make any sale for purposes other than resale”).
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essentially leaves states with all the discretion as to what to implement in order to 

encourage QF generation.131

90. Allco also asserts that the NOPR’s proposed delegation of authority to 

nonregulated electric utilities is an unconstitutional delegation. According to Allco, such 

a delegation would mean that nonregulated electric utilities (some of which are among the 

largest utilities in the United States) were regulating themselves. Allco argues that a

private entity such as a nonregulated electric utility cannot constitutionally be delegated 

regulatory power.132 

91. Nebraska Board states that there is no state agency in Nebraska that has ratemaking 

authority over retail electric suppliers and that all retail electric suppliers are consumerowned. Nebraska Board states its understanding that each retail electric supplier in 

Nebraska would have jurisdiction to exercise flexibilities provided to states in the NOPR.

92. Public Interest Organizations argue that the Commission failed to comply with 

PURPA section 210’s requirement to consult with federal and state regulatory agencies 

with ratemaking authority.133

b. Commission Determination 

93. Allco’s unlawful delegation claims are misplaced. By enacting PURPA section 

210(f)(1), Congress delegated to the states the obligation to implement the Commission’s 

131 Allco Comments at 39-40.

132 Id. at 40 (citing Ass’n of Am. R.R. v. DOT, 721 F.3d 666, 677 (D.C. Cir. 2013),

vacated on other grounds, 135 S. Ct. 1225 (2015)).

133 Public Interest Organizations Comments at 19 (citing 16 U.S.C. 824a-3(a)).
Docket Nos. RM19-15-000 and AD16-16-000 - 59 -

PURPA rules, and the Commission is acting consistent with that delegation. Congress’s 

delegation to the states was upheld in FERC v. Miss.

134 and we are ensuring that the rules 

we have imposed abide by all the terms of the statute. Further, the Commission’s current 

PURPA Regulations, promulgated in 1980, set forth a list of factors that the states are to 

consider, “to the extent practicable,” in setting QF rates.135 In so doing, the Commission 

emphasized that states have “great latitude in determining the manner of implementation 

of the Commission’s rules, provided that the manner chosen is reasonably designed to 

implement the requirements of Subpart C [which includes the pricing rules of 18 CFR

292.304].”136 This final rule adds factors that must be taken into account to the extent 

practicable in setting rates, while retaining the “great latitude” the states always have had 

to implement the PURPA Regulations and which have been an important feature of the 

Commission’s PURPA Regulations since their inception.

94. With respect to Allco’s claim that the NOPR proposed an unconstitutional 

delegation to nonregulated electric utilities, we note that PURPA section 210(f)(2) 

134 456 U.S. at 760 (“FERC has declared that state commissions may implement 

this by, among other things, ‘an undertaking to resolve disputes between qualifying 

facilities and electric utilities arising under [PURPA].’”). 

135 18 CFR 292.304(e).

136 Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,891-92. The Commission 

explained that “[s]uch latitude is necessary in order for implementation to accommodate 

local conditions and concerns, so long as the final plan is consistent with statutory 

requirements.” Policy Statement Regarding the Commission’s Enforcement Role Under 

Section 210 of the Public Utility Regulatory Policies Act of 1978, 23 FERC ¶ 61,304,at 

61,646.
Docket Nos. RM19-15-000 and AD16-16-000 - 60 -

specifically provides that “each nonregulated electric utility shall, after notice and 

opportunity for public hearing, implement” the Commission’s rules regarding the rates to 

be paid to QFs. Consistent with this statutory provision, the PURPA Regulations 

regarding the setting of QF rates have applied to nonregulated electric utilities since those 

regulations were promulgated in 1980.

137 The final rule does nothing more than continue 

to implement this statutory requirement in the same way it always has been implemented. 

Given PURPA’s unique statutory scheme involving state regulatory authorities, 

nonregulated electric utilities, QFs, and the Commission, we therefore reject Allco’s 

assertion that the rules proposed in the NOPR—and adopted in this final rule—establish

an unconstitutional delegation of authority to a private entity.

138 And it is beyond the 

Commission’s purview to consider whether this statutory grant is constitutional.139 

137 See Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,864 (“The 

implementation of these rules is reserved to the State regulatory authorities and 

nonregulated electric utilities.”). 

138 See Allco Comments at 40. 

139 Finnerty v. Cowen, 508 F.2d 979, 982 (2d Cir. 1974) (explaining that 

administrative agencies “have neither the power nor the competence to pass on the 

constitutionality of administrative or legislative action”) (quoting Murray v. Vaughn, 

300 F. Supp. 688, 695 (D. R.I. 1969)); see also Gibas v. Saginaw Mining Co., 748 F.2d 

1112, 1117 (6th Cir. 1984) (“[A]dministrative bodies like the Board do not have the 

authority to adjudicate the validity of legislation which they are charged with 

administering.”); Spiegel, Inc. v. FTC, 540 F.2d 287, 294 (7th Cir. 1976) (finding that 

the federal agency erred by making a constitutional determination); Downen v. Warner, 

481 F.2d 642, 643 (9th Cir. 1973) (“Resolving a claim founded solely upon a constitutional 

right is singularly suited to a judicial forum and clearly inappropriate to an administrative 

board.”); cf. Woodrow v. FERC, 2020 WL 2198050, at *9 (D.D.C. May 6, 2020) (“When 

Congress creates an intricate statutory-review process that incorporates agency 
Docket Nos. RM19-15-000 and AD16-16-000 - 61 -

Accordingly, when we refer to states in this final rule, we usually are referring to both 

state regulatory authorities and nonregulated electric utilities.

95. Regarding Public Interest Organizations assertion that the Commission failed to 

comply with PURPA section 210’s requirement to consult with federal and state 

regulatory agencies with ratemaking authority, we find that the 2016 Technical 

Conference’s invitation to the public (including state regulatory authorities) to speak, as 

well as the notice and comment process on the NOPR itself, encompasses the required 

consultation.140 The notices soliciting comments were open to all state authorities. 

Indeed, since the Commission first announced that technical conference and up to our 

receipt of comments on the NOPR, representatives from several states have filed 

comments expressing their views on how the Commission should implement PURPA.

B. QF Rates

1. Overview

96. PURPA requires that the Commission promulgate rules, to be implemented by the 

states,141 that “shall insure” that the rates electric utilities pay for purchases of electric

consideration and ultimately an avenue to petition an Article III court, we assume it wants 

that scheme to control.”).

140 See Notice Inviting Post-Technical Conference Comments, Implementation 

Issues Under the Public Utility Regulatory Policies Act of 1978, Docket No. AD16-16-

000 (Sept. 6, 2016); Supplemental Notice of Technical Conference, Implementation Issues 

Under the Public Utility Regulatory Policies Act of 1978, Docket No. AD16-16-000 

(Mar. 4, 2016) (announcing preliminary agenda and inviting interested speakers). 

141 Nonregulated electric utilities implement the requirements of PURPA with 

respect to themselves. An electric utility that is “nonregulated” is any electric utility other 

than a “state regulated electric utility.” 16 U.S.C. 2602(9). The term “state regulated 
Docket Nos. RM19-15-000 and AD16-16-000 - 62 -

energy from QFs meet the statutory criteria described above, including that “[n]o such 

rule. . . shall provide for a rate which exceeds” the purchasing utility’s “incremental cost. . 

. of alternative electric energy.”142 Under PURPA, such rates must: (1) be just and 

reasonable to the electric consumers of the electric utility and in the public interest; (2) not 

discriminate against qualifying cogenerators or qualifying small power producers;

143 and, 

as noted above, (3) not exceed “the incremental cost to the electric utility of alternative 

electric energy,”144 which is “the cost to the electric utility of the electric energy which, 

but for the purchase from such cogenerator or small power producer, such utility would 

generate or purchase from another source.”145 The “incremental cost to the electric utility 

of alternative electric energy” referred to in prong (3) above, which sets out a statutory 

upper bound on a QF rate, has been consistently referred to by the Commission and 

industry by the short-hand phrase “avoided cost,”146 although the term “avoided cost” 

itself does not appear in PURPA. 

electric utility,” in contrast, means any electric utility with respect to which a state 

regulatory authority has ratemaking authority. 16 U.S.C. 2602(18). The term “state 

regulatory authority,” as relevant here, means a state agency which has ratemaking 

authority with respect to the sale of electric energy by an electric utility. 16 U.S.C. 

2602(17). 

142 16 U.S.C. 824a-3(b).

143 16 U.S.C. 824a-3(b)(1)-(2).

144 16 U.S.C. 824a-3(b).

145 16 U.S.C. 824a-3(d) (emphasis added).

146 See 18 CFR 292.101(b)(6) (defining avoided costs in relation to the statutory 

terms); see also Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,865 (“This definition is 

derived from the concept of ‘the incremental cost to the electric utility of alternative 
Docket Nos. RM19-15-000 and AD16-16-000 - 63 -

97. In addition, the PURPA Regulations currently provide a QF two options for how to 

sell its power to an electric utility. The QF may choose to sell as much of its energy as it 

chooses when the energy becomes available, with the rate for the sale calculated at the 

time of delivery (frequently referred to as a so-called “as-available” sale and rate).147 

Alternatively, the QF may choose to sell pursuant to a legally enforceable obligation or 

LEO (such as a contract) over a specified term.148

98. If the QF chooses to sell under the second option, the PURPA Regulations then 

provide the QF the further option of receiving, in terms of pricing, either: (1) the 

purchasing electric utility’s avoided cost calculated at the time of delivery;

149 or (2) the 

purchasing electric utility’s avoided cost calculated and fixed at the time the LEO is 

incurred.

150

99. In implementing the PURPA Regulations, the Commission recognized that a 

contract with avoided costs calculated at the time a LEO is incurred could exceed the 

electric 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.”).

147 18 CFR 292.304(d)(1).

148 18 CFR 292.304(d)(2)(i)-(ii); see also FLS, 157 FERC ¶ 61,211 at P 21 (citing 

18 CFR 292.304(d)). The LEO or contract is frequently referred to as a long-term 

transaction, when contrasted with an “as available” sale and rate.

149 18 CFR 292.304(d)(2)(i).

150 18 CFR 292.304(d)(2)(ii). Rates calculated at the time of a LEO (for example, a 

contract) do not violate the requirement that the rates not exceed avoided costs if they 

differ from avoided costs at the time of delivery. 18 CFR 292.304(b)(5).
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electric utility’s avoided costs at the time of delivery in the future, thereby seemingly 

violating PURPA’s requirement that QFs not be paid more than an electric utility’s 

avoided costs. But the Commission believed that the fixed avoided cost rate might also 

turn out to be lower than the electric utility’s avoided costs over the course of the contract 

and that, “in the long run, ‘overestimations’ and ‘underestimations’ of avoided costs will 

balance out.”151 The Commission’s justification for allowing QFs to fix their rate at the 

time of the LEO for the entire life of the contract was that fixing the rate provides 

“certainty with regard to return on investment in new technologies.”152

100. In the NOPR, the Commission proposed to revise its PURPA Regulations to permit 

states to incorporate competitive market forces in setting QF rates. Specifically, the 

Commission proposed to revise its PURPA Regulations with regard to QF rates to provide 

states with the flexibility to: 

• require that “as-available” QF energy rates paid by electric utilities located in 

RTO/ISO markets be based on the market’s LMP, or similar energy price derived 

by the market, in effect at the time the energy is delivered.

151 Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,880. See also 18 CFR 

292.304(b)(5) (“In the case in which the rates for purchases are based upon estimates of 

avoided costs over the specific term of the contract or other legally enforceable obligation, 

the rates for such purchases do not violate this subpart if the rates for such purchases differ 

from avoided costs at the time of delivery.”); Entergy Servs., Inc., 137 FERC ¶ 61,199, at 

P 56 (2011) (“Many avoided cost rates are calculated on an average or composite basis, 

and already reflect the variations in the value of the purchase in the lower overall rate. In 

such circumstances, the utility is already compensated, through the lower rate it generally 

pays for unscheduled QF energy, for any periods during which it purchases unscheduled 

QF energy even though that energy’s value is lower than the true avoided cost.”).

152 Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,880. 
Docket Nos. RM19-15-000 and AD16-16-000 - 65 -

• require that “as-available” QF energy rates paid by electric utilities located outside 

of RTO/ISO markets be based on competitive prices determined by: (1) liquid 

market hub energy prices; or (2) formula rates based on observed natural gas prices 

and a specified heat rate.

• require that energy rates under QF contracts and LEOs be based on as-available 

energy rates determined at the time of delivery rather than being fixed for the term 

of the contract or LEO.

• implement an alternative approach of requiring that the fixed energy rate be 

calculated based on estimates of the present value of the stream of revenue flows of 

future LMPs or other acceptable as-available energy rates at the time of delivery.

• require that energy and/or capacity rates be determined through a competitive 

solicitation process, such as an RFP, with processes designed to ensure that the 

competitive solicitation is performed in a transparent, non-discriminatory 

fashion.153

101. Although the Commission proposed to modify how the states are permitted to 

calculate avoided costs, it did not propose to terminate the requirement that the states 

continue to calculate, and to set QF rates at, such avoided costs. 

102. We adopt these proposals in this final rule, with certain modifications. Each such 

proposal, and our final determination, is discussed further below.

2. Use of Competitive Market Prices to Set As-Available Avoided 

Cost Rates

103. In addition to commenting on the specific methods for determining as-available 

avoided cost rates, several commenters addressed more generally the Commission’s 

proposal in the NOPR that states be given the flexibility to use competitive market prices 

to set such rates. Before discussing the specific methods proposed in the NOPR, we first 

153 NOPR, 168 FERC ¶ 61,184 at PP 32-33.
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discuss the determination that the use of competitive market prices, however determined, 

can be an appropriate approach to determining as-available avoided cost rates.

a. NOPR Proposal

104. In the NOPR, the Commission proposed to give the states the flexibility to use 

competitive market prices to set as-available avoided cost rates. The Commission stated 

its belief that consideration of transparent, competitive market prices in appropriate 

circumstances would help to identify an electric utility’s avoided costs in a simpler, more 

transparent, and more predictable manner that would, in conjunction with the 

Commission’s other existing and proposed PURPA Regulations, act to encourage QFs.154 

105. For those utilities located in RTO/ISO markets, the NOPR identified LMP as a

competitive market price that states could choose to adopt as representing an as-available 

avoided energy cost. The Commission explained that LMP could provide an accurate 

measure of the varying actual avoided costs for each receipt point on an electric utility’s 

system where the utility receives power from QFs.155 In addition to these benefits, the 

Commission observed that LMPs, in contrast to the administrative pricing methodologies 

used to set as-available QF rates by many states, could promote the more efficient use of 

the transmission grid, promote the use of the lowest-cost generation, and provide for 

transparent price signals.156

154 Id. P 13.

155 Id. P 45. 

156 Id. P 48 (citing Cal. Indep. Sys. Operator Corp., 105 FERC ¶ 61,140, at PP 48-50 

(2003); Cf. Price Formation in Energy and Ancillary Servs. Mkts Operated by Reg’l 
Docket Nos. RM19-15-000 and AD16-16-000 - 67 -

106. For utilities located outside of RTO/ISO markets, the NOPR proposed to allow 

states to use two other potential competitively priced measures of a utility’s as-available 

avoided cost rates: (1) energy rates established at liquid market hubs; or (2) energy rates 

determined pursuant to formulas based on natural gas price indices and a proxy heat rate 

for an efficient natural gas combined-cycle generating facility. In each such case, though, 

the state would need to find that that price reasonably represents a competitive market 

price that represents the avoided costs of the purchasing electric utility.

157

b. Comments

107. Allco argues that the only reason for including the use of competitive market prices 

to set as-available energy rates is to create a menu of prices from which a state regulatory 

authority or unregulated electric utility can choose the lowest price. Allco claims this 

proposal would not encourage QF generation, would be inconsistent with the rules of 

economic dispatch, and would be inconsistent with the language of PURPA.158 BluEarth 

makes similar arguments.159 In contrast, El Paso Electric argues that state regulatory 

authorities should be able to set avoided cost rates based on the lesser of a market hub 

price or a combined cycle price.160 Similarly, the California Commission argues that 

Transmission Orgs. and Indep. Sys. Operators, 153 FERC ¶ 61,221, at P 2 (2015)).

157 NOPR, 168 FERC ¶ 61,184 at P 51. 

158 Allco Comments at 8.

159 BluEarth Comments at 2.

160 El Paso Electric Comments at 3-4.
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utilities located in organized markets (not just non-organized markets) should also be 

expressly permitted to use any competitive price (whether derived from a market hub, 

competitive solicitation, or a combined cycle price) to set avoided cost rates. The

California Commission also argues that states should have the ability to use competitive 

prices for not just as-available energy pricing, but also for capacity pricing, and proposes 

minor modifications to the relevant regulation text proposed in the NOPR in order to 

clarify these points.161

108. The California Commission argues that the proposed regulations should be 

modified to: (1) define the newly permissible avoided cost methodologies within the 

definitions section of Part 292; (2) eliminate any perception that the new methodologies 

can only be used to set avoided costs for as-available energy; (3) allow any appropriate 

market-based methodology to set avoided-cost rates for energy, capacity or both; and 

(4) define “Organized Electric Market.”162 The California Commission believes that the 

new regulations should indicate: (1) that they do not provide states any more flexibility 

than they already have; (2) that utilities located in organized markets may use any Market 

Hub Price, Competitive Solicitation Price, or Combined Cycle Price to establish avoidedcost rates; and (3) that a price based on LMP or a Competitive Price is just and reasonable 

and nondiscriminatory.163 

161 California Commission Comments at 23-27.

162 Id. at 11-14.

163 Id. at 23-25.
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109. Some commenters object to the use of competitive markets prices on the grounds 

that these competitive prices represent only short-term, or spot prices that do not reflect 

the long-term marginal costs and other costs avoided by purchasing utilities.164 Similarly, 

some commenters assert that competitive prices cannot support the financing of QFs.165

110. Public Interest Organizations argue that using competitive prices to set as-available 

energy avoided cost rates is discriminatory because non-QF generators are not limited to 

competitive prices and utilities can, and regularly do, pay effective prices for energy that 

exceed the price determined by competitive prices.166 Several other commenters express 

concern about setting QF prices by referencing short-term liquid hub prices while 

allowing utilities to rate base and recover their long-term investments.167 Industrial 

Energy Consumers argue that, if the Commission implements the liquid market hub 

proposal, there must be assurances that utilities’ self-builds face the same market risk 

exposure as QFs. For example, they argue, if states expose QFs to variable rates for their 

energy output, utility-owned generation should also be exposed to variable rates for their 

energy output.168

164 IdaHydro Comments at 11; Southeast Public Interest Organizations Comments 

at 19; NIPPC, CREA, REC, and OSEIA Comments at 52, 55 (citing Exelon Wind I, LLC, 

140 FERC ¶ 61,152, at P 52 (2012)); Union of Concerned Scientists Comments at 6.

165 BluEarth Renewables Comments at 2; Biological Diversity at 8; Covanta 

Comments at 9; Public Interest Organization Comments at 43-44.

166 Public Interest Organizations Comments at 64.

167 IdaHydro Comments at 11; Industrial Energy Consumers Comments at 12-13.

168 Industrial Energy Consumers Comments at 12-13.
Docket Nos. RM19-15-000 and AD16-16-000 - 70 -

111. Several commenters assert that QF rates should reflect benefits other than the 

avoided cost of energy.169 For example, Biogas and Biomass Power state that non-energy 

benefits, like waste reduction and economic development must be incorporated into 

avoided cost determinations.170 Biogas and Resources for the Future state that locational 

values should be incorporated into avoided cost calculations.171 American Dams states 

that utilities’ avoided transmission charges should be included in avoided cost 

determinations.172 Xcel states that hidden integration and utility planning costs should 

also be incorporated into avoided cost calculations.173 American Dams argues that for 

high capital projects like hydro, the Commission should consider longer-term public 

benefits and not just short-term market pricing.174

112. Solar Energy Industries asserts that payments based on the LMP should not relieve 

the purchasing utility of the requirement to compensate the QF for any values in addition 

to electricity (e.g., renewable energy credits, frequency response capabilities, pro-rated 

capacity value, etc.).175 

169 Biogas Comments at 1-2; Biomass Power Comments at 1; EPSA Comments at 

14-16; Resources for the Future Comments at 4; Xcel Comments at 3-5.

170 Biogas Comments at 2; Biomass Power Comments at 1.

171 Biogas Comments at 1; Resources for the Future Comments at 4.

172 American Dams Comments at 4.

173 Xcel Comments at 3-5.

174 American Dams Comments at 2.

175 Solar Energy Industry Comments at 27-28.
Docket Nos. RM19-15-000 and AD16-16-000 - 71 -

113. California Utilities request that the Commission clarify that states may but are not 

required to consider state policies when establishing avoided costs.

176 Harvard Electricity 

Law requests that the Commission clarify its rule allowing states to set tiered rates.177

c. Commission Determination

114. As an initial matter, we observe that some of the concerns raised by commenters 

about the use of competitive market prices to set as-available energy rates for QFs are 

based on the incorrect assumption that the NOPR proposal would permit states to use 

competitive market prices to set as-available energy rates for QFs even when competitive 

market prices are below the purchasing utility’s avoided costs. In fact, however, the use 

of competitive market prices to set QF rates is explicitly subject to the requirement that 

such prices are equal to the purchasing utility’s avoided energy costs.178 As the Supreme 

Court noted in API, the full avoided cost rate requirement represents the maximum rate 

permitted under PURPA, and thereby provides important encouragement to QFs.179 And 

as the Supreme Court also noted in the same decision, “the full-avoided-cost rule plainly 

satisfies the nondiscrimination requirement.”180 Further, in requiring full avoided cost 

176 California Utilities Comments at 18-19.

177 Harvard Electricity Law Comments at 32-33.

178 Arguments that the various competitive market prices identified in this final rule 

do not represent avoided energy costs are addressed below with respect to each such 

specific market price.

179 API, 461 U.S. at 413.

180 Id.
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rates, “[t]he Commission did not ignore the interest of electric utility consumers ‘in 

receiving electric energy at equitable rates.’”181

115. For this reason, Allco is incorrect when it claims that the competitive price 

proposal represents a menu of prices that a state can select to choose the lowest rate. In 

the event that more than one competitive price option potentially could apply, the state 

would be required to select the option that reasonably reflects the purchasing utility’s 

avoided costs, which is what PURPA requires.182

116. Further, the record supports the conclusion that the use of transparent, competitive 

market prices provides encouragement to QFs, represents the avoided cost, and can ensure 

that the rate does not exceed the incremental cost to the purchasing electric utility. In 

addition to the testimony to this effect presented at the technical conference and cited in 

the NOPR,183 the conclusion is further supported by comments submitted in response to 

181 Id. at 415 (quoting Conf. Rep. at 97).

182 In a competitive market, the transportation costs between any such two hubs and 

a QF would be such that they would make the QF rate the same, no matter which hub was 

selected. See FERC, Energy Primer, A Handbook of Market Basics, at 64 (June 2020), 

https://www.ferc.gov/market-assessments/guide/energy-primer-2020.pdf (Energy Primer) 

(“If there are no transmission constraints, or congestion, LMPs will not vary significantly 

across the RTO footprint. However, when transmission congestion occurs, LMPs will vary 

across the footprint because operators are not able to dispatch the least-cost generators 

across the entire region and some more expensive generation must be dispatched to meet 

demand in the constrained area.”).

183 See American Forest & Paper Association Comments, Docket No. AD16-16-

000, at 8 (filed June 8, 2016) (“To the extent possible, these determinations [of avoided 

costs] should not be made in a ‘black box’, but rather, as part of an open and transparent 

method and process.”); EEI Comments, Docket No. AD16-16-000, at 3 (filed June 30, 

2016) (“Where transparent competitive markets with day ahead prices exist, there is no 
Docket Nos. RM19-15-000 and AD16-16-000 - 73 -

the NOPR. For example, NIPPC, CREA, REC, and OSEIA cite to a report by Fitch, 

which explains how Fitch evaluates the financial strength of renewable energy projects. 

In this report, Fitch states that it gives a “stronger” evaluation to projects with power sales 

contract prices that are “indexed using simple, broad-based publicly available indexation 

formulas.”184 In addition, Solar Energy Industries notes the difficulties QFs face in 

expending large sums to develop their projects “[f]or states that do not publish the avoided 

costs, or for utilities that treat their avoided cost methodologies as confidential trade 

secrets.” 185 

117. We agree with commenters who assert that competitive market prices represent 

only short-run spot prices that do not reflect electric utilities’ long-run costs that QFs can 

displace. However, we are authorizing states to use competitive market prices only to 

establish as-available energy rates for QFs. The comments misunderstand the 

fundamental difference between the value to a purchasing utility of such as-available 

energy and the value to a purchasing utility of capacity.

118. A QF has no obligation under the as-available avoided cost rate provisions to 

deliver any set amount of electric energy at any point in the future, but merely is paid for 

the amount of electric energy actually delivered. Therefore, the delivery of as-available 

reason to adhere to second-best avoided cost pricing mechanisms.”).

184 NIPPC, CREA, REC, and OSEIA Comments at 37-38 (citing FitchRatings, 

Global Infrastructure & Project Finance, Renewable Energy Project Rating Criteria, at 3

(Feb. 26, 2019), https://www.fitchratings.com/site/re/10061770).

185 Solar Energy Industries Comments at 41.
Docket Nos. RM19-15-000 and AD16-16-000 - 74 -

energy does not displace any long-term energy the purchasing electric utility would 

generate itself or purchase from another source but rather allows the purchasing utility to 

reduce the amount of energy it otherwise would generate itself or purchase from another 

entity at the time the QF delivers the energy. Because the QF has no obligation to deliver 

any energy in the future, the utility is unable to avoid constructing or contracting for 

capacity to meet its future needs as a consequence of the delivery of energy by the QF. 

As-available energy rates therefore appropriately reflect only the short-run value of energy 

delivered at the particular moment in time when and if the QF has energy available to be 

delivered to the utility. 

119. A QF can displace an electric utility’s own generation or purchases from alternative 

sources over the long-run when a QF sells capacity to a utility in addition to as-available 

energy. In contrast to as-available energy, a sale of capacity would typically compensate 

the QF for maintaining the capability to deliver a set amount of energy in the future (i.e., 

capital costs),

186 and thus allows the purchasing utility to avoid the cost of making 

alternative arrangements, either through a self-build or an alternative purchase, to obtain 

that amount of energy. Consequently, the price of capacity purchased from a QF would

reflect this long-run avoided cost. And this final rule does not alter a purchasing utility’s 

186 See Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,885 (“Energy costs are 

the variable costs associated with the production of electric energy (kilowatt-hours). They 

represent the cost of fuel, and some operating and maintenance expenses. Capacity costs

are the costs associated with providing the capability to deliver energy; they consist 

primarily of the capital costs of facilities.”).
Docket Nos. RM19-15-000 and AD16-16-000 - 75 -

existing obligation to pay QFs for any avoided capacity benefit that allows the utility to 

avoid acquiring capacity.187

120. For these reasons, we decline to grant the California Commission’s request to allow

using competitive prices for not just as-available energy pricing, but also for capacity 

pricing.

188 We also reject the California Commission’s request to permit all electric 

utilities, both those located in organized markets and those located in non-organized 

market areas, to use any competitive price (whether a Market Hub Price or Combined 

Cycle Price, or alternatively a Competitive Solicitation Price) to set avoided cost rates. 

The Market Hub Price and Combined Cycle Price, as well as the Competitive Solicitation 

Price are options that should generally reflect a purchasing electric utility’s avoided asavailable energy costs in non-RTO/ISO areas, while the LMP should generally reflect a 

purchasing electric utility’s avoided as-available energy costs in RTO/ISO market areas.

121. With respect to the discrimination claims, our decision to give states the flexibility 

to use competitive prices is driven by the fact that the competitive market price represents

the purchasing utility’s avoided costs. And, as explained in Section IV.A.2 above, a rate 

set at full avoided costs by definition cannot be discriminatory and, in any event, the 

Commission is without authority under PURPA section 210(b) to require a rate above 

avoided costs. 

187 See Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,881-86 (describing how 

states must calculate avoided capacity costs).

188 See infra sections IV.B.3-5. We note that states may use competitive 

solicitations to set both energy and capacity avoided cost rates. See infra section IV.B.8.
Docket Nos. RM19-15-000 and AD16-16-000 - 76 -

122. Further, Industrial Energy Consumers are incorrect when they suggest that public 

utility energy rates do not vary with costs in the same way that the competitive market 

prices potentially applicable to QFs under the final rule vary. To the contrary, the 

Commission and most states provide for fuel adjustment clauses applicable to rates, which 

allow utility rates to adjust automatically with changes in utility fuel and purchased power 

costs.189 And even utilities whose rates do not include fuel and purchased power

adjustment clauses nevertheless typically must charge their retail customers cost-based 

rates, which means that their energy charges will vary from one rate case to the next as 

their fuel and purchased power costs vary from year to year. These mechanisms for 

ensuring that utility rates vary with the cost of energy result in variances in utility energy 

rates that are similar to the variance in QF energy rates for those states that elect a

Competitive Price option (either a Market Hub Price or a Combined Cycle Price) for asavailable avoided cost rates.

123. Finally, although we are sympathetic to the claims of certain QFs that they provide 

non-energy benefits (such as environmental benefits, waste reduction benefits, and

economic development benefits) that are not reflected in avoided cost rates, PURPA 

section 210(b) prohibits the Commission from requiring QF rates to be set above full 

189 See 18 CFR 35.14 (Fuel Cost and Purchased Economic Power Adjustment 

Clauses); ELCON, Fuel Adjustment Clauses & Other Cost Trackers, 

https://elcon.org/fuel-adjustment-clauses-cost-trackers (“Fuel adjustment clauses are in 

effect in almost all states.”); NARUC, Staff Subcommittee on Accounting and Finance, 

Fuel and Purchased Power Survey Results (Sept. 23, 2015),

https://pubs.naruc.org/pub/4AA28D50-2354-D714-5149-B773EFC3EFEF (stating that 

only one state surveyed said that it did not employ a fuel adjustment clause).
Docket Nos. RM19-15-000 and AD16-16-000 - 77 -

avoided costs. Because the Commission already requires states to set QF rates at full 

avoided costs, it is barred from requiring QF rates set higher than that based on the nonenergy benefits that QFs may also provide. However, nothing in PURPA, the PURPA 

Regulations as they currently exist, or this final rule would prevent states from rewarding

QFs for such non-energy benefits so long as that is done outside of PURPA, such as is 

now done for renewable energy credits (RECs) to compensate QFs for providing unique 

environmental or other non-PURPA benefits.190 We address in the sections below each 

type of competitive price that could be used as an acceptable energy avoided cost.

3. LMP as a Permissible Rate for Certain As-Available Avoided 

Cost Rates

a. NOPR Proposal

124. The Commission proposed to revise 18 CFR 292.304 to add subsections (b)(6) and 

(e)(1). In combination, these subsections would permit a state the flexibility to set the asavailable energy rate paid to a QF by an electric utility located in an RTO/ISO at LMPs

calculated at the time of delivery.

125. The Commission explained that RTO/ISO markets calculate a LMP at each 

location on the RTO/ISO-controlled grid, and that all sellers receive the LMP for their 

location and all buyers pay the market clearing price for their location. The Commission 

further recognized that LMPs reflect the true marginal cost of production, taking into 

190 See, e.g., American Ref-Fuel Co., 105 FERC ¶ 61,004, at PP 22-24 (2003), 

denying reh’g, 107 FERC ¶ 61,016 at PP 12, 15-16 (2004), dismissing pet. for review sub 

nom. Xcel Energy Servs. Inc. v. FERC, 407 F.3d 1242 (D.C. Cir. 2005).
Docket Nos. RM19-15-000 and AD16-16-000 - 78 -

account all physical system constraints, and these prices would fully compensate all 

resources for the variable cost of providing service,

191 and explained that prices in such an 

LMP-based rate structure are designed to reflect the least-cost of meeting an incremental 

megawatt-hour of demand at each location on the grid in each period, and thus such prices 

can vary based on location and time.192 

126. The Commission therefore preliminarily found that LMP is an accurate measure of 

avoided costs. Unlike, for example, average system-wide cost measures of avoided cost 

used by many states, LMP could provide an accurate measure of the varying actual 

avoided costs for each receipt point on an electric utility’s system where the utility 

receives power from QFs; LMP is the per MWh cost of obtaining incremental supplies at 

each point. Further, the Commission explained that these prices are not rigid, long-lasting 

prices as tends to be the case currently for administratively-determined avoided costs, but 

prices that are calculated daily (for the day-ahead markets) and/or every five minutes (for 

real-time markets) and they vary to reflect changing system conditions (e.g., they tend to 

rise as demand increases and the system operator dispatches increasingly expensive 

supplies to meet that higher demand). In addition, the Commission observed that LMPs, 

in contrast to the administrative pricing methodologies used to set as-available QF rates by 

191 Offer Caps in Mkts Operated by Reg’l Transmission Orgs. and Independent Sys. 

Operators, Order No. 831, 157 FERC ¶ 61,115, at P 7 (2016), order on reh’g and 

clarification, Order No. 831-A, 161 FERC ¶ 61,156 (2017).

192 Sacramento Mun. Util. Dist. v. FERC, 616 F.3d 520, 524 (D.C. Cir. 2010) 

(SMUD); see also FERC v. Elec. Power Supply Ass’n, 136 S. Ct. 760, 768-69 (2016) 

(describing how LMP is typically calculated).
Docket Nos. RM19-15-000 and AD16-16-000 - 79 -

many states, could promote the more efficient use of the transmission grid, promote the 

use of the lowest-cost generation, and provide for transparent price signals.193 Finally, the 

Commission also noted that Congress, through enactment of PURPA section 210(m), 

appears to have recognized that RTO/ISO LMP pricing provides sufficient encouragement 

for QFs. 

127. The Commission requested comment on whether the real-time prices established in 

the CAISO-administered Energy Imbalance Market (EIM)194 are similar for these 

purposes to the LMP in RTOs/ISOs. In this regard, the Commission requested comment 

on whether “prices developed in the EIM similarly ‘reflect the least-cost of meeting an 

incremental megawatt-hour of demand at each location on the grid,’ as the Commission 

has found to be the case with LMP rates.”195 

193 See, e.g., Cal. Indep. Sys. Operator Corp., 105 FERC ¶ 61,140, at PP 48-50 

(2003); cf. Price Formation in Energy and Ancillary Servs. Mkts Operated by Reg’l 

Transmission Orgs. and Indep. Sys. Operators, 153 FERC ¶ 61,221, at P 2.

194 The Commission noted that, by seeking comment regarding the Western EIM 

prices, the Commission did not mean to imply that real-time energy prices established by 

CAISO within its balancing authority area do not already satisfy the requirement for 

setting as-available QF rates.

195 NOPR, 168 FERC 61,184 at P 47 (quoting SMUD, 616 F.3d at 524). Use of 

real time prices in the Western EIM was addressed at the Technical Conference, but only 

in the context of whether that market could satisfy the requirements for termination of the 

mandatory purchase obligation under PURPA section 210(m)(1)(C). See Supplemental 

Notice of Technical Conference, Implementation Issues Under the Public Utility 

Regulatory Policies Act of 1978, Docket No. AD16-16-000 (May 9, 2016). The

Commission here requested comments on whether it would be appropriate to use the 

Western EIM price to develop an as-available energy rate.
Docket Nos. RM19-15-000 and AD16-16-000 - 80 -

128. The Commission understood that some states already use LMP to establish avoided 

cost energy rates under the existing PURPA Regulations.196 The Commission thus 

proposed also to clarify that, while a state in the past may have been able to conclude that 

LMP was an appropriate measure of the energy component of avoided costs,197 a state 

would, under the proposal in the NOPR, be able to adopt LMP as a per se appropriate 

measure of the as-available energy component of avoided costs.198

196 See Exelon Wind 1, LLC, 140 FERC ¶ 61,152, at P 11, reconsideration denied, 

155 FERC ¶ 61,066 (2016) (recognizing that the Texas Public Utility Commission has 

permitted Southwestern Public Service Company to set avoided costs at LMP); Xcel 

Energy Services Inc., Request for Reconsideration, Docket No. EL12-80-001, at 13 & 

n.23 (filed Sept. 27, 2012) (stating that Maryland, New Jersey, North Carolina, Virginia, 

Connecticut, New Hampshire, Kentucky, and Michigan have set avoided costs at LMP).

197 See 18 CFR 292.304(e).

198 The Commission recognized in the NOPR that this proposal could be seen as a 

departure from the Commission’s statement in Exelon Wind 1, LLC, 140 FERC ¶ 61,152 at 

P 52, reconsideration denied, 155 FERC ¶ 61,066 (“The problem with the methodology 

proposed by [Southwestern Public Service Company] and adopted by the Texas 

Commission is that it is based on the price that a QF would have been paid had it sold its 

energy directly in the [Energy Imbalance Service] Market, instead of using a methodology 

of calculating what the costs to the utility would have been for self-supplied, or purchased, 

energy ‘but for’ the presence of the QF or QFs in the markets, as required by the 

Commission’s regulations.”). The Commission has since found that this statement was 

overtaken by events, namely SPP’s evolution from an energy imbalance service market 

into an Integrated Marketplace, with day-ahead and real-time energy and operating reserve 

markets and the Texas Commission’s approving a separate request from Southwestern 

Public Service Company to substitute LMP for Locational Imbalance Prices in calculating 

avoided costs. Exelon Wind 1, LLC, 155 FERC ¶ 61,066 at P 11. The Commission also 

has acknowledged that, if adopted in a final rule, the reasoning in the NOPR supported a

departure from precedent. See Cal. Pub. Utils. Comm’n v. FERC, 879 F.3d 966, 977 (9th 

Cir. 2018) (“When an agency changes policy, the requirement that it provide a reasoned 

explanation for its action demands, at a minimum, that the agency ‘display awareness that 

it is changing position.’”) (citing FCC v. Fox Television Stations, Inc., 556 U.S. 502, 515

(2009)). 
Docket Nos. RM19-15-000 and AD16-16-000 - 81 -

b. Comments

i. Comments in Opposition

129. Several commenters oppose the NOPR’s LMP proposal.199 American Biogas 

asserts that, by definition, LMP rates assume that generating facilities are receiving other 

compensation to fund their operations and that the marginal rate reflects only the value of 

the energy. American Biogas asserts that LMP ignores biogas facilities’ unique municipal 

infrastructure role and multiple benefits to the community.200 Covanta argues that avoided 

costs paid to small baseload QFs should incorporate all long-run avoided costs for 

capacity and energy and include other externalities such as the value of renewable 

baseload energy, greenhouse gas mitigation, landfill diversion, reliable and resilient power 

and other benefits of small baseload QFs.201 Biological Diversity argues that LMP pricing 

ignores variability across the country and is inappropriate in regions like the Southeast 

which lack RTOs and ISOs and are instead still dominated by vertically-integrated 

monopolies.202

199 Biogas Comments at 2; Covanta Comments at 8-9; Biological Diversity 

Comments at 8-9; CA Cogeneration Comments at 8-9; ELCON Comments at 23-25; 

ENGIE Comments at 4; New England Small Hydro Comments at 8-11; NIPPC, CREA, 

REC, and OSEIA Comments at 53-60; Public Interest Organizations Comments at 52-64; 

Union of Concerned Scientists Comments at 4-9; Southeast Public Interest Organizations 

Comments at 21-25.

200 Biogas Comments at 2.

201 Covanta Comments at 8.

202 Biological Diversity Comments at 8-9.
Docket Nos. RM19-15-000 and AD16-16-000 - 82 -

130. CA Cogeneration argues that LMP may not represent a truly competitive price for 

electricity because, in California, the majority of supply is through bilateral contracts, not 

through competitive bidding in the market. CA Cogeneration states that rooftop solar 

distorts LMP by reducing load and not bidding in its full long-term marginal cost.203 CA 

Cogeneration states that LMPs can be well below the operating cost of conventional 

generation and combined heat and power, and even negative, especially when there is an 

abundance of procured resources such as hydro, solar, and wind.204 CA Cogeneration 

asserts that combined heat and power can survive only if: (1) fixed capacity prices are 

sufficiently high to cover the energy price risk; (2) the market price reflects the full cost of 

contracted power and includes all sources of supply; or (3) 18 CFR 292.304(f)(1) is 

modified to provide QF operations first priority, except in special circumstances related to 

reliability.205

131. ELCON argues that allowing utilities to use LMP and other competitive market 

prices would allow states to ignore long-standing factors established by Commission 

regulation in determining the avoided cost rates, including: (1) availability of capacity or 

energy from a QF during the system daily and seasonal peak periods; (2) dispatchability 

and reliability; (3) the relationship of the availability of energy or capacity from the QF to 

the ability of the utility to avoid costs; (4) costs or savings from variations in line losses;

203 CA Cogeneration Comments at 8-9.

204 Id.

205 Id.
Docket Nos. RM19-15-000 and AD16-16-000 - 83 -

and (5) application of technology-specific avoided cost rates.206 ENGIE argues that 

allowing states to set energy rates at LMP, while also allowing them to set capacity rates 

at zero if it is determined that a utility has no need for capacity, could allow traditional 

utilities to corner the market on capacity, leaving smaller independent QFs to fill energyonly contracts at LMP.207

132. New England Small Hydro states that the Commission has not supported the 

NOPR’s assertion that LMP is an accurate measure of avoided costs because the NOPR:

(1) inappropriately relies on the Energy Policy Act of 2005’s changes in PURPA section 

210(m) to support its proposed changes to calculation of the avoided cost rate; (2) ignores 

the costs that the utility pays to procure power (i.e., RFPs, other power contracts, planned 

retirements); and (3) ignores the fact that LMP and the default service rates that exist in 

ISO-NE-based states are quite different.208 In addition, New England Hydro states that,

for the avoided cost calculation, the appropriate LMP is the day-ahead LMP, not the realtime LMP, because utilities primarily purchase energy in the day-ahead market pursuant 

to bilateral contracts or RFPs, not in the real-time market.209 New England Hydro also 

believes that utilities or state regulatory bodies should be required to establish and 

206 ELCON Comments at 23-24.

207 ENGIE Comments at 4.

208 New England Small Hydro Comments at 8-10.

209 Id. at 10.
Docket Nos. RM19-15-000 and AD16-16-000 - 84 -

maintain long-term avoided energy forecasts upon which QF PURPA power purchase 

rates would be based.210 

133. NIPPC, CREA, REC, and OSEIA claim that LMPs only promote more efficient 

use of the transmission grid in the short-term because factors such as temporary outages, 

equipment failures, weather extremes, and the like can cause LMPs to spike, but these 

have no impact on long-term transmission availability.211 NIPPC, CREA, REC, and 

OSEIA believe that, while LMPs are a useful tool for developers to identify points on the 

grid where transmission is relatively more or less congested, developers have strong 

incentives to avoid congestion, and they will generally be guided to areas of low 

congestion during the transmission interconnection process, whether or not they face 

LMP-based contract prices. NIPPC, CREA, REC, and OSEIA claim that if transmission 

constraints prevent a generator from delivering power to a specific node, the LMP at that 

node cannot be an appropriate measure of costs avoided by purchase of power from that 

generator. NIPPC, CREA, REC, and OSEIA argue that LMP or Western EIM prices at 

the time of delivery are not a true measure of the long-term avoided costs of incumbent 

utilities unless those utilities are relying on those markets as a means to obtain long-term 

resources.212 

210 Id. at 11.

211 NIPPC, CREA, REC, and OSEIA Comments at 57-59.

212 Id. at 55 (citing Exelon Wind I, 140 FERC ¶ 61,152 at P 52). 
Docket Nos. RM19-15-000 and AD16-16-000 - 85 -

134. NIPPC, CREA, REC, and OSEIA assert that the NOPR proposal fails to recognize:

(1) the Commission’s struggle to develop effective capacity markets in the RTO/ISO

regions; (2) the fact that the merchant generation model is now in serious question; and (3) 

that the Commission’s claim that Congress endorsed the use of LMP to set avoided cost 

rates by adoption of section 210(m) cannot be squared with the plain language of the 

statute.213 NIPPC, CREA, REC, and OSEIA argue that there is substantial evidence that 

LMP prices are distorted by certain practices, such as zero-cost bids, so that plants operate 

uneconomically.214 NIPPC, CREA, REC, and OSEIA further maintain that the 2000-01 

California market demonstrated that these volatile short-term markets can reach extreme 

and unpredictable highs under stress conditions.

215 

135. Similarly, Public Interest Organizations cite to studies by the Sierra Club216 and 

Bloomberg New Energy Finance,217 for the proposition that the use of LMP as the QF 

price discriminates against QFs where utility-owned generation and non-QF generators are 

not limited to the LMP for recovery of their costs, and where utilities depress LMP 

213 Id. at 57-59.

214 Id. at 55.

215 Id. at 57.

216 Public Interest Organizations Comments at 53-56 (citing Jeremy Fisher, Sierra 

Club, Playing with Other People’s Money, How Non-Economic Coal Operations Distort 

Energy Markets, Sierra Club, Oct. 2019, at 4).

217 Id. at 57 (citing William Nelson & Sophia Liu, Half of U.S. Coal Fleet on Shaky 

Economic Footing; Coal Plant Operating Margins Nationwide, Bloomberg New Energy 

Finance, March 26, 2018).
Docket Nos. RM19-15-000 and AD16-16-000 - 86 -

through uneconomic dispatch of their own generation facilities.218 Union of Concerned 

Scientists states that LMPs are not an accurate measure of avoided costs and should not be 

used to set QF rates because the practice of providing utility-owned generation with outof-market cost-recovery in areas like MISO, PJM, SPP, the SERC Reliability Corporation, 

and the Western Electricity Coordinating Council suppresses the clearing prices in the 

markets where this is allowed.219

136. Southeast Public Interest Organizations argue that the NOPR’s proposed avoided 

cost methodology does not take into account: (1) long-term or seasonal purchases made 

from third parties or affiliates; (2) adjustments for transmission and distribution losses; (3) 

capacity deferrals; (4) avoided environmental compliance costs; or (5) a QF’s 

dispatchability.220 Southeast Public Interest Organizations state that LMP-based rates for 

QFs in Virginia have enticed little-to-no QF development in Virginia.221 Southeast Public 

Interest Organizations urge the Commission either to rescind the NOPR’s LMP provisions 

or at least to implement this provision on a case-by-case basis.222

218 Id. at 52-64.

219 Union of Concerned Scientists Comments at 3-8.

220 Southeast Public Interest Organizations Comments at 22.

221 Id. at 23.

222 Id. at 24.
Docket Nos. RM19-15-000 and AD16-16-000 - 87 -

(a) Utilizing Western EIM to Establish Avoided 

Costs

137. Solar Energy Industries argues that, because as-available QF resources are not 

eligible to participate in the Western EIM (also known as the CAISO EIM), either directly 

or through the purchasing utility, it would be inappropriate to use the Western EIM price 

as a proxy because that market does not factor in the participation of the QF resource.223 

ELCON asserts that the Western EIM is not a complete measure of avoided energy costs 

because the Western EIM merely covers imbalance conditions, and therefore does not 

capture the vast majority of unit commitment and dispatch scheduling cost parameters.224 

Union of Concerned Scientists asserts that allowing a state to adopt real-time prices 

established in the Western EIM as an accurate measure of avoided costs will be 

discriminatory.225

ii. Comments in Support

138. Several commenters support the Commission’s proposal to permit a state the 

flexibility to use LMPs to set the as-available energy rate paid to a QF by an electric 

utility located in an RTO/ISO.226 

223 Solar Energy Industries Comments at 27.

224 ELCON Comments at 24.

225 Union of Concerned Scientists Comments at 9.

226 APPA Comments at 11; Arizona Public Service Comments at 5; CA Utilities 

Comments at 17; Conn. Authority Comments at 13; DTE Electric Comments at 4; EEI 

Comments at 22-24; Comments at 4-5; Idaho Commission Comments at 3-4; Indiana 

Municipal Comments at 5; Kentucky Commission Comments at 4-5; NorthWestern 

Comments at 4-7; NRECA Comments at 6-7; Ohio Commission Energy Advocate 

Comments at 4-5; Pennsylvania Commission Comments at 7-9; South Dakota 
Docket Nos. RM19-15-000 and AD16-16-000 - 88 -

139. CA Utilities state that the NOPR’s LMP proposal is a return to the Commission’s 

policy as expressed in Winding Creek,

227 and will facilitate payments to QFs that more 

accurately represent a utility’s actual avoided costs. CA Utilities assert that the NOPR’s 

LMP proposal affirms that a formula energy price contract complies with PURPA if 

coupled with a fixed capacity price. CA Utilities state that a formula energy price contract

will have the additional benefit of avoiding the need to develop and administer a new 

PURPA contract.228

140. NRECA supports the Commission’s proposal because many utilities that 

participate in the RTO/ISO markets offer the entirety of their generation into the market,

and purchase all of their requirements to serve load from that market, at LMP prices.229

141. The Pennsylvania Commission supports the NOPR proposal because LMP prices 

vary through the day based on changing system conditions, such as changes in electricity 

demand, supply, congestion, and line losses. The Pennsylvania Commission asserts that,

because some utilities in Pennsylvania (and other states) have already incorporated LMP 

elements in their as-available energy rates, a corresponding revision to the Commission’s 

Commission Comments at 2; US Chamber of Commerce Comments at 4; We Stand 

Comments at 1; Xcel Comments at 5.

227 CA Utilities Comments at 15-17 (citing Winding Creek Solar LLC, 151 FERC 

¶ 61,103, at P 6 (2015)).

228 Id. at 17.

229 NRECA Comments at 6.
Docket Nos. RM19-15-000 and AD16-16-000 - 89 -

regulations that incorporates such practices and harmonizes state and federal regulations 

would bring greater predictability to suppliers, electric utilities and customers.230

142. The Ohio Commission Energy Advocate believes that, in the parts of the country 

with organized nodal wholesale electricity markets, LMP is an appropriate and fair means 

by which to calculate avoided costs because electricity supply and demand must be 

balanced in real time. The Ohio Commission Energy Advocate notes that Ohio has nodal 

LMPs that reflect the true value of energy at the place and the time it is produced or 

delivered, and this value can change dramatically, even within a day or an hour. The Ohio 

Commission Energy Advocate concludes that reflecting the dynamic nature of electricity 

pricing in avoided cost calculations will send the most accurate price signals to QFs and 

will appropriately and fairly value the energy they produce.231

143. The South Dakota Commission supports using LMP for certain as-available QF 

energy sales because using LMP will increase states’ flexibility. The South Dakota 

Commission regulates six vertically integrated electric utilities, five of which are RTO 

members, and five of which are multi-jurisdictional.232

144. Xcel submits that compensating QFs based on LMPs at the time of delivery will 

not impair QFs’ ability to obtain financing because other factors can drive the ability to 

obtain financing, including other project options, location, size, interconnection costs, 

230 Pennsylvania Commission Comments at 7-8.

231 Ohio Commission Energy Advocate Comments at 4-5.

232 South Dakota Commission Comments at 2.
Docket Nos. RM19-15-000 and AD16-16-000 - 90 -

experience of the developer, current economic conditions, creditworthiness of the 

developer, economies of scale, and other factors. Xcel states that some resource specific 

information generally suggests that the right project in the right location can obtain 

financing if the project receives hourly payment based on LMPs.233

(a) Utilizing Western EIM to Establish Avoided 

Costs

145. NorthWestern and EIM Entities agree that the Western EIM real-time prices are 

similar to LMPs and reflect the least cost of meeting an incremental megawatt-hour of 

demand at each location on the grid.234 Xcel asserts that prices in the Western EIM are 

calculated using the same methodology as LMPs because, in both cases, units are 

dispatched on a least-cost basis that respects applicable transmission constraints. Xcel 

requests that the Commission allow avoided costs to be based on Western EIM prices at 

the time of delivery absent a showing that prices would be suppressed in comparison to an 

LMP-style-market.235 Arizona Public Service states that it is a participant in the Western 

EIM, and requests that states be given flexibility to set the as-available energy rate to be 

paid to a QF by an electric utility that participates in the Western EIM at the LMP.236

233 Xcel Comments at 5-7.

234 EIM Entities Comments at 2-3, 7-13; NorthWestern Comments at 4-5.

235 Xcel Comments at 7-8.

236 Arizona Public Service Comments at 5-6.
Docket Nos. RM19-15-000 and AD16-16-000 - 91 -

iii. Comments in Support with Requested 

Modifications/Clarifications

146. APPA urges the Commission to clarify that nothing in the proposed rule is intended 

to call into question state regulatory authorities’ existing implementation of PURPA’s 

avoided cost requirements, such as their existing use of LMP.237

147. Industrial Energy Consumers do not object to the use of LMP as the avoided cost 

rate for electric utilities’ purchases of QF energy in RTO/ISO regions,238 but they maintain 

that in non-RTO/ISO regions, there must be assurance that utilities’ self-builds face the 

same market risk exposure as QFs.239

148. The Kentucky Commission supports the NOPR’s LMP proposal but prefers that the 

Commission in the final rule allow states to determine whether the LMP calculation 

should use the generator LMP or the load LMP on a case-by-case basis.240

149. Solar Energy Industries assert that, where the purchasing utility has demonstrated 

that it procures its marginal energy from an LMP market, the utility may use the LMP 

price as a proxy for avoided energy costs calculated at the time the obligation is incurred,

so long as there are published prices at the location.241 Solar Energy Industries request 

that the Commission make clear that: (1) the flexibility to set QF payment rates for as237 APPA Comments at 9.

238 Industrial Energy Consumers Comments at 11.

239 Id. at 12.

240 Kentucky Commission Comments at 4-5.

241 Solar Energy Industries Comments at 25-26.
Docket Nos. RM19-15-000 and AD16-16-000 - 92 -

available energy at the applicable LMP requires an on-the record determination that the 

purchasing utility procures incremental energy from the identified LMP market at those 

prices; (2) payments based on an LMP do not relieve the purchasing utility of the 

requirement to compensate the QF for any values in addition to electricity (e.g., renewable 

energy credits, frequency response capabilities, pro-rated capacity value, etc.); and (3) the 

state’s flexibility to allow utilities to set QF payment rates for as-available energy at the 

applicable LMP does not in any way limit QFs’ rights to establish a LEO or contract for a 

longer-term sale at fixed, full avoided costs.242

150. NorthWestern believes that as-available rates based on LMPs should accurately 

capture current events impacting prices, including times when there is a high saturation of 

energy available causing prices to be negative. However, NorthWestern believes that it is 

appropriate to deduct from the avoided cost rate the cost for ancillary services to balance 

and integrate energy resources.243 

c. Commission Determination

151. We affirm with one modification the NOPR proposal to allow LMP to be used as a 

measure of as-available energy avoided costs for electric utilities located in RTO/ISO 

markets for the reasons set forth in the NOPR244 and those provided by various 

commenters. 

242 Id. at 27-28.

243 NorthWestern Comments at 4-5.

244 NOPR, 168 FERC ¶ 61,184 at PP 44-45.
Docket Nos. RM19-15-000 and AD16-16-000 - 93 -

152. We recognize that an LMP selected by a state to set a purchasing utility’s avoided 

energy cost component might not always reflect a purchasing utility’s actual avoided 

energy costs. Accordingly, we find that it is appropriate to modify the option for a state to 

set avoided energy costs using LMP from a per se appropriate measure of avoided cost to

a rebuttable presumption that LMP is an appropriate means to determine avoided cost. 

While a state could rely on the presumption, an aggrieved entity (such as a QF) may 

attempt to rebut the presumption that LMP reflects the purchasing electric utility’s 

avoided costs. The aggrieved entity would be able to challenge the state’s decision to rely 

on LMP in the appropriate forum, which could include any one or more of the following: 

(1) initiating or participating in proceedings before the relevant state commission or 

governing body;; (2) filing for judicial review of any state regulatory proceeding in state 

court (under PURPA section 210(g)); or, alternatively (3)) filing a petition for 

enforcement against the state at the Commission and, if the Commission declines to act,

later filing a petition against the state in U.S. district court (under PURPA section 

210(h)(2)(B)).245 

153. Commenters have not persuaded us that LMP may not presumptively reflect a 

purchasing electric utility’s avoided energy costs. LMP sets day-ahead and real-time 

energy prices through competitive auctions in RTOs/ISOs that optimally dispatch 

resources to balance supply and demand, while taking into account actual system 

245 See Policy Statement Regarding the Commission's Enforcement Role Under 

Section 210 of the Public Utility Regulatory Policies Act of 1978, 23 FERC ¶ 61,304.
Docket Nos. RM19-15-000 and AD16-16-000 - 94 -

conditions including congestion on the transmission system. We continue to find that: (1)

LMPs reflect the true marginal cost of production of energy, taking into account all 

physical system constraints; (2) these prices would fully compensate all resources for their

variable cost of providing service; (3) LMP prices are designed to reflect the least-cost of 

meeting an incremental megawatt-hour of demand at each location on the grid, and thus 

prices vary based on location and time; and (4) unlike average system-wide cost measures 

of the avoided energy cost used by many states, LMP should provide a more accurate 

measure of the varying actual avoided energy costs, hour by hour, for each receipt point 

on an electric utility’s system where the utility receives power from QFs.246

154. Various commenters have provided additional reasons for supporting the NOPR 

proposal concerning LMP. NRECA explains that LMP rates for energy are appropriate 

because many utilities that participate in the RTO/ISO markets offer the entirety of their 

generation into the market at LMP prices and buy all of their load requirements from the 

market at LMP prices.247 This scenario described by NRECA is a common one, and it 

demonstrates that the market itself, with its LMP pricing, can be the electric utility 

resource that would be displaced by a QF purchase. Furthermore, as argued by

Pennsylvania Commission, because some utilities in Pennsylvania and other states have 

246 See NOPR, 168 FERC ¶ 61,184 at PP 44-45 (citing SMUD, 616 F.3d at 524;

FERC v. Elec. Power Supply Ass’n, 136 S. Ct. at 768-69 (describing how LMP is typically 

calculated); Order No. 831, 157 FERC ¶ 61,115, at P 7, order on reh’g and clarification, 

Order No. 831-A, 161 FERC ¶ 61,156).

247 NRECA Comments at 6.
Docket Nos. RM19-15-000 and AD16-16-000 - 95 -

already incorporated LMP in their as-available energy rates, a corresponding revision to 

the Commission’s regulations that incorporates such practices and harmonizes state and 

federal regulations would bring greater predictability to suppliers, electric utilities and 

customers.248 

i. Arguments Against the NOPR Proposal

155. Commenters have not offered persuasive arguments for rejecting the use of LMP 

for avoided cost energy rate determination. We disagree with the argument made by 

Union of Concerned Scientists,

249 NIPPC, CREA, REC, and OSEIA,250 and Public 

Interest Organizations251 that LMP should not be used as a measure of avoided energy 

costs because LMP prices are depressed in many markets where self-scheduling rights and 

state cost-recovery mechanisms for fuel and operating costs create the opportunity for 

market participation at a loss. We recognize that, all other things being equal, selfscheduling of resources may impact market clearing prices. This potential price effect, 

however, does not mean that the LMP is not an accurate measure of avoided energy costs. 

The Commission’s regulations, using language from PURPA section 210(d), define 

avoided costs as “the incremental costs to an electric utility of electric energy or capacity 

248 Pennsylvania Commission Comments at 7-8.

249 Union of Concerned Scientists Comments at 3-8.

250 NIPPC, CREA, REC, and OSEIA Comments at 52.

251 Public Interest Organizations Comments 52-64.
Docket Nos. RM19-15-000 and AD16-16-000 - 96 -

or both which, but for the purchase from the qualifying facility or qualifying facilities, 

such electric utility would generate for itself or purchase from another source.”252 

156. In organized wholesale electric market areas, the electric utility purchases that 

would be displaced by QF purchases would, as NRECA explains, in all likelihood be 

priced at the relevant LMP. These LMPs are impacted by many factors, such as selfscheduling, generator outages, and transmission outages, that may result in LMPs that are 

lower or higher than they might otherwise have been. Thus, while self-scheduling or other 

factors may impact LMPs, in any case, an electric utility’s purchases during periods when 

these price impacts are occurring would be made at the resulting LMPs, whatever those 

LMPs may be. Therefore, LMPs meet the Commission’s long-standing definition of 

avoided costs for a purchasing electric utility, even if they happen to reflect price impacts 

from self-scheduling or other factors.

157. Furthermore, while commenters discuss the possibility that utility-owned coal-fired 

resources are self-scheduling only because retail ratepayers are subsidizing such activities, 

even if such claims were true they would not alter the above analysis. The LMPs that 

result from a market that includes self-scheduled resources still represent the price of 

purchases in the market that would be displaced by the QF purchase. 

158. In addition, we reject the related request for clarification made by Solar Energy 

Industries,

253 i.e., that the flexibility to set QF payments for as-available energy at the 

252 18 CFR 292.101(b)(6) (emphasis added).

253 Solar Energy Industry Comments at 27-28.
Docket Nos. RM19-15-000 and AD16-16-000 - 97 -

applicable LMP should require an on-the-record determination that the purchasing utility 

procures incremental energy from the identified LMP market at those prices. Unless an 

aggrieved entity seeks to rebut this presumption in a state avoided cost adjudication, 

rulemaking, legislative determination, or other proceeding, that state would not need to 

make such an on-the-record determination before it decides to use LMP. 

159. Entities may seek to rebut the presumption in particular cases, as described earlier, 

and whether the utility actually procures energy from the identified LMP market or from 

resources with prices tied to the identified LMP may be a relevant factor in such rebuttal 

arguments. Consistent with the reasons described above for why there should be such a 

rebuttable presumption in favor of LMP, this delineation of rights appropriately places the 

initial burden on entities seeking to rebut the presumption, rather than on the states who 

wish to rely on LMP for setting avoided cost rates for as-available energy. The 

Commission could consider such issues if and when they may arise in individual cases

appropriately brought to the Commission, including whether the state has adequately 

justified its use of that rebuttable presumption.

160. We reject the arguments made by NIPPC, CREA, REC, and OSEIA that, more 

generally, prices for long-term QF contracts should be set by reference to long-term price 

indices or other indicators that genuinely reflect the long-term costs of generation avoided 

by the purchasing utility.254 This final rule only addresses as-available energy, and as254 NIPPC, CREA, REC, and OSEIA Comments at 53.
Docket Nos. RM19-15-000 and AD16-16-000 - 98 -

available energy prices by definition are short term, as explained below in 

Section IV.B.7.c. 

161. We also reject the arguments made by NIPPC, CREA, REC, and OSEIA that,

while the NOPR is correct that LMPs are intended to promote more efficient use of the 

transmission grid, that is true only in the short term since factors such as temporary 

outages, equipment failures, weather extremes, and the like can cause LMPs to spike, but 

these have no impact on long-term transmission availability. LMPs promote efficient use 

of the transmission grid in the long term as well as the short term. Persistence of 

significant price separation between different LMP nodes provides an indication of the 

value of various possible transmission system upgrades and can show transparently how 

system efficiencies may be improved by such transmission system upgrades. Developers 

may have some incentive to avoid congestion without LMPs, but LMPs provide an 

important price signal as to how economic or uneconomic a particular production site may 

be. In any event, the potential for more efficient use of the transmission grid is merely an 

additional benefit of using LMP for avoided energy cost determinations. Our adoption of 

LMP as a measure of avoided energy costs in the RTO/ISO markets is based principally

on the fact that, in RTO/ISO markets, LMP accurately represents the purchasing electric 

utility’s avoided energy cost at the time the energy is delivered, for the reasons described 

earlier.

162. We also are not persuaded by arguments that, if transmission constraints prevent a 

generator from delivering power to a specific node, the LMP at that node cannot be an 

appropriate measure of costs avoided by purchase of power from that generator. As 
Docket Nos. RM19-15-000 and AD16-16-000 - 99 -

discussed above, an avoided cost rate should reflect not only the cost of energy that was 

avoided by the purchasing electric utility, but also the cost to deliver the QF energy to the 

purchasing electric utility’s load, such that the total cost avoided is reflected in the rate. In 

an RTO/ISO market, a state appropriately is entitled to consider whether the cost of 

delivery from the QF node to the load node (including any redispatch costs necessary to 

facilitate such delivery over a system that is otherwise constrained between those nodes) 

should be reflected in the LMP at the QF supply node. In instances commenters refer to 

where transmission constraints prevent a generator from delivering power to a specific 

node, we disagree that such delivery is actually “prevented.” Rather, redispatch of system 

resources would be necessary to facilitate the delivery, and the respective LMPs reflect 

those redispatch costs. 

163. We also reject the argument made by NIPPC, CREA, REC, and OSEIA that the 

2000-01 California market demonstrated that volatile short-term markets can reach 

extreme and unpredictable highs under stress conditions.255 First we note that, in the wake 

of the 2000-2001 California energy crisis, all RTO/ISO markets developed more 

comprehensive ex ante market power mitigation measures than existed in CAISO at that

time, including offer caps and reference level replacement offers, meant in part to 

moderate such extremes.256 In any event, any price volatility that may currently exist in 

255 NIPPC, CREA, REC, and OSEIA Comments at 57. Curiously, these 

commenters here essentially take the position that higher LMPs and resulting higher 

avoided cost energy rates, which would normally seem to be beneficial to QFs, are instead 

now anathema. 

256 See generally Wholesale Competition in Regions with Organized Elec. Mkts., 
Docket Nos. RM19-15-000 and AD16-16-000 - 100 -

LMP markets, regardless of the reason for the price volatility, and regardless of whether 

the volatility causes LMPs to be lower or higher, nevertheless accurately represents the 

avoided cost of the purchasing electric utilities in those markets in those hours, as 

explained elsewhere in this final rule. 

164. Finally, we remain convinced that Congress recognized that RTO/ISO LMP pricing 

provides sufficient encouragement for QFs through the enactment of PURPA section 

210(m) with its directive that, essentially, the mandatory purchase obligation can be lifted 

upon QFs having non-discriminatory access to RTO/ISO markets. As noted earlier, 

however, our decision to grant states the flexibility to rely on a rebuttable presumption 

that RTO/ISO LMP pricing is an appropriate measure of avoided energy costs (and thus 

set as-available energy rates in reliance on LMPs) reflects our view that, in RTO/ISO 

markets, as a general matter LMP indeed accurately represents the purchasing electric 

utility’s avoided energy costs.

165. We also disagree with ELCON’s257 argument that LMP should not be used to

measure avoided costs because that would allow states to ignore long-standing factors 

established by the Commission that should be used to determine avoided costs. The 

factors referenced by ELCON are relevant to the traditional administrative determination 

of avoided cost, and our revisions to the regulations preserve these factors for that purpose

Order No. 719, 125 FERC ¶ 61,071 (2008), order on reh’g, Order No. 719-A, 128 FERC 

¶ 61,059, order on reh’g, Order No. 719-B, 129 FERC ¶ 61,252 (2009).

257 ELCON Comments at 23-24.
Docket Nos. RM19-15-000 and AD16-16-000 - 101 -

and for avoided capacity costs. If a state chooses instead to rely on LMP to set avoided 

energy cost rates, then it will necessarily not be using those administrative means of 

determining avoided costs, and these factors thus will not be relevant. 

166. We are not persuaded by the arguments of various commenters that LMP cannot be 

used for avoided cost rates because it ignores the unique municipal infrastructure role and 

the multiple benefits of the community of biogas facilities,

258 including the value of 

renewable baseload energy, greenhouse gas mitigation, landfill diversion, reliable and 

resilient power and other benefits of small baseload QFs.259 PURPA frames the 

determination of QF rates in terms of avoided cost and does not authorize the Commission 

in determining QF rates, particularly as-available energy rates, to consider non-energyrelated factors such as a generator’s unique municipal infrastructure role, greenhouse gas 

mitigation, and landfill diversion. 

167. We also are not persuaded by the argument of CA Cogeneration that LMP may not 

represent a truly competitive price for electricity in California since the majority of 

California supply is through bilateral contracts, not through competitive bidding in the 

market, and that other factors also distort LMP such as roof top solar. CA Cogeneration,

in essence, objects to the state of California’s decision to award preferred resource status 

to some resources, such as solar and wind, and not others, such as cogeneration. These are 

procurement decisions made at the state level in connection with resource planning and 

258 Biogas Comments at 2.

259 Covanta Comments at 8.
Docket Nos. RM19-15-000 and AD16-16-000 - 102 -

retail ratemaking. Even if those decisions impact the resulting LMPs, as CA Cogeneration 

claims, that impact would not invalidate the arguments made above for why LMP is 

presumptively an appropriate measure of as-available energy avoided costs in RTO/ISO 

markets. The aggrieved entity would be able to challenge the state’s decision to rely on 

LMP in the appropriate forum, which could include any one or more of the following: (1) 

initiating or participating in proceedings before the relevant state commission or 

governing body; (2) filing for judicial review of any state regulatory proceeding in state 

court (under PURPA section 210(g)); or, alternatively (3) filing a petition for enforcement 

against the state at the Commission and, if the Commission declines to act, later filing a 

petition against the state in U.S. district court (under PURPA section 210(h)(2)(B)).

260

168. We reject the argument made by New England Small Hydro that the Commission 

has not supported its view that LMP is an accurate measure of avoided costs since LMP

ignores the costs that the utility pays to procure power, including through competitive 

solicitations, other power contracts, planned retirements and other factors that are 

considered in a utility’s long-term plans; and ignores the fact that LMP and the default

service rates that exist in ISO-NE-based states are quite different.261 The costs that a 

purchasing utility pays to procure power, including through competitive solicitations, 

other power contracts, planned retirements and other factors that are considered in a 

260 See Policy Statement Regarding the Commission's Enforcement Role Under 

Section 210 of the Public Utility Regulatory Policies Act of 1978, 23 FERC ¶ 61,304.

261 New England Small Hydro Comments at 8-10.
Docket Nos. RM19-15-000 and AD16-16-000 - 103 -

utility’s long-term plans may be relevant to the utility’s purchase of capacity using longterm contracts, but not to the determination of the proper as-available energy avoided cost

rate to be paid to QFs, which rates will necessarily vary as system conditions vary over 

time, as reflected by variances in LMP over time. The fact that LMP and the default 

service rates that exist in ISO-NE-based states may diverge is to be expected because the 

latter, unlike the as-available energy rates charged by QFs in RTO/ISO markets that LMP 

is being used to price, normally include transmission and distribution costs (and possibly 

firm supplier capacity costs) necessary to ensure that firm supply is continually available 

to residential customers.262 While utilities or state regulatory authorities continue to have 

the authority to establish and maintain long-term avoided energy forecasts upon which QF 

PURPA power purchase rates may be based, and to recognize the actual future energy 

costs incorporated in new power contracts that are being signed by New England utilities, 

262 Compare ISO-NE, Transmission, Markets, and Services Tariff, LMPs and RealTime Reserve Clearing Prices Calculation, § III.2.5 (describing how nodal real-time prices 

are calculated in ISO-NE at each node using energy offers and bids, transmission 

constraints, and other factors) with National Grid, Investigation as to the Propriety of 

Proposed Tariff Changes, Docket No. DPU 18-150, Exh. NG-HSG-1, Gorman Test. 3:18-

4:6 (Nov. 15, 2018), 

https://fileservice.eea.comacloud.net/FileService.Api/file/FileRoom/10043215 (“The 

Company’s filing is based on its investments and costs incurred to provide distribution 

service to its customers. An [Allocated Cost of Service Study] directly assigns or allocates 

each element of the revenue requirement, including plant and other investments, operating 

expenses, depreciation and taxes, among the rate classes, in order to determine the costs of 

providing service to each rate class. Each element of the total revenue requirement is 

analyzed and assigned to or allocated among the rate classes, so the utility can establish 

rates that, subject to assumptions such as kilowatt-hour (‘kWh’) delivery volumes and the 

number of customers, provide it with a fair opportunity to recover its costs and to earn an 

appropriate return.”).
Docket Nos. RM19-15-000 and AD16-16-000 - 104 -

elsewhere in this final rule the Commission explains why the use of variable prices can be 

appropriate for long-term energy contracts.

169. We are not persuaded by the argument of Southeast Public Interest Organizations

that the NOPR does not establish a framework for just and reasonable and 

nondiscriminatory rates because the proposed avoided cost methodology does not take 

into account any long-term or seasonal purchases made from third parties or affiliates, 

adjustments for transmission and distribution losses, capacity deferrals, avoided 

environmental compliance costs, or dispatchability of the QF.263 LMP pricing, in fact, 

does reflect transmission and distribution losses. The other factors that the Southeast 

Public Interest Organizations mention here, such as environmental compliance costs, 

dispatchability, long-term or seasonal purchases and capacity deferrals, are factors that are 

more applicable to the pricing of capacity and long-term contracts, not the pricing of asavailable energy, which is what the Commission’s NOPR proposal as adopted in this final 

rule addresses. 

170. The Commission rejects the argument made by Biological Diversity264 that LMP 

pricing ignores the variability of conditions across the country. LMP prices by definition

vary as supply, demand, and system conditions change across the country. In any event, 

the Commission agrees that LMP pricing would not currently be applicable in regions like 

the Southeast that lack RTOs and ISOs and thus that do not use LMP.

263 Southeast Public Interest Organizations Comments at 22.

264 Biological Diversity Comments at 8-9.
Docket Nos. RM19-15-000 and AD16-16-000 - 105 -

171. We further reject the argument made by ENGIE that allowing states to set energy 

rates using LMPs combined with the ability to set capacity rates at zero if it is determined 

that a utility has no need for capacity has the potential to allow traditional utilities to 

corner the market on capacity, leaving smaller independent QFs to provide only energyonly service.

265 PURPA does not direct the Commission to guarantee that QF sales make 

up some specified share of utilities’ capacity needs nor does it require that each QF 

receive compensation for providing capacity. PURPA instead focuses on the purchasing 

electric utility’s avoided costs and provides that the Commission cannot require that prices 

charged by a QF exceed the purchasing electric utility’s avoided cost, if a purchasing 

electric utility has no need for additional capacity (and thus the purchasing utility’s 

avoided cost for capacity would be zero),

266 the only service that QFs (and other suppliers) 

would need to provide that utility is energy. However, a utility’s ability to “corner the 

market” on capacity depends not uniquely on the pricing of QF sales to the utility, but on a 

host of factors including the utility’s analysis of its need for capacity and, without a 

specific inquiry into the circumstances of each utility, it cannot be concluded that any 

utility’s decision will always be deficient or that it has been adversely and inappropriately 

affected by the Commission’s action here. 

265 ENGIE Comments at 4.

266 See, e.g., NOPR, 168 FERC ¶ 61,184 at P 33 n.58; see also City of Ketchikan, 

Alaska, 94 FERC ¶ 61,293 at 62,061 (2001) (“[A]voided cost rates need not include the 

cost for capacity in the event that the utility’s demand (or need) for capacity is zero. That 

is, when the demand for capacity is zero, the cost for capacity may also be zero.”).
Docket Nos. RM19-15-000 and AD16-16-000 - 106 -

172. Several commenters maintain that reliance on LMP will make it difficult for QFs to 

obtain financing.267 This argument is addressed below in section IV.B.7 of this final rule.

ii. Requests for Modification or Clarification of the 

NOPR

173. We will not provide the clarifications requested by New England Small Hydro that 

the Commission require the use of the day-ahead LMP for QF rates set at LMP, or 

Southeast Public Interest Organizations’ request to require the use of real-time LMP rather 

than average LMP. States that choose to use LMP will determine the LMP most 

representative of the avoided cost of the relevant purchasing utility.

174. While the Kentucky Commission requests that the Commission allow the use of the 

LMP at a delivery (load) node rather than a receipt (generator or QF) node, we find that 

this decision should be made by the state as it determines which particular LMP best 

reflects the avoided cost of the purchasing electric utility. 

175. We grant APPA’s request for clarification that, while the NOPR provides greater 

clarity as to states’ entitlement to rely on competitively-set prices as a measure of avoided 

cost rates, nothing in the final rule is intended to call into question any particular state’s

existing implementation of PURPA’s avoided cost requirements, such as their existing use 

of LMP.268 While in the past a state may have been able to conclude that LMP was an 

267 Biogas Comments at 2; BluEarth Renewables Comments at 2; Biological 

Diversity at 8; Covanta Comments at 9; Distributed Sun Comments at 1-2; New England 

Small Hydro Comments at 10; NIPPC, CREA, REC, and OSEIA Comments at 53.

268 APPA Comments at 9.
Docket Nos. RM19-15-000 and AD16-16-000 - 107 -

appropriate measure of the avoided cost for energy, a state can now also rely on a 

rebuttable presumption that LMP is an appropriate measure of the as-available avoided 

cost for energy to be used in determining a QF’s as-available avoided cost energy rate. 

176. We provide the following clarification in response to the Solar Energy Industries’

request that the Commission make clear that payments based on LMP do not relieve the 

purchasing utility of the requirement to compensate the QF for any values in addition to 

electricity (e.g., RECs, etc.), and that the state’s flexibility to allow utilities to set QF 

payment rates for as-available energy at the applicable LMP does not in any way limit 

QFs’ rights to establish a LEO or contract for a longer-term sale at fixed, full avoided 

costs.269 In Windham Solar LLC,

270 the Commission summarized its precedent concerning 

RECs. The Commission stated that the states have the authority to determine who owns 

RECs in the initial instance and how they are transferred, and that the automatic transfer 

of RECs within a sale of power at wholesale must find its authority in state law, not 

PURPA. But the Commission also held that a state may not assign ownership of RECs to 

utilities based on a logic that the avoided cost rates in PURPA contracts already 

compensate QFs for RECs in addition to compensating QFs for energy and capacity, 

because under PURPA the avoided cost rates are, in fact, compensation just for energy 

and capacity.271 We see no reason to disturb that precedent in this final rule. With regard 

269 Solar Energy Industry Comments at 27-28.

270 156 FERC ¶ 61,042 (2016).

271 Id. P 4.
Docket Nos. RM19-15-000 and AD16-16-000 - 108 -

to the right of QFs to establish a LEO, that right is neither limited nor expanded by a 

state’s choice of LMP as the measure of avoided costs for energy.

iii. Western EIM

177. We hereby find that the Western EIM prices, like other LMP prices, may 

presumptively be used as a measure of as-available energy avoided costs for utilities able 

to participate in the Western EIM market. As Xcel points out, “prices in the EIM are 

calculated using the same methodology as LMPs” since, “in both cases, units are 

dispatched on a least-cost basis that respects applicable transmission constraints (i.e., 

congestion),” and “[t]he formula for price calculation involves determination of the 

system marginal energy cost, which is the cost of providing the next increment of energy 

to the system, minus congestion costs, minus losses, and, in some cases, minus the cost of 

carbon.”272 As with LMP, these Western EIM price components presumptively reflect the 

avoided cost of as-available energy incurred by purchasing electric utilities that are able to 

participate in the Western EIM region.

178. We reject arguments that Western EIM prices should not be used to establish asavailable avoided cost energy rates for sales by QFs. With respect to the unit commitment 

and dispatch scheduling cost parameters ELCON refers to, it is true that the Western EIM 

is a real-time imbalance market built on a decentralized unit commitment that may not 

result in exactly the same real-time dispatch and LMP as would result from an RTO 

market with centralized day-ahead unit commitment and co-optimized energy and 

272 Xcel Comments at 7-8.
Docket Nos. RM19-15-000 and AD16-16-000 - 109 -

reserves. Nonetheless, Western EIM prices represent quite precisely the avoided cost of 

as-available energy for utilities operating in that market structure since those prices show 

the cost of obtaining an additional unit of energy at any particular place and time. With 

regard to the argument of Union of Concerned Scientists concerning the cost recovery 

mechanisms available to utility-owned and -affiliated generation,

273 as discussed above

with respect to the rebuttable presumption that LMP may be used for avoided cost rate 

determination, we do not find these unproven allegations of use of retail cost recovery 

mechanisms to subsidize wholesale RTO/ISO market participation at a loss sufficient to

make a blanket finding prohibiting the use of Western EIM prices to set as-available 

avoided cost energy rates for sales by QFs. 

179. With regard to the argument concerning the ability to participate in the Western 

EIM raised by Solar Energy Industries,

274 for PURPA rate purposes, it is not relevant 

whether QFs are able to participate in the Western EIM. The rates at issue here are 

intended, per the statute, to reflect the costs of alternative electric energy that the 

purchasing utility is avoiding. In this context, all that matters is whether the Western 

EIM’s prices accurately reflect a purchasing electric utility’s avoided costs for energy. 

Thus, as long as the purchasing electric utility is able to participate in the Western EIM, a 

rebuttable presumption should apply that Western EIM prices reflect the purchasing 

electric utility’s avoided costs for energy.

273 Union of Concerned Scientists Comments at 9.

274 Solar Energy Industry Comments at 27.
Docket Nos. RM19-15-000 and AD16-16-000 - 110 -

4. Use of Market Hub Prices as a Permissible Rate for Certain AsAvailable QF Energy Sales

a. NOPR Proposal 

180. In the NOPR, the Commission recognized that competitive bilateral energy markets 

have arisen outside of the RTO/ISO energy markets. Particularly in the Western United 

States, price hubs such as the Mid-Columbia (Mid-C) and Palo Verde hubs are liquid 

markets with prices the Commission has recognized as representing competitive market 

prices at those hubs.275 For the same reasons that LMPs could represent an appropriate 

avoided cost energy rate for QFs selling to electric utilities located in RTO/ISO markets, 

the Commission proposed to find that liquid market hubs can represent appropriate rates 

for QFs selling to electric utilities located outside of RTO/ISO markets. Like LMP, liquid 

market hubs would rely on competition to derive an avoided cost. From a price 

determination perspective, liquid market hub prices differ from LMP mainly in that they 

measure price at only one or a few points, whereas RTOs/ISOs derive unique LMPs for all 

receipt and delivery points on a specific area of the system.276

275 NOPR, 168 FERC ¶ 61,184 at P 52 (citing Price Discovery in Nat. Gas and 

Elec. Mkts., 109 FERC ¶ 61,184, at P 66 (2004) (approving the use of published prices at 

market hubs with sufficient liquidity to set prices charged in tariffs); El Paso Elec. Co., 

148 FERC ¶ 61,051, at P 7 (2014) (approving the use of the Palo Verde price to set 

imbalance charges); Idaho Power Co., 121 FERC ¶ 61,181 at P 27 (2007) (approving use 

of Mid-Columbia prices to set energy imbalance charge); PacifiCorp, 95 FERC ¶ 61,467, 

at 62,676 (2001) (approving setting energy imbalance rate at average of four market hub 

prices); Pinnacle West Energy Corp., 92 FERC ¶ 61,248, at 61,791 (2000) (accepting the 

use of the Palo Verde price to set prices for affiliate transactions because the Palo Verde 

Index is a recognized market hub with competitive prices)).

276 NOPR, 168 FERC ¶ 61,184 at P 53.
Docket Nos. RM19-15-000 and AD16-16-000 - 111 -

181. Consequently, the Commission proposed in the NOPR to revise the PURPA 

Regulations in 18 CFR 292.304 to add a subsection (b)(7) which, in combination with new 

subsection (e)(1), would permit a state to set the as-available energy rate paid to a QF by 

electric utilities located outside of RTO/ISO markets at energy rates established at liquid 

market hubs. The Commission proposed to define Market Hub Prices as prices 

determined at a liquid market hub to which the purchasing electric utility has reasonable 

access. States electing to set QF energy rates using a Market Hub Price also would 

identify the particular market hub used to set the price. Such determination would require 

the state to find that the prices at such hub are competitive prices that reflect the costs an 

electric utility would avoid but for the purchase from the QF.277 

b. Comments

i. Comments in Support

182. Arizona Public Service and El Paso Electric state that the Palo Verde/Hassayampa 

hub represents a regional liquid market hub that could be used to set as-available energy 

avoided costs.278 Portland General likewise asserts that the Mid-C price hub should be 

approved as appropriate for use in establishing as-available energy avoided costs.279 

183. Xcel provides two additional factors to support the liquid market hub proposal. 

First, Xcel cites to the 2018 State of the Market report issued by the Commission’s Office 

277 Id. P 56.

278 Arizona Public Service Comments at 6-8; El Paso Electric Comments at 2-3.

279 Portland General Comments at 6-7.
Docket Nos. RM19-15-000 and AD16-16-000 - 112 -

of Enforcement’s Division of Energy Market Oversight, which states that trading hub 

prices generally align with energy prices associated with competitive, market-based sales. 

Second, Xcel cites to wholesale power sales contracts providing for the purchase of excess 

energy based on a combination of day-ahead prices at Palo Verde and at Four Corners, 

which Xcel asserts demonstrates that prices at Palo Verde and Four Corners are 

reasonably representative of the value of energy.280

ii. Comments in Opposition

184. Several commenters argue that liquid market hubs are short-term spot markets and 

do not represent long-term energy rates or the other costs associated with that energy 

including, but not limited to, congestion, transmission, and capacity costs.281 Other 

commenters express concern with setting QF prices at short-term liquid hub prices while 

allowing utilities to rate base and recover their long-term investments.282

185. Public Interest Organizations assert that the liquid market hub proposal is 

discriminatory because non-QF generators are not limited to the liquid market hub price 

and utilities can, and regularly do, pay effective prices for energy that exceed the price 

determined by regional trading.283 Union of Concerned Scientists similarly asserts that 

280 Xcel Comments at 8.

281 IdaHydro Comments at 11; Southeast Public Interest Organizations Comments 

at 19.

282 IdaHydro Comments at 11; Industrial Energy Consumers Comments at 12-13.

283 Public Interest Organizations Comments at 64.
Docket Nos. RM19-15-000 and AD16-16-000 - 113 -

liquid market hub prices are distorted by the participation of integrated utilities that submit 

bids below their total costs.284

186. Industrial Energy Consumers oppose the liquid market hub pricing proposal 

because such markets are not sufficiently competitive, nondiscriminatory, and transparent 

to be used as the basis for calculating a utility’s avoided cost payment.285 Industrial 

Energy Consumers urge the Commission not to assume that non-competitive markets are, 

in fact, competitive.286 Southeast Public Interest Organizations state that no southeast 

state could credibly identify a particular market hub that is reasonably accessible and has 

competitive prices that actually relate to the costs an electric utility would avoid but for 

the purchase from the QF.287 Southeast Public Interest Organizations also assert that the 

liquid market hub proposal does not require states to determine whether liquid market hub 

prices represent a utility’s avoided costs, and therefore the proposal would allow liquid 

market hubs to set avoided energy prices even when they do not represent avoided energy 

costs.288

284 Union of Concerned Scientists Comments at 8.

285 Industrial Energy Consumers Comments at 12.

286 Id.

287 Southeast Public Interest Organizations Comments at 18.

288 Id. at 19.
Docket Nos. RM19-15-000 and AD16-16-000 - 114 -

187. ELCON asserts that a liquid regional hub does not necessarily imply liquidity at a 

more granular level.289 According to ELCON, the basis spread resulting from 

transmission congestion outside of RTO/ISOs is often opaque in real time and poorly 

documented in hindsight, and this is a clear indication that discriminatory treatment and 

barriers to the bulk transmission system persist under current conditions outside of 

RTO/ISOs.290 ELCON states that for these and other reasons, bilateral markets alone are 

insufficient to serve as complete avoided cost measures.291

188. Allco states that prices at liquid market hubs would suffer from shortcomings with 

respect to small QFs connected to the distribution system, because purchases from such 

QFs also allow the purchasing utility to avoid transmission costs, including line losses.292

iii. Commission Determination

189. We adopt the proposal in the NOPR to give the states flexibility to set as-available 

avoided cost energy rates using prices from a liquid market hub to which the purchasing 

electric utility has reasonable access. For the reasons explained in the NOPR, we find that 

liquid market hubs can represent appropriate as-available avoided cost energy rates for 

QFs selling to electric utilities located outside of RTO/ISO markets. However, as the 

Commission also found in the NOPR, before relying on prices from liquid market hubs, a 

289 ELCON Comments at 25.

290 Id.

291 Id.

292 Allco Comments at 7-8.
Docket Nos. RM19-15-000 and AD16-16-000 - 115 -

state must find that the liquid market hub price in question represents the purchasing 

utility’s avoided cost for as-available energy.

293

190. Examples of factors a state reasonably could consider in making this determination 

(in addition to the core finding that the liquid market hub represents the purchasing 

utility’s avoided cost for as-available energy) are: (1) whether the hub is sufficiently 

liquid that prices at the hub represent a competitive price;294 (2) whether the prices 

developed at the hub are sufficiently transparent; (3) whether the electric utility has the 

ability to deliver power from such hub to its load, even if its load is not directly connected 

to the hub; and (4) whether the hub represents an appropriate market to derive an energy 

price for the electric utility’s purchases from the relevant QFs given the electric utility’s 

physical proximity to the hub. These factors are not intended to be exhaustive, and states 

reasonably could consider other factors in identifying a relevant liquid market hub for 

setting as-available QF energy rates. 

191. In order for prices at market hubs to represent a purchasing electric utility’s 

avoided costs, the market hub price may need to be subject to adjustments to account for 

transmission costs the electric utility would incur before such prices could serve as a 

factor in determining appropriate QF rates.295 In addition, market prices in a region may 

293 See NOPR, 168 FERC ¶ 61,184 at PP 53, 56.

294 In considering whether a hub is sufficiently liquid, states could, for example, 

consider such factors as those identified by the Commission in Price Discovery in Nat.

Gas and Elec. Mkts., 109 FERC ¶ 61,184, at P 66.

295 Other adjustments also may be necessary in other situations in order for the 
Docket Nos. RM19-15-000 and AD16-16-000 - 116 -

be determined based on a formula that includes adjustments to the market hub price or that 

incorporates prices at more than one market hub located in the region, when such prices 

represent standard pricing practice in the region where the purchasing electric utility is 

located.296 Such adjustments may be necessary to ensure that the competitive market price 

reflects a purchasing utility’s actual avoided costs for as-available energy.

192. Arguments regarding the short-term nature of liquid market hubs and claims that 

use of such prices is discriminatory are addressed in Section IV.B.2 above. 

193. We will not address in this final rule arguments about whether particular market 

hubs should be found to represent avoided costs or, to the contrary, that particular market 

hubs may be too illiquid or insufficiently granular, or that prices at particular market hubs 

may not reflect avoided costs. We are not making any determination in this final rule that 

the prices at any specific market hub do or do not represent the avoided costs of any 

specific utility. Rather, we are allowing the states the flexibility to rely on prices at liquid 

market hubs to set as-available avoided cost energy rates for QF sales in regions outside 

RTO/ISO markets upon a state finding that it is appropriate to do so given the specific 

circumstances governing a particular market hub and the purchasing utility involved. The 

aggrieved entity would be able to challenge the state’s decision to use a liquid market hub 

price in the appropriate forum, which could include any one or more of the following: (1) 

initiating or participating in proceedings before the relevant state commission or 

adjusted hub price to reasonably reflect the purchasing electric utility’s avoided cost.

296 NOPR, 168 FERC ¶ 61,184 at P 58.
Docket Nos. RM19-15-000 and AD16-16-000 - 117 -

governing body; (2) filing for judicial review of any state regulatory proceeding in state 

court (under PURPA section 210(g)); or, alternatively (3) filing a petition for enforcement 

against the state at the Commission and, if the Commission declines to act, later filing a 

petition against the state in U.S. district court (under PURPA section 210(h)(2)(B))..

297

194. With respect to Southeast Public Interest Organizations’ assertion that the liquid 

market hub proposal in the NOPR does not require states to determine whether liquid 

market hub prices represent a utility’s avoided costs, the Commission intended to impose 

such a requirement as a prerequisite before a liquid market hub may be relied on as a 

measure of a purchasing utility’s avoided cost of as-available energy. However, we

acknowledge that the regulatory text in the NOPR was ambiguous in that regard. 

Therefore, the regulatory text of 18 CFR 292.304(b)(7)(i) in the final rule has been revised 

to make this more clear.

c. Proposed Modifications

i. Comments 

195. APPA requests that the Commission clarify that, in addition to liquid market hubs, 

as-available energy avoided costs could be determined based on prices of comparable 

competitive quality.298 APPA states that amending the proposed regulation in this fashion 

297 See Policy Statement Regarding the Commission's Enforcement Role Under 

Section 210 of the Public Utility Regulatory Policies Act of 1978, 23 FERC ¶ 61,304.

298 APPA Comments at 13.
Docket Nos. RM19-15-000 and AD16-16-000 - 118 -

would also enable utilities proximate to (or embedded within) RTO/ISO markets to 

reference prices in those markets as viable alternatives in establishing avoided costs.299

196. The California Commission requests that the Commission clarify that states 

previously were permitted to use liquid market hub prices under the current PURPA 

Regulations and that the proposed revisions simply codify and confirm the validity of this 

past practice.300 The California Commission and Massachusetts DPU further request that 

the proposed rules be modified to permit states to use competitive prices to set both 

energy and capacity costs, and to not be limited to using such mechanisms only for asavailable energy prices.301

197. EEI notes that some states may be located in regions with access to more than one 

market hub and those states should have the flexibility to use an average of market hub 

prices or develop a formula correlated to the appropriate market hubs to develop the 

electric utility’s avoided cost.302 EEI notes that this proposal is not new, but its inclusion 

in the Commission’s regulations will provide certainty to states.303

299 Id. at 13.

300 California Commission Comments at 24.

301 California Comments at 25; Massachusetts DPU Comments at 8-10.

302 EEI Comments at 26.

303 Id. at 27.
Docket Nos. RM19-15-000 and AD16-16-000 - 119 -

198. NIPPC, CREA, REC, and OSEIA assert that the liquid market hub proposal should 

not be adopted without making significant changes.304 For example, they argue, only 

long-term contract prices reported at market hubs should be used.305 Even with respect to 

market-hub prices for long-term contracts, they assert that the Commission should include 

safeguards to ensure that prices are set based on liquid trading with a sufficient number of 

competitors to assure effective price discovery, that prices are not subject to manipulation, 

and that reported price indices are accurate and not subject to mis-reporting or other forms 

of manipulation.306 Finally, they argue that the Commission should require avoided costs 

to include the costs of transmission to and from such hubs except in cases where the 

utility’s system directly interconnects with that hub.307 Resources for the Future makes 

similar arguments.

308

199. In contrast, NorthWestern asserts that liquid market hub prices should be adjusted 

downward by a transmission differential to reflect the cost of getting energy from the 

market to load.309 NorthWestern states that reliance on the market hub to establish 

304 NIPPC, CREA, REC, and OSEIA Comments at 60.

305 Id.

306 Id.

307 Id.

308 Resources for the Future Comments at 8.

309 NorthWestern Comments at 5. 
Docket Nos. RM19-15-000 and AD16-16-000 - 120 -

avoided costs only remains a valid option if the prices are less than what it would cost a 

utility to build a resource to supply its customers’ needs.310

ii. Commission Determination

200. We clarify that, in adopting a rule allowing states to use liquid market hubs to 

determine as-available avoided energy costs, we are not finding that the use of liquid 

market hubs for this purpose prior to the issuance of this final rule was not permitted. 

Depending on the specific circumstances, a state may appropriately have determined, prior 

to the final rule, that a liquid market hub price represented a purchasing utility’s asavailable avoided energy cost. After the effective date of this final rule, an aggrieved 

entity may seek review of a state’s determination to use liquid market hubs in the 

appropriate forum.311

201. We confirm that: (1) states located in regions with access to more than one market 

hub have the flexibility to use an appropriate average of market hub prices or to develop 

an appropriate formula that relies on data from relevant market hubs to develop an electric 

utility’s as-available avoided energy cost, so long as doing so yields a price that accurately

reflects the purchasing electric utility’s as-available avoided energy cost;

312 (2) states must 

determine that a liquid market hub is sufficiently liquid that its prices represent a 

310 Id.

311 See Policy Statement Regarding the Commission's Enforcement Role Under 

Section 210 of the Public Utility Regulatory Policies Act of 1978, 23 FERC ¶ 61,304.

312 NOPR, 168 FERC ¶ 61,184 at P 58.
Docket Nos. RM19-15-000 and AD16-16-000 - 121 -

competitive price;313 and (3) the market hub price may need to be subject to adjustments 

to account for transmission costs the electric utility would incur.

314

202. Finally, we find that the general ruling requested by APPA regarding the use of 

“prices of comparable competitive quality” to set as-available avoided cost rates is beyond 

the scope of this rulemaking in that here we were proposing only particular discrete 

changes to our regulations for setting as-available avoided cost energy rates charged by 

QFs.

5. Use of Formulas Based on Natural Gas Prices to Establish a 

Permissible Rate for Certain As-Available QF Energy Sales

a. NOPR Proposal

203. The Commission observed in the NOPR that, in regions where there are no 

RTOs/ISO or liquid market hubs, the price of electricity generated by efficient combinedcycle natural gas generation facilities would appear to represent a reasonable measure of a 

competitive energy price.315

204. The Commission therefore proposed to revise the PURPA Regulations in 18 

CFR 292.304 to add a subsection (b)(7) which, in combination with new subsection (e)(1), 

would permit a state to set the as-available energy rate paid to a QF by electric utilities 

located outside of RTO/ISO markets at Combined Cycle Prices, defined as a formula rate 

established by the state using published natural gas price indices and a proxy heat rate for 

313 Id. P 57.

314 Id. P 58.

315 Id. P 59. 
Docket Nos. RM19-15-000 and AD16-16-000 - 122 -

an efficient natural gas combined-cycle generating facility. The state would need to 

determine that the resulting Combined Cycle Price represents an appropriate 

approximation of the purchasing electric utility’s avoided costs. This determination would 

involve consideration of such factors as, for example: (1) whether the cost of energy from 

an efficient natural gas combined-cycle generating facility represents a reasonable 

approximation of a competitive price in the purchasing electric utility’s region; 

(2) whether natural gas priced in accordance with a particular proposed natural gas price 

index would be available in the relevant market; (3) whether there should be an 

adjustment to the natural gas price to appropriately reflect the cost of transporting natural 

gas to the relevant market; and (4) whether the proxy heat rate used in the formula should 

be updated regularly to reflect improvements in generation technology. The Commission 

described the above factors as not exhaustive and proposed providing states the flexibility 

to apply other factors that also might be appropriate for consideration.316

205. The Commission stated that natural gas price indices coupled with the heat rate of 

an efficient natural gas combined-cycle generating facility may be a reasonably accurate 

measure of avoided cost, at least in those markets where natural gas-fired resources are

commonly the marginal units. In such markets, the Commission stated that it would 

expect that new supplies of energy would need to be offered at a price equal to or less than 

the incremental cost of using these efficient gas units in order to displace them

economically. Thus, the Commission found preliminarily that using natural gas price 

316 Id.
Docket Nos. RM19-15-000 and AD16-16-000 - 123 -

indices and the heat rate of an efficient combined-cycle natural gas generating facility to 

establish an avoided cost energy rate relies on competitive market forces, in this case 

competitive forces in natural gas markets for the fuel used by natural gas combined-cycle 

generating facilities that the purchasing electric utility, but for the purchase from the QF,

would generate itself or purchase from another source.317

b. Comments

206. Several entities oppose the NOPR’s Combined Cycle Prices proposal.318 Allco 

asserts that this is exactly the type of administrative avoided cost determination about 

which NARUC and utilities have complained.319 Allco also argues that the only reason 

for including the Combined Cycle Prices proposal in the Commission’s regulations is to 

create a menu of prices from which a state commission or unregulated utility can choose 

the lowest price, which Allco claims would not encourage QF generation, and would be 

inconsistent with the rules of economic dispatch and the language of PURPA.320 Public 

Interest Organizations argue that the Combined Cycle Price proposal is discriminatory to 

QFs for all the same reasons that restricting QF rates to LMP is discriminatory (i.e.,

because utilities can, and allegedly do, pay effective prices for energy that exceed the 

317 Id. P 54.

318 Allco Comments at 8; BluEarth Comments at 1-2; ELCON Comments at 25-26; 

Industrial Energy Consumers Comments at 10-11; Public Interest Organizations 

Comments at 64; R Street Comments at 5; Southeast Public Interest Organizations 

Comments at 19-20.

319 Allco Comments at 8.

320 Id.
Docket Nos. RM19-15-000 and AD16-16-000 - 124 -

calculation from natural gas prices and assumed combined cycle heat rates).321 Southeast 

Public Interest Organizations argue that the Combined Cycle Prices proposal does not 

require states to include variable O&M costs in the proxy combined cycle plant or an 

adjustment for natural gas transportation, even though a utility-owned combined cycle gas 

plant would be allowed to recover both types of costs.

322

207. In contrast, R Street opposes the proposal because using natural gas combined 

cycle plants as the basis for QF rates in non-RTO/ISO regions could lead to the 

overpayment of a QF. R Street argues that regions without organized wholesale markets 

should instead price QF rates at the lowest cost resource based on an administratively 

determined avoidable cost.323

208. Similarly, ELCON argues that the proposal is complicated by the fact that natural 

gas units are not always marginal, especially in export-constrained subregions when 

renewables output is high. ELCON believes this proposal would be subject to extensive 

forecasting error, and therefore argues that careful assessment should precede its 

adoption.324

209. Other entities support the NOPR’s Combined Cycle Price proposal.325 The 

California Commission and EEI argue that states already had this flexibility under the 

321 Public Interest Organizations Comments at 64.

322 Southeast Public Interest Organizations Comments at 19-20.

323 R Street Comments at 5.

324 ELCON Comments at 26.

325 APPA Comments at 12-13; Arizona Public Service Comments at 6; California 
Docket Nos. RM19-15-000 and AD16-16-000 - 125 -

current regulations, and request that the Commission acknowledge this fact in a final 

rule.326 Similarly, other supporters of the Combined Cycle Price proposal argue that states 

should have the ability to develop as-available energy price formulas based on 

technologies other than combine cycle gas plants, if doing so would more accurately 

reflect the relevant purchasing utility’s avoided cost.327

210. El Paso Electric argues that: (1) the gas index price should be adjusted to account 

for the basis differential between the price at the natural gas hub and the price of natural 

gas in or near the utility’s service area; and (2) states should be allowed to update the 

formula periodically to reflect improved efficiencies in combined cycle generating 

facilities.328

c. Commission Determination

211. We adopt the NOPR proposal to revise 18 CFR 292.304 to add a subsection (b)(7) 

which, in combination with new subsection (e)(1), would permit a state to set the asavailable energy rate paid to a QF by electric utilities located outside of RTO/ISO markets 

at Combined Cycle Prices, defined as a formula rate established by the state using 

published natural gas price indices and a proxy heat rate for an efficient natural gas 

Commission Comments at 23; Chamber of Commerce Comments at 4; Duke Energy 

Comments at 9-10; EEI Comments at 27; El Paso Electric Comments at 3; Idaho 

Commission Comments at 3; Southern Comments at 9.

326 California Commission Comments at 23; EEI Comments at 27-28.

327 APPA Comments at 13; Duke Energy Comments at 10; EEI Comments at 27; 

Idaho Commission Comments at 3; Southern Comments at 9-11.

328 El Paso Electric Comments at 3-4.
Docket Nos. RM19-15-000 and AD16-16-000 - 126 -

combined-cycle generating facility. We also clarify that the formulas used to set asavailable energy rates based on natural gas prices should include recovery of variable 

O&M costs.

212. While some commenters oppose allowing states to use Combined Cycle Prices (or

other competitive prices) to set avoided energy cost rates, states already had the flexibility 

to determine avoided costs in this manner under the current regulations, as the California 

Commission and EEI observe.

329 If Combined Cycle Prices accurately represent a 

particular purchasing utility’s avoided energy costs, their use would be consistent with the 

Commission’s existing definition of avoided costs as “the incremental costs to an electric 

utility of electric energy or capacity or both which, but for the purchase from the 

qualifying facility or qualifying facilities, such utility would generate itself or purchase 

from another source.”330 Furthermore, as noted above in section IV.B.2, the use of 

competitive market prices, including Combined Cycle Prices, to set QF rates is explicitly 

subject to the requirement that such prices are equal to the purchasing utility’s avoided 

energy costs. Therefore, this proposal merely codifies more explicitly an option for 

determining avoided cost rates that already existed, i.e., where a state determines that a 

Combined Cycle Price is a measure of the purchasing electric utility’s avoided cost for asavailable energy. 

329 States could have used any of the competitive prices adopted in this final rule to 

set avoided cost energy rates as long as such prices met, to the extent practicable, the 

factors described 18 CFR 292.304(e).

330 See 18 CFR 292.101(b)(6).
Docket Nos. RM19-15-000 and AD16-16-000 - 127 -

213. The concerns of R Street, ELCON, and others that Combined Cycle Prices may not 

reflect a particular purchasing electric utility’s avoided cost are addressed by the 

requirement that the state would need to determine that the Combined Cycle Price indeed 

represents the purchasing electric utility’s avoided cost for as-available energy.

214. While some commenters requested that we expand the proposed regulation

explicitly to include technologies other than combined cycle natural gas generating 

facilities, we decline to do so for two reasons. First, as already mentioned, the current 

regulations are already flexible enough to accommodate states calculating avoided costs

based on the cost of the generating units or technology that accurately reflects the relevant 

purchasing utility’s avoided cost.

331 Second, this proposal focused specifically on 

combined cycle technology, as opposed to other generating technologies, because 

combined cycle generation makes up such a large portion of the nation’s generation 

fleet.332 This relative ubiquity, coupled with the fact that combined cycle natural gas 

generation facilities are often the marginal units in many regions, justifies an elevated 

profile in the PURPA Regulations for combined cycle technology compared to other 

technologies. This final rule does not foreclose other technologies from being used for 

331 See 18 CFR 292.101(b)(6).

332 According to EIA data, the nameplate capacity of natural gas-fired combined 

cycle generation technology, exceeds the nameplate capacity of generation from any other 

fuel source. See EIA, Electric Power Annual Table 4.7.A Net Summer Capacity of Utility 

Scale Units by Technology and by State, 2018 and 2017 (Megawatts), 

https://www.eia.gov/electricity/annual/html/epa_04_07_a.html, and 4.7.C Net Summer 

Capacity of Utility Scale Units Using Primarily Fossil Fuels and by State, 2018 and 2017 

(Megawatts), https://www.eia.gov/electricity/annual/html/epa_04_07_c.html.
Docket Nos. RM19-15-000 and AD16-16-000 - 128 -

avoided cost determination, upon an appropriate finding by the state that they accurately 

measure a purchasing electric utility’s avoided cost for as-available energy. 

215. Southeast Public Interest Organizations support their opposition to Combined 

Cycle Prices in part by claiming that the Commission did not specifically require states to 

include variable O&M in the formula. We agree that variable O&M expenses are an 

appropriate cost component of formula rates and should be included in any Combined 

Cycle Price formulae in order to accurately reflect the relevant purchasing electric utility’s 

avoided costs. 

216. With respect to the arguments of Southeast Public Interest Organizations regarding

natural gas transportation costs, the regulation we adopt in this final rule, 18 CFR 

292.304(b)(7)(ii)(C), specifically requires that states consider whether there should be an 

adjustment to the natural gas price to appropriately reflect the cost of transporting natural 

gas to the relevant market. As to El Paso Electric’s arguments regarding index price 

adjustments using basis differentials, and periodic formula updates to reflect efficiency 

improvements, we note that the revisions to the PURPA Regulations, which we adopt in 

this final rule, provide that states which choose to rely on Combined Cycle Prices must 

consider, when designing their formulae, whether and to what extent to include these 

costs, based on their assessment of how best to identify a relevant purchasing electric 

utility’s avoided cost for as-available energy.

333

333 See new 18 CFR 292.304(b)(7)(ii).
Docket Nos. RM19-15-000 and AD16-16-000 - 129 -

6. Permitting the Energy Rate Component of a Contract to be Fixed 

at the Time of the LEO Using Forecasted Values of the Estimated 

Stream of Market Revenues 

217. The NOPR noted that, frequently, price forecasts are available for LMPs in 

RTOs/ISOs, for liquid market hubs located outside of RTOs/ISOs, and for natural gas 

pricing hubs. Accordingly, the NOPR suggested that such forecasts could be used to 

allow QFs to request a fixed energy rate component calculated at the time a LEO is 

incurred. The Commission therefore proposed to add a new option in 18 CFR 

292.304(d)(1)(iii) permitting fixed energy rates to be based on forecasted estimates of the 

stream of revenue flows during the term of the contract.334 In other words, states could 

rely on estimates of forecasted energy prices at the time of delivery over the anticipated 

life of the contract – such estimates are commonly referred to as forward price curves – to 

develop a fixed energy rate component for that contract when such estimates reflect the 

purchasing electric utility’s avoided costs. 

218. The NOPR stated that the fixed energy rate component of the contract could be a 

single energy rate, based on the amortized present value of the forecast energy prices, or it 

could be a series of specified energy rates that are different in future years (or other 

periods).335 Under this proposal, the QF would be able to establish, at the time the LEO is 

334 NOPR, 168 FERC ¶ 61,184 at P 61.

335 Id. P 62 (noting that the PURPA Regulations already require that the fixed 

energy rate would need to account for the operating characteristics of the QF, including 

the QF’s ability to deliver energy during peak periods and the utility’s ability to dispatch 

energy from the QF (citing 18 CFR 292.304(e)(2)).
Docket Nos. RM19-15-000 and AD16-16-000 - 130 -

incurred, the applicable energy rate(s) for the entire term of a contract; however, the 

energy rate in the contract could be different from year-to-year (or some other period) and 

nevertheless comply with the current requirement in 18 CFR 292.304(d)(2)(ii) that the 

energy rate be fixed for the term of the contract.336

a. Comments

219. Two commenters oppose the NOPR proposal to add a new option in 18 CFR

292.304(d)(1)(iii) permitting fixed energy rates to be based on forecasted estimates of the 

stream of revenue flows during the life of the contract.337 Southeast Public Interest 

Organizations and Mr. Mattson state that the NOPR proposal is a departure from past 

precedent.338 Southeast Public Interest Organizations state that this proposal suffers the 

same deficiencies as the LMP and liquid market hub price proposals. Furthermore, 

according to Southeast Public Interest Organizations, the NOPR provides no analysis as to 

336 Id. (noting that this is permissible under the Commission’s existing PURPA 

Regulations (citing Windham Solar LLC, 157 FERC ¶ 61,134, at PP 5-6 (2016) (Windham 

Solar) (“[A]lthough state regulatory authorities cannot preclude a QF . . . from obtaining a 

legally enforceable obligation with a forecasted avoided cost rate, we remind the parties 

that the Commission’s regulations allow state regulatory authorities to consider a number 

of factors in establishing an avoided cost rate. These factors which include, among others, 

the availability of capacity, the QF’s dispatchability, the QF’s reliability, and the value of 

the QF’s energy and capacity, allow state regulatory authorities to establish lower avoided 

cost rates for purchases from intermittent QFs than for purchases from firm QFs.” (citing 

18 CFR 292.304(e)-(f)) (footnote omitted))).

337 Southeast Public Interest Organizations Comments at 25; Mr. Mattson 

Comments at 26. 

338 Southeast Public Interest Organizations Comments at 25; Mr. Mattson 

Comments at 26.
Docket Nos. RM19-15-000 and AD16-16-000 - 131 -

how or whether the forward price curves result in just and reasonable and nondiscriminatory rates as required by PURPA.339

220. Other commenters support the NOPR proposal to add a new option in 18 

CFR 292.304(d)(1)(iii) permitting fixed energy rates to be based on forecasted estimates 

of the stream of revenue flows during the term of the contract.340 The South Dakota 

Commission and Pennsylvania Commission state that they support the NOPR proposal on 

forecasted values of the estimated stream of revenues because it forecasts a steady stream 

of revenue and provides built-in flexibility.341 According to these commenters, the 

proposal also balances the QF’s need for a steady stream of revenue with the purchasing 

electric utility’s responsibility to have a prudent mix of supply contracts for its provider of 

last resort obligations.342 The Chamber of Commerce states that, while future rates are not 

guaranteed to materialize, the projected rates will more accurately reflect those realized 

than a single avoided cost rate set at the inception of a QF contract.343

339 Southeast Public Interest Organizations Comments at 25. 

340 Allco Comments at 8; APPA Comments at 14; Arizona Public Service 

Comments at 2-3; Chamber of Commerce Comments at 4-5; Connecticut Authority at 13; 

Distributed Sun Comments at 2; EEI Comments at 28-30; Idaho Commission Comments 

at 4; NorthWestern Comments at 6; NRECA Comments at 8; Pennsylvania Commission 

Comments at 8; Resources for the Future Comments at 8; South Dakota Commission 

Comments at 3.

341 Pennsylvania Commission Comments at 8-9; South Dakota Commission 

Comments at 3.

342 Pennsylvania Commission Comments at 8-9.

343 Chamber of Commerce Comments at 4-5.
Docket Nos. RM19-15-000 and AD16-16-000 - 132 -

221. Arizona Public Service states that it supports the proposal because it grants states 

additional flexibility, which helps protect utilities’ customers from over-paying for 

generation due to QFs need for sales guarantees and financing.344 NRECA agrees that 

states must have flexibility in determining forecasted market prices including appropriate 

discounting to ensure that utilities and consumers are not locked into contracts with fixed 

prices that are higher than prevailing market prices.345

222. NRECA requests that the Commission clarify proposed revisions to 18 

CFR 292.304(d)(1)(i), (ii), and (iii) to state that an electric utility is exempt from offering

a stream of market revenue as payment, even if there is a market hub price that could be 

relevant.346 The Connecticut Authority also suggests that the Commission modify 18 

CFR 292.304(d)(1)(ii) to specify that a state may set a series of energy rates. For this 

option, Connecticut Authority argues, the regulatory text should provide greater regulatory 

and commercial certainty to QF developers, avoiding disputes with distribution utilities 

and states.

347

223. Connecticut Authority supports revisions to 18 CFR 292.304(d)(2) because the rule 

would permit a state to limit a QF’s option to select a preferred energy rate 

344 Arizona Public Service Comments at 2-3. 

345 NRECA Comments at 8.

346 Id. at 9. 

347 Connecticut Authority Comments at 14.
Docket Nos. RM19-15-000 and AD16-16-000 - 133 -

methodology.348 Connecticut Authority also supports the proposed 18 CFR

202.304(d)(iii) that permits states to set a stated or fixed rate for energy that is calculated 

using the present value of the expected stream of revenue from as-available energy rates 

during the life of the contract or LEO.

224. EEI states that this proposal is not novel, and as an example notes that the 

Commission and a federal district court have already found that the Connecticut Authority 

could set avoided cost rates based on a forecast of future avoided costs.349 According to 

EEI, the Commission has not ruled either that any form of forecasting is mandated or that 

any is unacceptable.350

225. Allco states that the proposed new option in 18 CFR 292.304(d)(1)(iii) permitting 

fixed energy rates to be based on forecasted estimates of the stream of revenue flows 

during the life of the contract is consistent with PURPA section 210 and is already 

permitted. Allco also states that forecasts need to be non-discriminatory. According to 

Allco, utilities and states frequently use one forecast when dealing with QFs and another 

when obtaining approval for their favored projects; Allco asserts that this practice is

discriminatory.351

348 Id. at 13.

349 EEI Comments at 28 (citing Allco Renewable Energy Ltd. v. Mass. Elec. Co., 

208 F. Supp. 3d. 390, 395 (D. Mass. 2016); Windham Solar, 157 FERC ¶ 61,134 at P 5.

350 EEI Comments at 28-30.

351 Allco Comments at 8.
Docket Nos. RM19-15-000 and AD16-16-000 - 134 -

226. APPA states that the proposed change is a logical extension of the conclusion that 

market options are a legitimate alternative means of specifying avoided costs.352 

Distributed Sun states that it supports permitting states to set fixed energy rates with 

forward curves or through competitive solicitations.353 NorthWestern supports the 

proposal to permit fixed energy rates to be on a forward price curve developed from prices 

in either the organized markets or liquid market hubs.354 

b. Commission Determination

227. We adopt the proposal to add a new option in 18 CFR 292.304(d)(1)(iii) permitting 

fixed energy rates to be based on forecasted estimates of the stream of revenue flows 

during the term of the contract. The Commission has previously permitted the use of this

method to establish energy and capacity rates over the term of a contract or LEO.355 

Nevertheless, given the flexibilities we adopt in this final rule with respect to competitive 

market prices and variable energy rates, we clarify here that a state may use competitive 

market prices and/or variable energy rates in the context of a more fixed estimated 

avoided cost energy rate (together with a fixed avoided capacity rate) that is determined at 

the time an LEO or contract is incurred. The fixed energy rate component of the contract 

could be a single rate, based on the amortized present value of forecast energy prices, or it 

352 APPA Comments at 14.

353 Distributed Sun Comments at 2.

354 NorthWestern Comments at 6.

355 Windham Solar, 157 FERC ¶ 61,134 at P 4 (citing 18 CFR 292.304(d)(2)).
Docket Nos. RM19-15-000 and AD16-16-000 - 135 -

could be a series of specified rates that change from year-to-year (or other periods) in 

future years. We also will allow the state to establish the applicable energy rate(s) for the 

QF for the entire term or the rate may change from year-to-year (or some other period) of 

the contract at the time the LEO is incurred.

228. Southeast Public Interest Organizations and Mr. Mattson state that the NOPR 

proposal is a departure from past precedent. The very purpose of a proceeding like this is 

to consider changes to our regulations and our doing so is not impermissible. 

229. Southeast Public Interest Organizations also state that the proposal suffers the same 

deficiencies as the LMP and liquid market hub pricing proposals and that the NOPR 

provides no evidence as to how or if the forward price curves present just and reasonable 

and non-discriminatory rates as required by PURPA. Given that we find above that LMPs 

and liquid market hub prices may reflect avoided as-available energy costs and that 

estimates of such prices over the term of a contract can therefore reflect a purchasing 

electric utility’s avoided as-available costs over time, we do not believe Southeast Public 

Interest Organizations and Mr. Mattson’s concerns are justified. 

230. Although, as described below, we allow states to require variable avoided cost 

energy rates, allowing forward price curves determined at the time an LEO is incurred 

provides an additional option for states to calculate avoided energy costs in advance while 

also using transparent metrics for those calculations. Use of the forward price curve does 

not deter the adoption of just and reasonable and non-discriminatory rates required by 

PURPA, moreover, and insofar as we require that states determine that the estimated 

stream of revenues reflects the purchasing electric utility’s avoided energy, such pricing is 
Docket Nos. RM19-15-000 and AD16-16-000 - 136 -

fully consistent with the statute’s requirements. With regard to forecasts, we acknowledge

that the forecast used to set the avoided cost rate must meaningfully and reasonably reflect 

the utility’s avoided costs over time.

356

231. We decline to modify this proposal expressly either to permit or prohibit a state 

from setting a series of estimated avoided energy costs over time. Each state will be 

required to determine whether a particular estimated stream of revenues represents a 

purchasing electric utility’s avoided costs over a specified term. Similarly, in order to 

provide states flexibility to use LMPs and other competitive market prices to establish asavailable avoided energy costs, we will not require a state to use this option to guarantee a 

stream of revenues. 

7. Providing for Variable Energy Rates in QF Contracts 

a. Background

232. As explained above, if a QF chooses to sell energy and/or capacity pursuant to a 

contract, the PURPA Regulations currently provide the QF the option of receiving the 

purchasing electric utility’s avoided cost calculated and fixed at the time the LEO is 

incurred.357 The Commission’s justification in Order No. 69 for allowing QFs to fix their 

rate at the time of the LEO for the entire term of a contract was that fixing the rate 

356 See 18 CFR 292.304(b)(5). Rates calculated at the time of a LEO (for example, 

a contract) do not violate the requirement that the rates not exceed avoided costs if they 

differ from avoided costs at the time of delivery. 

357 18 CFR 292.304(d)(2)(ii). 
Docket Nos. RM19-15-000 and AD16-16-000 - 137 -

provides certainty necessary for the QF to obtain financing.358 The Commission stated 

that its regulations pertaining to LEOs “are intended to reconcile the requirement that the 

rates for purchases equal the utilities’ avoided costs with the need for qualifying facilities 

to be able to enter contractual commitments based, by necessity, on estimates of future 

avoided costs.”359 Further, the Commission agreed with the “need for certainty with 

regard to return on investment in new technologies.”360 The Commission stated its belief

that any overestimations or underestimations “will balance out.”361 

233. The provision that QFs be permitted to fix their rates for the entire term of a 

contract or other LEO has proved to be one of the most controversial aspects of the 

Commission’s PURPA Regulations. Some commenters at the Technical Conference 

submitted data indicating that energy prices have declined in recent years, leaving the 

fixed energy portion of the QF rate, even when levelized, well above market prices that 

likely would represent the purchasing electric utility’s actual avoided energy costs at the

time of delivery.362 Based on this concern, some commenters recommended that the 

358 Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,880 (justifying the rule on 

the basis of “the need for certainty with regard to return on investment in new 

technologies”). 

359 Id.

360 Id.

361 Id.

362 See Alliant Energy Comments, Docket No. AD16-16-000, at 5 (Nov. 7, 2016) 

(“Current market-based wind prices in the Iowa region of MISO are approximately 25 

[percent] lower than the PURPA contract obligation prices [Interstate Power and Light 

Company] is forced to pay for the same wind power for long-term contracts entered into 

as of June 2016. As a result, PURPA-mandated wind power purchases associated with 
Docket Nos. RM19-15-000 and AD16-16-000 - 138 -

Commission allow states to “price generation [energy] from QFs at market prices, and to 

update those prices regularly so that the prices for [QFs] are not burdensome on customer 

rates” and that the Commission should limit avoided cost energy rates in a LEO to no 

higher than avoided cost rates at the time of delivery.363 QFs, in turn, argued that 

elimination of the option to fix QF rates for the term of a contract would threaten a QF’s 

ability to obtain financing.364

just one project could cost Alliant Energy’s Iowa customers an incremental $17.54 million 

above market wind prices over the next 10 years.”) (emphasis in original); EEI

Supplemental Comments, Docket No. AD16-16-000, attach. A at 3-4 (June 25, 2018)

(EEI Supplemental Comments) (“On August 1, 2014, a 10-year fixed price contract at the 

Mid-Columbia wholesale power market trading hub was priced at $45.87/MWh. On June 

30, 2016, the same contract was priced as $30.22/MWh, a decline of 34 [percent] in less 

than two years. However, over the next 10 years, PacifiCorp has a legal obligation to 

purchase 51.9 million MWhs under its PURPA contract obligations at an average price of 

$59.87/MWh. The average forward price curve for the Mid-Columbia trading hub during 

the same period is $30.22/MWh, or 50 [percent] below the average PURPA contract price 

that PacifiCorp will pay. The additional price required under long-term fixed contracts 

will cost PacifiCorp’s customers $1.5 billion above current forward market prices over the 

next 10 years.”); Comm’r Kristine Raper, Idaho Commission Comments, Docket No. 

AD16-16-000, at 3-4 (filed June 30, 2016) (“Idaho Power demonstrated that the average 

cost for PURPA power since 2001 has exceed the Mid-Columbia (Mid-C) Index Price and 

is projected to continue to exceed the Mid-C price through 2032. Likewise, PacifiCorp’s 

levelized avoided cost rates for 15-year contract terms in Wyoming shows a decrease of 

approximately 50 [percent] from 2011 through 2015 (from approximately $60 per 

megawatt-hour to less than $30 per megawatt-hour).”).

363 EEI Supplemental Comments, attach. A at 4; see also Southern Company

Comments, Docket No. AD16-16-000, at 7 (filed June 30, 2016) (“[T]he avoided energy 

cost payment to the QF should be based on actual avoided energy cost at the time the QF 

delivers energy.”).

364 See Technical Conference, Docket No. AD16-16-000, Tr. 26:22-25, 27:1-3 

(June 29, 2016) (filed July 8, 2016) (Technical Conference Tr.) (Solar Energy Industries) 

(“The Power Purchase Agreement is the single most important contract of the development 

and financing of an energy project that’s not owned by a utility. Without the long-term 

commitment to buy the output of that agreement at a fixed price, there is no predictable 
Docket Nos. RM19-15-000 and AD16-16-000 - 139 -

b. NOPR Proposal

234. In the NOPR, the Commission proposed to revise 18 CFR 292.304(d) to permit a 

state to limit a QF’s option to elect to fix at the outset of a LEO the energy rate for the 

entire length of its contract or LEO, and instead allow the state the flexibility to require 

QF energy rates to vary during the term of the contract. However, under the proposed 

revisions to 18 CFR 292.304(d), a QF would continue to be entitled to a contract with 

avoided capacity costs calculated and fixed at the time the contract or LEO is incurred. 

Only the energy rate in the contract or LEO could be required by a state to vary. Further, 

the NOPR did not propose to obligate states to require variable avoided cost energy 

rates—they would retain the ability to allow the QF’s energy rate be fixed at the time the 

LEO is incurred.365

235. The Commission preliminarily found compelling the record evidence that 

overestimations have not been adequately balanced by underestimations in past years. 

Further, it appeared to the Commission that this trend may persist into the future with the 

continuing general decline in the cost of both wind and solar generation.366 Consequently, 

stream of revenue. Without a predictable stream of revenues, there is no financing. 

Without any financing, there is no project.”).

365 NOPR, 168 FERC ¶ 61,184 at P 67.

366 Id. P 68 (citing EIA, Today in Energy, Average U.S. construction costs for solar

and wind continued to fall in 2016 (Aug. 8, 2018),

https://www.eia.gov/todayinenergy/detail.php?id=36813 (“Based on 2016 EIA data for 

newly constructed utility-scale electric generators (those with a capacity greater than one 

megawatt) in the United States, annual capacity-weighted average construction costs for 

solar photovoltaic systems and onshore wind turbines declined . . . .”)). 
Docket Nos. RM19-15-000 and AD16-16-000 - 140 -

the Commission found that it may be necessary to allow states to provide for a variable 

energy rate in order to reflect more accurately the purchasing electric utility’s avoided 

costs and therefore to satisfy the statutory requirement that QF rates not exceed the 

utility’s avoided cost and “be just and reasonable to the electric consumers of the electric 

utility and in the public interest.”367

236. The Commission acknowledged that the current PURPA Regulations allowing a 

QF to fix its rates for the life of a contract or LEO were based on the recognition that fixed 

rates are beneficial for obtaining financing for QF projects. The Commission also 

recognized that QF developers have continued to assert that they require fixed rates to 

finance new projects. However, the Commission stated that it did not view the proposed 

modification to the PURPA Regulations as materially affecting the ability of QFs to 

obtain financing for several reasons.368

237. First, the Commission expressed its understanding that fixed energy rates are not 

generally required in the electric industry in order for electric generation facilities to be 

financed. For example, RTO/ISO capacity markets provide only for fixed capacity 

payments, leaving capacity owners to sell their energy into the organized electric markets 

at LMPs that vary based on market conditions at the time the energy is delivered. The 

Commission stated that these fixed capacity and variable energy payments have been 

sufficient to permit the financing of significant amounts of new capacity in the RTOs and 

367 Id. P 68 (internal quotations omitted) (citing 16 U.S.C. 824a-3(b)(1)).

368 Id. P 69.
Docket Nos. RM19-15-000 and AD16-16-000 - 141 -

ISOs.369 Testimony presented at the Technical Conference similarly showed that non-QF 

independent power projects located outside of RTOs enter into contracts with fixed 

capacity and variable energy prices.370 Other comments at the Technical Conference 

suggested that a fixed capacity charge likewise would be adequate for financing a QF 

project.371

238. The Commission further noted that there are financial products available, such as 

contracts for differences, which allow generation owners to hedge their exposure to 

fluctuating energy prices.372 The Commission stated that financial products can provide 

additional comfort to lenders regarding the level of energy rate revenues that a QF can 

369 Id. P 70 (citing Monitoring Analytics, LLC., Third Quarter, 2018 State of the 

Market Report for PJM, January through September, at 249, Table 5-6 (Nov. 8, 2018), 

http://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2018/2018q3-

som-pjm.pdf (over 23,000 MW of new capacity constructed in PJM Interconnection, 

L.L.C. since 2007-2008; including over 16,000 MW of new capacity added in the last 

four years)).

370 Id. (citing Technical Conference Tr. at 167-69 (Southern Company) (“So if we 

enter into a bilateral contract with an independent power producer for combustion turbine 

or combined cycle capacity, we don’t fix the energy price. The capacity payment is a 

fixed payment. That’s their fixed [stream]. The energy price is typically indexed to the

price of natural gas.”); id. at 178 (American Forest & Paper Association) (“Now, you sign 

a long-term IPP contract. That contract [has] got a variable energy cost in it.”)).

371 Id. P 70 (citing Solar Energy Industries Comments, Docket No. AD16-16-000, 

at 3 (filed June 30, 2016) (“Developers need rates for such sales of energy and/or capacity

to be fixed.”) (emphasis added)).

372 Id. P 72 (citing Elec. Storage Participation in Mrkts. Operated by Reg’l

Transmission Org. and Independent Sys. Operators, Order No. 841, 162 FERC ¶ 61,127, 

at P 299 (2018) (noting that “market participants that purchase energy from the RTO/ISO 

markets . . . may enter into bilateral financial transactions to hedge the purchase of that 

energy”)).
Docket Nos. RM19-15-000 and AD16-16-000 - 142 -

expect from the energy it delivers, in addition to the fixed capacity payments the QF is 

entitled to receive under its contract.373

239. The Commission also explained that, although it may have been true at the time the 

Commission promulgated its PURPA Regulations in 1980 that QFs needed to fix their 

energy rate for the term of their contract in order to obtain financing of their facilities, 

there is evidence that this no longer is true. This evidence comes in the form of data, 

described below, showing that independent generators that have not qualified as QFs 

under PURPA (including renewable resources that could qualify as QFs but have not 

sought QF status) have been able to obtain financing for new facilities. The Commission 

stated that the fact that owners of such facilities, which do not have recourse to the 

avoided cost rate provisions of PURPA, have been able to obtain financing for new 

projects is relevant to the question of whether the existing PURPA avoided cost provisions 

– including the requirement to enter into contracts with fixed energy rates – are necessary 

for QFs to obtain financing. 374 

240. For example, EIA data showed that, since 2005, QFs have made up only 10% to 

20% of all renewable resource capacity in service in the United States, demonstrating that 

most renewable resources no longer need to rely on PURPA avoided cost rates to sell their 

output economically.375 EIA data also showed that net generation of energy by non-utility 

373 Id. P 72.

374 Id. P 73.

375 Id. P 74 (citing EIA, Today in Energy, North Carolina has More PURPAQualifying Solar Facilities than any other State, figure titled PURPA qualifying facilities 
Docket Nos. RM19-15-000 and AD16-16-000 - 143 -

owned renewable resources in the United States escalated from 51.7 terawatt hours (TWh)

in 2005 when EPAct 2005 was passed, to 340 TWh in 2018. The Commission further 

observed that, while much of this growth was in states located in RTOs/ISOs, there also 

was significant growth of non-utility renewable generation in other states. For example, 

net generation by non-utility renewable resources in the region defined by EIA as the 

Mountain State region376 increased from 3.6 TWh in 2005 to 19.5 TWh in 2012, and to 

42.5 TWh in 2018. Pacific Northwest (Oregon and Washington) net non-utility 

generation from renewable resources increased from 1.5 TWh in 2005, to 8.7 TWh in 

2012, and to 10.6 TWh in 2018.

377

241. The Commission found that EIA data on independently-owned natural gas-fired 

generation capacity told a similar story. Natural gas-fired capacity without the requisite 

cogeneration technology cannot qualify as qualifying small power production or 

cogeneration, and thus most of this capacity would not be within the scope of the PURPA 

avoided cost rate provisions. The Commission cited to EIA data showing that, in 2018, 

approximately 44% of all energy produced by natural gas-fired generation in the United 

States was generated by independently-owned capacity.378 The total amount of energy 

(1980-2015) percent of total renewable capacity (Aug. 23, 2016), 

https://eia.gov/todayinenergy/detail.php?id=27632). 

376 Arizona, Colorado, Idaho, Montana, Nevada, New Mexico, Utah, and 

Wyoming.

377 NOPR, 168 FERC ¶ 61,184 at P 74.

378 NOPR, 168 FERC ¶ 61,184 at P 75 (citing EIA, Electric Power Monthly with Data 

for December 2018, at tbl. 1.7.B,
Docket Nos. RM19-15-000 and AD16-16-000 - 144 -

produced in 2018 by independently-owned natural gas-fired generation was 651 TWh, an 

increase of 13.7% from 2017.379 Again, the percentage of independently-owned natural 

gas generation outside of RTOs/ISOs was lower than in RTOs/ISOs, but still was 

significant. In the Mountain State region, 21.4% of the energy produced by natural gasfired generation in 2018 was produced by independently-owned capacity, and in Oregon 

and Washington 45.4% of natural gas-fired energy was produced by independently-owned 

capacity.380 From this, the Commission concluded that independent owners of non-QF 

generation have been, and continue to be, able to obtain financing for their facilities.381

242. The Commission did not suggest that this evidence supports the conclusion that 

substantial non-QF capacity is being financed and constructed without any form of fixed 

revenue to support financing. Rather, the Commission concluded that the evidence 

demonstrated that the existing PURPA avoided cost rate provisions are not necessary for

some independent power generators to put in place contractual arrangements, including 

fixed revenue streams, that are sufficient to obtain financing. The Commission reasoned 

that QFs, which have the ability to take advantage of PURPA’s mandatory purchase 

requirements, should be better positioned than non-QFs to negotiate the necessary 

contractual arrangements for financing. Moreover, the Commission noted that QFs are 

https://www.eia.gov/electricity/monthly/current_month/epm.pdf.).

379 Id.

380 Id.

381 Id.
Docket Nos. RM19-15-000 and AD16-16-000 - 145 -

equally as well positioned as non-QF independent generators to take advantage of federal 

and state incentives designed to encourage the construction of renewable resources. 382

243. Further, the Commission pointed to evidence that the desire to limit the effect of 

fixed QF contract rates had directly led to PURPA implementation issues that affected QF 

financing in other respects, particularly with respect to the length of QF contracts.383 For 

example, a commissioner of the Idaho Commission testified at the Technical Conference 

that the Idaho Commission’s decision to limit QF contracts to a two-year term was based 

on the Idaho Commission’s concern that longer contract terms at fixed rates would lead to 

payments above avoided costs.384 Similarly, Southern Company testified that the fixed 

rate requirement is “resulting in . . . typically shorter contract term lengths.”385 Golden 

Spread Electric Cooperative recommended that, if the fixed rate requirement is not 

eliminated, the Commission permit shorter contract terms, “as short as one-year or three 

years at most.”386

382 Id. P 76.

383 Id. P 65 (citing Natural Resources Defense Council Comments, Docket 

No. AD16-16-000, at 4 (filed June 30, 2016)).

384 Id. P 65 (citing Technical Conference Tr. at 142-43 (Idaho Commission) (“No 

matter the starting point, allowing QFs to fix their avoided cost rates for long terms results 

in rates which will eventually exceed and overestimate avoided cost rates into the future. 

The longer the term, the greater the disparity. . . . [The Idaho Commission] recently 

reduced PURPA contract lengths to two years in order to correct the disparity. We didn’t 

reduce contract lengths to kill PURPA. We did it to allow periodic adjustment of avoided 

cost rates.”)).

385 Id. P 65 (citing Technical Conference Tr. at 202 (Southern Company)).

386 Id. P 65 (citing Golden Spread Electric Cooperative Comments, Docket 
Docket Nos. RM19-15-000 and AD16-16-000 - 146 -

244. Finally, the Commission addressed one particular standard form of QF contract rate 

currently employed by a number of utilities, which is a one-part rate, applicable to each 

MWh of energy delivered by the QF. This one-part rate is calculated to reflect both 

avoided capacity costs and avoided energy costs. Contracts employing such rates also 

typically impose a must purchase obligation on the purchasing utility. The Commission

stated that its proposed rule was not intended to prevent states from implementing such an 

approach to setting QF contract rates in the future. The Commission proposed that, to the 

extent a state determines to establish a one-part QF contract rate that recovers both 

avoided capacity and avoided energy costs, the rate must continue to be subject to the 

QF’s option to select a fixed rate for the term of the contract, as provided in 18 

CFR 304(d)(2)(ii). Any requirement to impose a variable energy QF contract rate would 

need to be accomplished through a multi-part rate that includes separate avoided capacity 

cost rates and avoided energy cost rates.387

c. General Comments on the NOPR Proposal 

i. Comments in Support of NOPR Proposal

245. Several commenters support the NOPR proposal to allow energy rates to vary in 

QF contracts and other LEOs, arguing it will reduce overpayments and protect 

customers.388 In that regard, Duke Energy asserts that the primary factor behind 

No. AD16-16-000, at 10 (filed June 30, 2016)).

387 Id. P 81.

388 Conservative Action Comments at 1; Consumer Energy Alliance Comments at 

2; EEI Comments at 30-31; Idaho Power Comments at 7-8; Idaho Commission Comments 
Docket Nos. RM19-15-000 and AD16-16-000 - 147 -

overpayment has been the requirement to offer fixed avoided cost energy rates during a 

period of rapidly declining energy prices.389 Several other commenters similarly cite to 

the general decline of energy prices coupled with the fact that QFs have been able to lock 

in rates over the life of a contract or other LEO as reasons for their support of the NOPR 

proposal.

390

246. Several commenters also support the NOPR’s variable rate proposal because it will 

allow states greater flexibility to determine avoided cost rates accurately and to meet 

PURPA’s consumer protection goals.391 LG&E/KU states that such flexibility is 

appropriate and necessary to meet the statutory requirement that ratepayers not pay a rate 

that exceeds the electric utility’s incremental cost of alternative energy.

392 NorthWestern 

argues that providing such flexibility will assist in guaranteeing that customers are held 

harmless by purchases of QF power.393

at 4; LG&E/KU Comments at 3; NextEra Comments at 5; see also Alaska Power 

Comments at 1; Arizona Public Service Comments at 3-4; Basin Comments at 6-8; 

Chamber of Commerce Comments at 4; Freedom Center Comments at 1-2; R Street 

Comments at 5; Tax Reform Comments at 1-2.

389 Duke Energy Comments at 5-7.

390 Consumer Energy Alliance Comments at 2; Idaho Power Comments at 7-8; 

Idaho Commission Comments at 4; LG&E/KU Comments at 3; Ohio Commission Energy 

Advocate Comments at 4.

391 Alliant Energy Comments at 9; Duke Energy Comments at 8-9; LG&E/KU 

Comments at 4; MA DPU Comments at 1, 7; NorthWestern Comments at 6-7.

392 LG&E/KU Comments at 4.

393 NorthWestern Comments at 6-7.
Docket Nos. RM19-15-000 and AD16-16-000 - 148 -

247. Supporters of the NOPR variable rate proposal also commented on specific aspects 

of the proposal. These comments are discussed in more detail in the following sections. 

ii. Comments in Opposition to NOPR Proposal

248. Several commenters oppose the NOPR variable energy rate proposal.

394 In 

addition to objections as to specific aspects of that proposal, which are discussed in the 

following sections, some commenters raise threshold issues regarding this proposal. 

249. NIPPC, CREA, REC, and OSEIA cite to the PURPA Conference Report as 

expressing Congress’s intent that QFs be entitled to long-term fixed energy rates. 

Specifically, they cite to the statement in the Conference Report that “the Commission and 

States should look to the reliability of that power to the utility and the cost savings to the 

utility which may result at some later date by reason of supply to the utility at that time of 

power from the cogenerator or small power producer.”395 According to NIPPC, CREA, 

REC, and OSEIA, this statement shows that “Congress also recognized that attempts to set 

394 Allco Comments at 9-11; AllEarth Comments at 2; Biogas Comments at 2; 

BluEarth Comments at 2; CARE Comments at 3-5; Biological Diversity Comments at 8; 

ELCON Comments at 18, 21-23; EPSA Comments at 6-13; Massachusetts AG Comments 

at 8-9; North Carolina DOJ Comments at 2-6; North Carolina Commission Staff 

Comments at 2-4; New England Hydro Comments at 8; NIPPC, CREA, REC, and OSEIA 

Comments at 29-48; North American-Central Comments at 4-6; Public Interest 

Organizations Comments at 6-7, 27-51; Resources for the Future Comments at 4-7; Solar 

Energy Industries Comments at 28-38; SC Solar Alliance Comments at 4-10; Southeast 

Public Interest Organizations Comments at 9-18; sPower Comments at 10-13; State 

Entities Comments at 2-3; Mr. Mattson Comments at 26-27; Two Dot Wind Comments at 

11-13; Western Resource Councils Comments at 2.

395 NIPPC, CREA, REC, and OSEIA Comments at 27 (quoting Conf. Rep. at 98-

99).
Docket Nos. RM19-15-000 and AD16-16-000 - 149 -

the rates based on the avoided costs at the time of delivery would likely be insufficient to 

encourage such facilities.”396

250. Harvard Electricity Law asserts that the Commission may not authorize state 

regulators to change rates in existing contracts.397 Harvard Electricity Law then asserts 

that the Commission: (1) attempts to portray its agenda as consistent with Congressional 

intent by providing a skewed summary of the legislative history; (2) presents an 

unsupported statement that its rules will “continue to encourage” QF development, which 

ignores the administrative record and fails to account for regulatory changes since 

PURPA’s enactment; (3) misreads its own rules in claiming that repeal is necessary to 

protect consumers; and (4) relies on a finding that fixed price energy contracts are not 

necessary to encourage QFs that is based on irrelevant data and questionable assumptions 

that are not grounded in reasoned decision making. 

251. Harvard Electricity Law also asserts that allowing long-term contracts to include 

variable rates is contrary to PURPA.398 In support of this assertion, Harvard Electricity 

Law cites to two decisions which it claims stand for the proposition that the Commission’s 

proposed rule would impose forbidden utility-type regulation on QFs.399 

396 Id.

397 Harvard Electricity Law Comments at 23 (citing API, 461 U.S. at 414).

398 Id. at 28.

399 Id. at 29 (citing Freehold Cogeneration Assoc. v. Bd. of Regulatory Comm’rs. of 

N.J., 44 F.3d 1178, 1193 (3d Cir. 1995) (Freehold Cogeneration); Smith Cogeneration 

Mgt. v. Corp. Comm’n., 863 P.2d 1227 (Okla. 1993) (Smith Cogeneration)).
Docket Nos. RM19-15-000 and AD16-16-000 - 150 -

252. NIPPC, CREA, REC, and OSEIA and Public Interest Organizations assert that it is 

unclear whether independent power producers that have obtained financing did so with 

short-term variable rate conditions.400 North American-Central argues that, if a variable 

rate will preclude a QF from receiving financing in the first place, it is irrelevant that a 

state might be more willing to offer a longer-term contract.401 

iii. Commission Determination

253. In this final rule, we adopt without modification the NOPR variable rate proposal. 

We find that setting QF energy avoided cost contract and other LEO rates at the level of 

the purchasing utility’s avoided energy costs at the time the energy is delivered is 

consistent with PURPA, which limits QF rates to the purchasing utility’s avoided costs. 

Indeed, a variable energy avoided cost approach is a more accurate way to ensure that 

payments to QFs equal, but do not exceed, avoided costs.402 It is inevitable that, in 

contrast, over the life of a QF contract or other LEO a fixed energy avoided cost rate, such 

as that used in past years, will deviate from actual avoided costs.

254. As described in more detail in the following sections, the record overwhelmingly 

supports our conclusions that long-term forecasts of avoided energy costs are inherently 

less accurate, and that states should be given the flexibility to rely on a more accurate 

variable avoided cost energy rate approach. Further, there are numerous instances where 

400 NIPPC, CREA, REC, and OSEIA Comments at 46.

401 North American-Central Comments at 5-6.

402 16 U.S.C. 824a-3(b)(1).
Docket Nos. RM19-15-000 and AD16-16-000 - 151 -

overestimates and underestimates have not balanced out.403 When that has occurred, 

consumers have borne the brunt of the overpayments, which subsidized QFs, in 

contravention of Congressional intent and the Commission’s expectations. 

403 See Duke Comments at 6 (Duke’s QF contracts cost $4.66 billion but its “actual 

current avoided costs” are $2.4 billion); Idaho Power Comments at 10-11 (“The cost of 

PURPA generation contained in Idaho Power’s base rates, on a dollars per MWh basis, is 

not just greater than Mid-C market prices, it is greater than all the net power supply cost 

components currently recovered in base rates. Idaho Power’s average cost of PURPA

generation included in base rates is $62.49/MWh. At $62.49/MWh, the average cost of 

PURPA purchases is greater than the average cost of FERC Account 501, Coal at 

$22.79/MWh; greater than FERC Account 547, Natural Gas at $33.57/MWh; greater than 

FERC Account 555, Non-PURPA Purchases at $50.64/MWh; and significantly greater 

than what is being sold back to the market as FERC Account 447, Surplus Sales at 

$22.41/MWh.”); Portland General Comments at 5 (“for a typical 3 MW Solar QF project 

that incurred a LEO in 2016 and reaches commercial operations three years later, [Portland 

General’s] customers would pay 67% more for the project’s energy than if the 2019 

avoided cost rate had been used. As a result of this lag, [Portland General’s] customers 

would pay an additional $1.6 million more for the energy from the QF facility over the 15-

year contract term.”); see also NOPR, 168 FERC 61,184 at P 64 n.101 (citing Alliant 

Energy, Comments, Docket No. AD16-16-000, at 5 (filed Nov. 7, 2016) (“Current marketbased wind prices in the Iowa region of MISO are approximately 25% lower than the 

PURPA contract obligation prices [Interstate Power and Light Company] is forced to pay 

for the same wind power for long-term contracts entered into as of June 2016. As a result, 

PURPA-mandated wind power purchases associated with just one project could cost 

Alliant Energy’s Iowa customers an incremental $17.54 million above market wind prices 

over the next 10 years.”) (emphasis in original); EEI Supplemental, Comments, attach. A at 

3-4 (“On August 1, 2014, a 10-year fixed price contract at the Mid-Columbia wholesale 

power market trading hub was priced at $45.87/MWh. On June 30, 2016, the same contract 

was priced as $30.22/MWh, a decline of 34% in less than two years. However, over the 

next 10 years, PacifiCorp has a legal obligation to purchase 51.9 million MWhs under its 

PURPA contract obligations at an average price of $59.87/MWh. The average forward 

price curve for the Mid-Columbia trading hub during the same period is $30.22/MWh, or 

50% below the average PURPA contract price that PacifiCorp will pay. The additional 

price required under long-term fixed contracts will cost PacifiCorp’s customers $1.5 billion 

above current forward market prices over the next 10 years.”); Comm’r Kristine Raper, 

Idaho Commission Comments, Docket No. AD16-16-000, at 3-4 (filed June 30, 2016) 

(“Idaho Power demonstrated that the average cost for PURPA power since 2001 has 

exceed the Mid-Columbia (Mid-C) Index Price and is projected to continue to exceed the 

Mid-C price through 2032. Likewise, PacifiCorp’s levelized avoided cost rates for 15-year 
Docket Nos. RM19-15-000 and AD16-16-000 - 152 -

255. Given that PURPA section 210(b) prohibits the Commission from requiring QF 

rates in excess of avoided costs,

404 this record evidence supports our decision to give the 

states the flexibility to require variable avoided cost energy rates in QF contracts and other 

LEOs to prevent QF rates from exceeding avoided costs. We discuss specific aspects of 

the variable energy rate provisions below, but at the outset address certain threshold issues 

raised in the comments.

256. We reiterate the points made in detail above in Section II. The variable energy 

avoided cost rate provision is not based on any determination that the Commission’s rules 

no longer should encourage QF development. The question of whether QFs should 

continue to be encouraged is a question for Congress. Rather, we are revising the PURPA 

Regulations by giving states the flexibility to require variable avoided cost energy rates in 

QF contracts and other LEOs in order to better comply with Congress’s clear instruction 

in PURPA that the Commission may not require QF rates in excess of a purchasing 

utility’s avoided costs.

257. By its very nature, the question of fixed versus variable energy rates is a question 

of how risk from increases in avoided energy costs over the life of a QF contract or other 

LEO should be allocated. Answering this question requires the Commission to allocate 

this risk either to (i) customers of electric utilities, or (ii) QFs and their investors and 

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).”).

404 This prohibition is described in Section IV.A.
Docket Nos. RM19-15-000 and AD16-16-000 - 153 -

lenders. But the Commission does not have unlimited discretion in how it resolves the 

question. Congress in PURPA section 210(b) provided guidance to the Commission in 

how it should perform that allocation – by mandating that the Commission cannot adopt a 

rule that provides for a rate that exceeds the incremental cost of alternative electric 

energy.405

258. Opponents of variable avoided cost energy rates urge the Commission to continue 

placing this risk on the customers of electric utilities, as it did in the past, by retaining the 

option for QFs to fix their avoided cost energy rates in their contracts or LEOs

notwithstanding record evidence, discussed elsewhere in this final rule, that fixed energy 

rates compared to actual avoided costs have not balanced out over time. But, after 

consideration of the record, the Commission has decided instead to allow states to reduce 

the risk to customers by giving states the flexibility to require variable avoided cost energy 

rates in QF contracts and LEOs. The Commission’s determination ensures that the 

PURPA Regulations continue to be consistent with the statutory avoided cost rate cap in 

PURPA section 210(b), coupled with the directive in the Conference Report that 

customers of utilities not be required to subsidize QFs.406

405 16 U.S.C. 824a-3(b); see also 16 U.S.C. 824a-3(d); 18 CFR 292.101(b)(6), 

292.304(b)(2).

406 Conf. Rep. at 98 (“The provisions of this section are not intended to require the 

rate payers of a utility to subsidize cogenerators or small power produc[er]s.”) (emphasis 

added). 
Docket Nos. RM19-15-000 and AD16-16-000 - 154 -

259. Third, there is no merit to the contention that the PURPA Conference Report 

expresses Congressional intent that QFs are entitled to long-term fixed energy rates. The 

statement in the Conference Report cited by NIPPC, CREA, REC, and OSEIA does not 

support this contention.407 The example provided in the PURPA Conference Report was 

of a utility owning a hydroelectric generating facility. Congress hypothesized that this 

utility might be able to avoid drawing down its reservoir as a result of a purchase from a 

QF, and thereby be able to generate electricity from the hydroelectric facility at a later 

date rather than running a more expensive fossil fuel unit at that later date. Congress 

stated that the avoided cost in its example should be based on the cost of the more 

expensive fossil unit whose operation was avoided at a later date rather than the avoided 

cost at the time the QF delivered its energy.

408 

407 See NIPPC, CREA, REC, and OSEIA Comments at 27 (quoting Conf. Rep. at

98-99).

408 Id. at 98-99 (“In interpreting the term ‘incremental cost of alternative energy,’

the conferees expect that the Commission and the states may look beyond the cost of 

alternative sources which are instantaneously available to the utility. Rather, the 

Commission and states should look to the reliability of that power to the utility and the 

cost savings to the utility which may result at some later date by reason of supply to the 

utility at that time of power from the cogenerator or small power producer; for example an 

electric utility which owns a source of hydroelectric power and which is offered the sale 

of electric energy from a cogenerator or small power producer might, if measured over the 

short term, have a low incremental cost of alternative power because of its access to 

hydropower; however, it may be the case that by purchasing from the cogenerator or small 

power producer and saving hydropower for later use, the utility can avoided the use of 

expensive electric energy generated by fossil fired units during later months of its seasonal 

generation cycle. Thus, viewed over the longer period of time, the incremental cost of 

alternative electric energy might be substantially higher than that measured by the 

instantaneously available hydropower.”).
Docket Nos. RM19-15-000 and AD16-16-000 - 155 -

260. While Congress recognized that the better measure of avoided cost in that scenario 

might be the cost of the alternative fossil fuel unit that would not be run at that later 

date,

409 nothing in the quoted section of the PURPA Conference Report suggests that 

Congress intended the Commission to require that all avoided cost energy rates be fixed at 

the outset for the life of a QF contract or other LEO. And nothing in the revision being 

implemented in this final rule would prohibit a state from calculating a QF’s avoided cost 

energy rate for a QF contract or LEO in the manner suggested in the PURPA Conference 

Report or, indeed, in the manner the Commission has long allowed, if a state determined 

that such an approach best reflects the purchasing electric utility’s avoided costs.

261. Fourth, the variable avoided cost energy rate provision adopted herein does not run 

afoul of the Freehold Cogeneration and Smith Cogeneration cases cited by Harvard 

Electricity Law.410 Those decisions, which overturned state avoided cost determinations 

allowing for changes in QF rates, were based on the provision in the original PURPA 

Regulations giving QFs the option to select contracts with long-term fixed avoided cost 

rates.411 Indeed, the Smith Cogeneration decision quotes at length from the explanation in 

409 Under the approach adopted in this final rule, with the flexibility granted to 

states to adopt – but not a mandate directing states to adopt – variable avoided cost energy 

rates for QF contracts and other LEOs, states can adopt a pricing approach that best fits 

their circumstances, including adopting the pricing approach described by the Conference 

Report to address the circumstances described by the Conference Report. 

410 Harvard Electricity Law Comments at 29 (citing Freehold Cogeneration, 

44 F.3d at 1193; Smith Cogeneration, 863 P.2d at 1227).

411 See Smith Cogeneration, 863 P.2d at 1241 (holding that allowing 

reconsideration of established avoided costs “makes it impossible to comply with PURPA 

and FERC regulations requiring established rate certainty for the duration of long term 
Docket Nos. RM19-15-000 and AD16-16-000 - 156 -

Order No. 69 of the Commission’s justification for its requiring in its regulations fixed 

avoided cost rates in QF contracts and LEOs.

412 Neither decision suggests that PURPA 

would prevent the Commission from revising its regulations to allow states the flexibility 

to require variable avoided cost energy rates, as the Commission is doing here.

262. Harvard Electricity Law also relies on Freehold Cogeneration and Smith 

Cogeneration to assert that the Commission is imposing “utility-type” regulation in 

violation of Congressional intent as expressed in the PURPA Conference Report.413 

However, those holdings do not address the changes the Commission is implementing 

here. By adopting a provision that allows states the option to require variable avoided cost 

energy rates, we are not mandating “utility-type” regulation. The PURPA Conference 

Report states that: “It is not the intention of the conferees that [QFs] become subject . . . to 

the type of examination that is traditionally given to electric utility rate applications to 

determine what is the just and reasonable rate that they should receive for their electric 

power.”414 Our action today is consistent with that statement; we are not subjecting QFs 

to the same type of examination that is traditionally given to electric utility rate 

applications (e.g., cost-of-service rate regulation).

contracts for qualifying facilities that have incurred an obligation to deliver power”) 

(emphasis added); Freehold Cogeneration, 44 F.3d at 1193 (relying on Smith 

Cogeneration analysis that “that PURPA and FERC regulations preempted the State 

Commission rule”) (emphasis added).

412 Smith Cogeneration, 863 P.2d at 1240.

413 Harvard Electricity Law Comments at 30.

414 Conf. Rep. at 97.
Docket Nos. RM19-15-000 and AD16-16-000 - 157 -

263. Indeed, the regulation adopted today does not subject QF rates to any examination 

whatsoever of the costs incurred by QFs in producing and selling power. Rather, the 

variable avoided cost energy rate provision applicable to QF contracts and other LEOs 

that is adopted in this final rule sets QF rates based on the avoided costs of the purchasing 

utility. In no sense can this variable avoided cost energy rate provision be characterized as 

imposing utility-style regulation on the QFs themselves.

264. Finally, we agree with Harvard Electricity Law that state regulators may not change 

rates in existing QF contracts or other existing LEOs.

415 By its terms, the variable energy 

avoided cost provision adopted in this final rule applies only prospectively to new 

contracts and new LEOs entered into after the effective date of this final rule. Nothing in 

the final rule, including in this preamble, should be read as sanctioning the modification of 

existing fixed-rate QF contracts and LEOs.

d. Whether the Current Approach Has Resulted in Payments 

to QFs in Excess of Avoided Costs 

i. Comments in Support of NOPR Proposal

265. Duke Energy states that its experience shows the Commission’s original

assumption that overestimations and underestimations will balance out over time was 

incorrect. From 2012 to 2017, Duke Energy states that it experienced explosive growth in 

solar QF contracts, and entered into at a time of rapidly declining natural gas prices—

which drove down Duke Energy’s avoided costs. Duke Energy states that, as of July 1, 

415 Harvard Electricity Law Comments at 23 (citing API, 461 U.S. at 414).
Docket Nos. RM19-15-000 and AD16-16-000 - 158 -

2019, it has almost 4,000 MW of QF power under contract and in commercial operation. 

Duke Energy claims the total estimated financial obligation on Duke Energy’s retail and 

wholesale customers to pay for this QF power is approximately $4.66 billion over the next 

approximately 15 years. If the contracts had been permitted to contain rates that mirrored 

the utilities’ declining incremental costs either to generate that electric energy itself or to 

purchase alternative electric energy, i.e., Duke Energy’s “actual current avoided costs,” 

Duke Energy asserts that the contracts would be valued at $2.4 billion. Duke Energy 

claims that, among the factors contributing to this overpayment of $2.26 billion for the 

remainder of these QF contracts, the primary factor has been the requirement to offer 

fixed avoided cost energy rates during a period of rapidly declining energy prices.416

266. EEI argues that relying on certain avoided cost methods, such as the costs of a 

proxy unit at a fixed point in time, may result, and has resulted, in the over estimation of 

future energy prices, leaving customers saddled with uneconomic PURPA contracts. 

According to EEI, the Commission’s variable rate proposal will help ensure that the 

variable energy rate more accurately reflects the electric utility’s actual avoided cost of 

energy so that rates for customers are just and reasonable. EEI describes this change as

important for states, especially those in RTO/ISO markets, that elect to have the avoided 

cost rate set at LMP. 

267. EEI also submitted with its comments a study performed by Concentric Energy 

Advisors showing that the avoided cost rates in the sample of solar and wind QF contracts 

416 Duke Energy Comments at 6.
Docket Nos. RM19-15-000 and AD16-16-000 - 159 -

they reviewed generally exceeded rates that are realized in competitive markets for solar 

and wind energy. According to that report, the total overpayment ranged between $2.7 

billion and $3.9 billion. Several other commenters also cited the Concentric Energy 

Advisors report for the proposition that consumers nationwide have overpaid for QF 

contracts between 2009-2018.417 Berkshire Hathaway represents that PURPA contracts 

held by PacifiCorp will cost customers more than $1.2 billion above projected market 

costs over the next 10 years.418

268. Massachusetts DPU argues that a 10-year, fixed energy rate based on current New 

England wholesale energy market prices is highly likely to diverge from actual energy 

market prices over the ten-year contract term and could significantly harm ratepayers.419 

Mr. Transeth represents that Consumers Energy’s QF contracts are priced between 30 to 

50% higher than their current market value.420 

269. APPA supports the variable energy rate proposal because the discrepancy between 

administratively set, locked-in, long-run avoided costs and actual market prices for the 

purchase of equivalent energy can be enormous, as demonstrated by the evidence 

submitted in the Technical Conference. According to APPA, were continued 

development of the IPP and renewable industries in jeopardy, the Commission might have 

417 Alliant Energy Comments at 7-8; Conservative Action Comments at 1; Duke 

Energy Comments at 5-7; Mr. Moore Comments at 2; Mr. Transeth Comments at 2.

418 Berkshire Hathaway Comments at 5.

419 Massachusetts DPU Comments at 7 (citing NOPR, 168 FERC ¶ 61,184 at 40).

420 Mr. Transeth Comments at 2.
Docket Nos. RM19-15-000 and AD16-16-000 - 160 -

grounds to conclude that enabling QFs to lock in energy payments over the course of their 

agreement is needed in order to bolster these resources, but the growth in the IPP and 

renewables industries in RTOs/ISOs indicate otherwise.421

270. Commissioner O’Donnell asserts that the Montana Public Service Commission has 

addressed concerns about overpayments by shortening QF contract length from 25 years 

to 15, which has resulted in litigation currently pending before the Montana Supreme 

Court. Commissioner O’Donnell asserts that, because the energy component of an 

avoided cost rate reflects the price at which the purchasing electric utility could purchase 

power on the open market, there is no need to fix that fluid energy component for as long 

as 25 years.422

271. Competitive Enterprise asserts that long-term fixed price rates “serve only to 

reward certain financial investors at the expense of consumers, who are forced to pay 

inflated rates for electricity” and insists that utilities should only be required to purchase 

from resources that are needed and competitively priced.423

ii. Comments in Opposition to NOPR Proposal

272. Harvard Electricity Law observes that the Commission’s examples of contract rates 

that exceed avoided costs calculated years prior illustrate the general proposition that 

“energy forecasts have a manifest record of failure.”424 Harvard Electricity Law notes, 

421 APPA Comments at 16.

422 Commissioner O’Donnell Comments at 2.

423 Competitive Enterprise Comments at 2.

424 Harvard Electricity Law Comments at 24 (citing Vaclav Smil, Energy at the 
Docket Nos. RM19-15-000 and AD16-16-000 - 161 -

however, that in issuing Order No. 69, the Commission recognized that industry changes 

are difficult to forecast, but the Commission nonetheless concluded in Order No. 69 that 

the possibility that consumers would be harmed by high rates was outweighed by the 

Commission’s duty to encourage QFs.425 Harvard Electricity Law further claims that the 

repeal of the fixed-price rule is not necessary to protect consumers from rates in future 

contracts.426 Harvard Electricity Law argues that the Commission’s rules do not require 

an annual matching between avoided costs and rates, nor prevent states from setting 

declining avoided costs (which Order No. 69 explicitly condones).427 

273. Several commenters argue that the NOPR’s assertion of artificially high avoided 

cost rates is unsupported or relies on flawed data and analysis.428 For example, NIPPC, 

CREA, REC, and OSEIA argue that the Commission relied on flawed data and analysis by 

using actual market prices that resulted after substantial QF penetration (which they assert 

has reduced power prices).429 

Crossroads: Global Perspectives and Uncertainties, Mass. Inst. Tech., 2003, at 121, 145-

149).

425 Harvard Electricity Law Comments at 24.

426 Id. at 23.

427 Id. at 23-24 (citing Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,881).

428 NIPPC, CREA, REC, and OSEIA Comments at 30; Public Interest 

Organizations Comments at 39-40; Public Interest Organizations Comments at 43; Solar 

Energy Industries Comments at 34-36.

429 NIPPC, CREA, REC, and OSEIA Comments at 30-31.
Docket Nos. RM19-15-000 and AD16-16-000 - 162 -

274. Public Interest Organizations claim that the NOPR’s evidence of overestimations is 

based on a selective choice of years reflecting general wholesale price declines, in which 

QF contracts were executed just before unforeseen natural gas price declines.430 Public 

Interest Organizations argue that these recent electricity price overestimations are not 

unique to QFs and can be explained by general declines in natural gas prices since the 

adoption of hydraulic fracturing and the 2007-2009 recession.431

275. Public Interest Organizations dispute Alliant’s asserted overestimation by claiming 

that Alliant likely would have procured non-QF energy at the same price and further point 

out that Alliant does not disclose the data upon which it relies.432 Public Interest 

Organizations assert that the Commission similarly erred in relying on EEI’s description 

of overestimations of avoided costs in PacifiCorp’s QF contracts because PacifiCorp only 

compares those prices to the Mid-C hub and does “not contain an analysis of the longterm balancing of its forecasted avoided energy rates with actual avoided energy costs.”433 

Public Interest Organizations contend that this comparison implies that PacifiCorp would 

have relied entirely on the Mid-C hub for all of its needs but for the QF contracts.434

430 Public Interest Organizations Comments at 39-40.

431 Id. at 47-50.

432 Id. at 40-41.

433 Id. at 41 (citing NOPR, 168 FERC ¶ 61,184 at P 64 n.101 (citing EEI Supplemental 

Comments, Docket No. AD16-16-000, attach. A at 3-4 (June 25, 2018))).

434 Id.
Docket Nos. RM19-15-000 and AD16-16-000 - 163 -

276. SC Solar Alliance contests Duke Energy’s estimate of $2.26 billion in 

overpayments for QF power. According to SC Solar Alliance, “an expert witness for 

South Carolina’s Office of Regulatory Staff, which represents the interests of the using 

and consuming public in proceedings before the South Carolina Commission, recently 

testified that Duke’s estimation of ‘overpayments’ to QFs was not reliable and that he 

‘wouldn’t put a whole lot of weight in [Duke’s estimate].’”435

277. GridLab attacks the conclusions of the Concentric Report, raising two principal 

arguments. First, according to GridLab, QF contracts are executed in non-competitive 

markets where utilities do not perform competitive solicitations. If QF avoided cost 

pricing is higher than prices set through competitive bidding, GridLab asserts that is 

because the utility’s production costs are higher than competitive prices.436 Second, 

GridLab asserts that Concentric has compared two datasets that are different in several 

ways, most notably project size—with larger projects enjoying economies of scale that 

result in lower costs. According to GridLab, the difference in project size and its impact 

on cost is a significant factor that could account for the whole of the reported increase on 

price.437

435 SC Solar Alliance Comments at 7 (quoting Public Service Commission of 

South Carolina, Docket No. 2019-185 & 186-E, Hearing Transcript Vol. 2 at 596, 

lines 6 – 21 (Horii Test.)) (attached as Appendix 1 to SC Solar Alliance Comments).

436 GridLab Comments at 1-2.

437 Id. at 4.
Docket Nos. RM19-15-000 and AD16-16-000 - 164 -

278. NIPPC, CREA, REC, and OSEIA argue that it was unreasonable for the 

Commission in the NOPR to assume that electricity price declines are permanent, given 

recent integrated resource plans (IRP) in the Northwest predicting significantly increased 

electricity demand and market prices at the Mid-C and Palo Verde hubs.438 NIPPC, 

CREA, REC, and OSEIA represent that electricity prices will climb significantly in the 

Northwest. NIPPC, CREA, REC, and OSEIA also assert that 100% renewable or nonemitting generation mandates and increased electrification of transportation could 

substantially increase electricity demand. NIPPC, CREA, REC, and OSEIA contend that 

fixed-price QF contracts protect consumers from the potential for future rising prices, 

market volatility, market risk, and project risk.439

279. Resources for the Future reasons that “while fixed prices determined [five to ten] 

years ago would likely exceed current average market prices, that may not be true for 

fixed prices determined either more recently or in the future.”440 Resources for the Future 

states that, contrary to the NOPR, there is no consensus that wind and solar generation 

costs will continue to decline because any capital cost declines will be relatively modest 

and will be offset by declining federal tax credits.441 Furthermore, Resources for the 

Future attributes these cost declines to the recent U.S. natural gas boom and points out that 

438 NIPPC, CREA, REC, and OSEIA Comments at 33-34.

439 Id. at 34-36.

440 Resources for the Future Comments at 4.

441 Id. at 5.
Docket Nos. RM19-15-000 and AD16-16-000 - 165 -

this decline is therefore not likely to continue.442 sPower similarly argues that recent 

energy price declines will not necessarily continue, especially given expiring tax credits 

and additional tariffs.443

280. Several commenters assert that the risk of overpayments to QFs should be 

compared to the alternative generation sources used by the utility.444 For example, 

ELCON claims that critics who assert that QFs are “locking-in” consumers to artificially 

high rates must acknowledge that utility procurement does exactly the same via the preapproval process, sometimes for even longer durations. ELCON argues that QFs can only 

benefit consumers by competing on a level playing field with comparable terms and 

conditions.445 North Carolina Commission Staff similarly asserts that the risk of 

overpayment to QFs should be considered in the context of a utility’s long-term 

commitment to build plants where “generation decisions are based upon uncertain 

forecasts that could result in ratepayers bearing the same type of forecast risk from utility 

plants as they do from QFs.”446

442 Id. at 4.

443 sPower Comments at 10-11.

444 ELCON Comments at 22; North Carolina Commission Staff Comments at 2-3; 

NIPPC, CREA, REC, and OSEIA Comments at 31; Public Interest Organizations 

Comments at 40,43; Solar Energy Industries Comments at 36-38.

445 ELCON Comments at 22.

446 North Carolina Commission Staff Comments at 2-3.
Docket Nos. RM19-15-000 and AD16-16-000 - 166 -

281. According to Solar Energy Industries, the risk from utility generation construction 

is allocated to ratepayers for the life of these assets regardless of ongoing changes in 

energy prices, while PURPA was designed to shift this risk away from ratepayers. Solar 

Energy Industries state that there is no evidence that ratepayers are harmed by long-term 

QF contracts any more than other long-term contracts or utility recovery of generation 

assets in their rate base. Solar Energy Industries state that, even though solar prices have 

declined over time, solar QFs should not be penalized for utility failures to update their 

avoided cost calculations to keep pace with such declines.

447

282. The DC Commission states that, with respect to the fact that long-term contracts 

(e.g., 20 years) using fixed avoided energy costs could create stranded costs potentially 

due to inaccurate projections, the chance of creating stranded costs is substantially 

reduced when the most up-to-date data regarding avoided energy costs is used. The DC 

Commission states that, if the contract length is permitted to be flexible, the possibility of 

stranded costs would be significantly reduced for shorter term contracts.448 The DC 

Commission states that, without the worry of stranded costs, there is no need to eliminate 

the fixed price contract option for QFs.449

447 Solar Energy Industries Comments at 36-38.

448 DC Commission Comments at 8.

449 Id.
Docket Nos. RM19-15-000 and AD16-16-000 - 167 -

iii. Commission Determination

283. As explained above, the NOPR proposal to give states the flexibility to require 

variable energy pricing in QF contracts and other LEOs, instead of providing QFs the 

right to elect fixed energy prices, was based on the Commission’s concern that, at least in 

some circumstances, long-term fixed avoided cost energy rates have been well above the

purchasing utility’s avoided costs for energy—a result prohibited by PURPA section 

210(b). And the record evidence demonstrates just that, i.e., that QF contract and LEO 

prices for energy can exceed and have exceeded avoided costs for energy without any 

subsequent balancing out. In addition to the examples presented in the record of the 

Technical Conference that were cited in the NOPR, commenters have provided additional 

examples of such overpayments, as described above.450 Such evidence has persuaded us

that it is necessary to give states the flexibility to address QF contract and LEO rates for 

energy that exceed avoided costs for energy, while at the same time still allowing states 

the flexibility to continue requiring long-term fixed avoided cost energy rates in QF 

contracts and other LEOs when such treatment is appropriate.

284. As Harvard Electricity Law concedes, the examples of QF contract rates that 

exceed avoided costs that are in the record illustrate the general proposition that “energy 

forecasts have a manifest record of failure.”451 It is this “manifest record of failure” 

450 See Duke Comments at 6; Idaho Power Comments at 10-11; Portland General 

Comments at 5; NOPR, 168 FERC ¶ 61,184 at P 64 n.101.

451 Harvard Electricity Law Comments at 24 (citing Vaclav Smil, Energy at the 

Crossroads: Global Perspectives and Uncertainties, Mass. Inst. Tech., 2003, at 121, 145-
Docket Nos. RM19-15-000 and AD16-16-000 - 168 -

including evidence in the record that the failure has been at the expense of consumers, that

drives us to make the change adopted in the final rule.

452

285. While some commenters challenge the idea that avoided cost energy rates in QF 

contracts and other LEOs have exceeded actual avoided costs, their arguments largely 

either concede that overestimations have occurred while arguing that such overestimations 

impacted purchasing electric utilities just as much as QFs, or attempt to argue that such

overestimations were temporary or unusual. For these reasons, they assert that the 

Commission should not conclude that historical overestimations of avoided cost require a 

change to the current PURPA Regulations requiring states to allow QFs to fix their 

avoided costs energy rates for the term of their contracts. These arguments do not cause 

us to reconsider our determination, for the reasons explained below.

286. First, Harvard Electricity Law’s citation to the Commission’s original 

determination in Order No. 69 that it was not necessary to provide for variable avoided 

cost energy rates carries little weight.453 The purpose of the NOPR was to reconsider the 

Commission’s determinations made in Order No. 69 in light of changes in circumstances 

and additional evidence that was not available to the Commission when it issued Order 

No. 69 in 1980. The record evidence cited above demonstrates that, contrary to the 

Commission’s finding in 1980, overestimations and underestimations of future avoided 

149)..

452 See, e.g., supra P 254 & note 403.

453 Id. at 23-24 (citing Order No. 69, FERC Stats. & Regs. ¶ 30,128, at 30,881).
Docket Nos. RM19-15-000 and AD16-16-000 - 169 -

costs may not even out.454 Consequently, the Commission’s determination in 1980 does 

not preclude the Commission from changing the rule adopted at that time.

287. We agree with Public Interest Organizations that the recent electricity price 

overestimations were not unique to QFs and can be explained by general declines in 

natural gas prices since the adoption of hydraulic fracturing and the 2007-2009 

recession.455 But that is precisely why the estimates of avoided costs reflected in the QF 

contracts and LEOs were incorrect and why the resulting fixed avoided cost energy rates 

reflected in such QF contracts and other LEOs resulted in QF rates well above utility 

avoided costs in violation of PURPA section 210(b); the precipitous decline in natural gas 

prices caused a corresponding reduction in utilities’ energy costs, and thus in their energy 

avoided costs but this decline was not reflected in the QFs’ fixed contract rates that

remained at their previous levels.

288. Similarly, arguments from commenters that electric utilities also based resource 

acquisitions on incorrect forecasts of natural gas prices456 ignore a key distinction between 

utility rates and fixed QF rates. Electric utilities may have relied on incorrect natural gas 

price forecasts to justify the timing and type of their resource acquisitions, as commenters 

454 See Duke Comments at 6; Idaho Power Comments at 10-11; Portland General 

Comments at 5; NOPR, 168 FERC ¶ 61,184 at 64 n.101.

455 Public Interest Organizations Comments at 47-50.

456 ELCON Comments at 22; North Carolina Commission Staff Comments at 2-3; 

NIPPC, CREA, REC, and OSEIA Comments at 31; Public Interest Organizations 

Comments at 40,43; Solar Energy Industries Comments at 36-38.
Docket Nos. RM19-15-000 and AD16-16-000 - 170 -

assert. But once an electric utility resource decision was made, their cost-based rate 

regimes typically obligated the electric utility eventually to pass through to customers any 

energy cost savings realized as a result of declining natural gas and other fuel prices, as 

well as any energy cost savings due to lower purchased power rates resulting from the 

decline in natural gas prices. By contrast, once QF avoided cost energy rates were fixed 

based on now-incorrect (and now-high) natural gas price forecasts, those energy rates 

remained fixed for the term of the QFs’ contracts and LEOs. Therefore, unlike fixed 

avoided cost energy rates in QF contracts and LEOs, cost-based electric utility energy 

rates declined as the cost of natural gas and other fuels and purchased power declined.

289. We also disagree with Public Interest Organizations’ assertions that it was improper 

to have used competitive market hub prices to determine whether fixed QF contract and 

LEO prices resulted in overpayments as compared to electric utilities’ actual avoided 

costs.457 We recognize that the competitive market hub prices used in the comparisons 

may not have precisely reflected the avoided energy costs of all electric utilities located in 

the same region as the competitive market hub. However, as explained above in the 

discussion of the use of Market Hub Prices to determine avoided energy costs, competitive 

market prices in general should reflect the marginal avoided energy costs of utilities with 

access to such markets. Certainly, those markets generally reflect the marginal cost of 

energy in the region.

458 The magnitude of the differences between the market hub prices 

457 Public Interest Organizations Comments at 40-41.

458 A review of recent Mid-C Hub daily spot prices (from Intercontinental 

Exchange (ICE) https://www.eia.gov/electricity/wholesale/, indicates that they reflect the 
Docket Nos. RM19-15-000 and AD16-16-000 - 171 -

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.

290. We acknowledge that energy prices may increase in the future, as several 

commenters point out.459 However, as noted by Harvard Electricity Law, “energy 

forecasts have a manifest record of failure.”460 Moreover, the fact that energy prices may

increase in the future does not eliminate the risk that fixed avoided cost energy rates could 

still be above actual avoided costs. That is, if the actual increase in energy prices is still

lower than the forecasted increase that would form the basis of the fixed avoided cost 

energy rate, then the fixed avoided cost energy rate will be above actual avoided energy 

costs. Giving states the flexibility to require variable avoided cost energy rates in QF 

contracts and in other LEOs will allow states to better ensure that avoided cost energy 

payments made to QFs will more accurately reflect the purchasing utility’s avoided costs 

marginal cost of energy in that area since they are usually the result of a significant 

number of trades (averaging 54 per day), counterparties (averaging 16 per day), and 

trading volume (averaging 26,714 MWh/day), which usually exceed those of the NP-15 

trading hub, an active Western trading hub in Northern California in the CAISO footprint

(averaging 6 trades per day, 4 counterparties per day, and 2,756/MWh per day). The 

prices for Mid-C ranged between an average of approximately $16/MWh high price and

$13/MWh low price during the recent spring (Mar 19-Jun 20, 2020). During this period

the index was reported for 65 trading days for Mid-C and 9 trading days for NP-15.

459 NIPPC, CREA, REC, and OSEIA Comments at 33-36; Resources for the Future 

Comments at 4; sPower comments at 10-11.

460 Harvard Electricity Law Comments at 24 (citing Vaclav Smil, Energy at the 

Crossroads: Global Perspectives and Uncertainties, Mass. Inst. Tech., 2003, at 121, 145-

149).
Docket Nos. RM19-15-000 and AD16-16-000 - 172 -

regardless of whether energy prices are increasing or declining. We also note that, if 

energy prices do in fact increase, variable avoided cost energy pricing would protect and 

even benefit the QF itself, as it would not be locked into a fixed energy rate contract or 

LEO that would be below the purchasing electric utility’s avoided energy cost.

291. Although many commenters agreed that fixed QF energy rates were higher than 

actual avoided energy costs in at least some instances, challenges were raised against both 

Duke Energy’s estimate that its fixed QF contract rates were $2.6 billion above market 

costs, and the Concentric Report’s comparison of QF fixed rates for wind and solar 

facilities with the cost of wind and solar projects with competitive, non-PURPA contracts. 

292. However, the expert testimony cited by the SC Solar Alliance, that the witness 

“wouldn’t put a whole lot of weight in [Duke’s estimate],”461 does not address Duke’s 

calculation of past overpayments. Rather, the witness was answering a question regarding 

the potential for overpayments “[f]or going forward solar,” i.e., future overpayments as a 

result of the new fixed avoided cost rates being considered by the South Carolina 

Commission that were the subject of the expert witness’ testimony.462 The same witness 

acknowledged the past overpayments made by Duke Energy, which he attributed to 

461 SC Solar Alliance Comments at 7 (quoting, Public Service Commission of 

South Carolina, Docket No. 2019-185 & 186-E, Hearing Transcript Vol. 2, Tr. at 596: 6–

21 (Horii Test)) (attached as Appendix 1 to SC Solar Alliance Comments).

462 Public Service Commission of South Carolina, Docket No. 2019-185 & 186-E, 

Hearing Transcript Vol. 2, Tr. 596: 3-4 (Horii Test)) (attached as Appendix 1 to SC Solar 

Alliance Comments).
Docket Nos. RM19-15-000 and AD16-16-000 - 173 -

“drops in natural gas prices that no one could’ve foreseen.”463 It is these overpayments 

due to unforeseen declines in natural gas prices that form an important basis for the 

Commission’s determination in this final rule to now give states the flexibility to require 

variable avoided cost energy rates in QF contracts and LEOs.

293. With respect to the criticisms of the Concentric Report, we emphasize that we have 

not relied on that report to support the variable energy avoided cost provision adopted in 

the final rule. It is not clear that the lower cost of the competitively priced renewable 

resources identified in the report represents the avoided costs of the purchasing utilities 

that entered into the QF contracts at fixed rates for renewable resources under PURPA. 

Therefore, it is not clear that the difference in costs identified by Concentric can be 

ascribed to the fixed rates in the QF contracts or rather to the fact that the avoided cost 

rates in the QF contracts were based on more expensive non-renewable capacity that was 

avoided by the purchasing utilities. 

e. Whether the Proposed Change Would Violate the 

Statutory Requirement that the PURPA Regulations 

Encourage QFs 

i. Comments

294. Several commenters argue that the NOPR’s variable rate proposal is inconsistent 

with PURPA’s mandate that the PURPA Regulations “encourage” the development of 

QFs.

464 Southeast Public Interest Organizations state that removing QFs’ right to a fixed 

463 Id. at 593:21-22.

464 Allco Comments at 9; Con Edison at 3, 4; Harvard Electricity Law Comments at 

1; North American-Central Comments at 4-6; Southeast Public Interest Organizations at 
Docket Nos. RM19-15-000 and AD16-16-000 - 174 -

energy rate would flout Congressional intent that PURPA encourage QF development 

because fixed rates are necessary to attract QF financing.465 Harvard Electricity Law

states that Congress’s mandate to encourage QFs is not contingent on industry conditions 

and does not expire.466

ii. Commission Determination

295. As explained above in Section IV.A.1, the statutory requirement that the 

Commission’s PURPA Regulations encourage QFs remains, but it is bounded by the 

statutory provision in PURPA section 210(b) that QF rates may not exceed a purchasing 

utility’s avoided costs. Further, as explained above, we have determined, based on the 

record evidence, that it is not necessarily the case that overestimations and 

underestimations of avoided energy costs will balance out. Consequently, a fixed energy 

rate in a QF contract or LEO potentially could violate the statutory avoided cost cap on 

QF rates. 

296. The Commission’s PURPA Regulations continue to encourage the development of 

QFs by, among other things, allowing a state to vary the rate paid to the QF over time but 

in a way that satisfies the rate cap established in PURPA section 210(b). In this way, the 

QF can obtain a higher rate when the utility’s avoided costs increase, and ratepayers are 

not paying more than the utility’s avoided costs when prices decrease. Furthermore, as 

9-11.

465 Southeast Public Interest Organizations Comments at 9-10.

466 Harvard Electricity Law Comments at 1.
Docket Nos. RM19-15-000 and AD16-16-000 - 175 -

discussed above, allowing the use of variable energy rates may promote longer contract 

terms, which would help encourage and support QFs.467 It therefore is consistent with 

PURPA section 210(b), as well as the obligation imposed by PURPA section 210(a) to 

revise the Commission’s PURPA Regulations “from time to time,” to provide the states 

the flexibility to require that QF contracts and other LEOs implement variable avoided 

cost energy rates in order to prevent payments to QFs in excess of the purchasing electric 

utility’s avoided energy costs. PURPA section 210(b) prohibits the Commission from

requiring QF rates above avoided costs even if, according to some commenters, a fixed 

avoided cost energy rate would provide greater encouragement to QFs than a variable 

avoided cost energy rate.

f. Discrimination

i. Comments in Support of NOPR Proposal

297. Alliant Energy observes that utility-owned generation and traditional power 

purchase agreements (PPAs) are subject to a demonstration of need and that traditional 

PPAs are subject to re-evaluation during their term to determine whether they continue to 

be cost-competitive and in the best interests of customers. Alliant Energy asserts that, by 

contrast, QFs are not required to demonstrate that their projects are needed and that, once 

a contract is executed, it is not subject to re-evaluation.468

467 See infra P 349.

468 Alliant Energy Comments at 6-7.
Docket Nos. RM19-15-000 and AD16-16-000 - 176 -

ii. Comments in Opposition to NOPR Proposal

298. Several commenters assert that the NOPR’s variable avoided cost energy rate 

proposal is discriminatory.469 For example, EPSA argues that PURPA requires the 

Commission to implement regulations that, for rates for electric utility purchases from 

QFs, “shall not discriminate against qualifying cogenerators or qualifying small power 

producers.” EPSA describes this standard as more restrictive than the FPA’s prohibition 

against “unduly discriminatory” rates. According to EPSA, the fact that long-term QF 

contracts are substantially above prevailing market prices due to declining wholesale 

prices over the long-term does not justify the variable rate proposal because electric 

utility-owned generation is similarly based on imperfect long-term forecasts of energy 

prices that oftentimes prove to be too high. EPSA therefore argues that the NOPR 

variable rate proposal should not be adopted unless utility-owned assets are also subject to 

a similar cost recovery regime.470

299. sPower describes the NOPR proposal to allow variable rates as providing a 

significant advantage to electric utilities over QFs, given that electric utilities themselves, 

according to sPower, have not had to lower rates to consumers as energy prices have 

declined.471 ELCON asserts that pushing more market risk to QFs while utility assets 

469 ELCON Comments at 21-22; SC Solar Alliance Comments at 5-10; sPower 

Comments at 13; see also ELCON Comments at 22; North Carolina Commission Staff 

Comments at 2-3; NIPPC, CREA, REC, and OSEIA Comments at 31; Public Interest 

Organizations Comments at 40, 43; Solar Energy Industries Comments at 36-38.

470 EPSA Comments at 8-9.

471 sPower Comments at 13.
Docket Nos. RM19-15-000 and AD16-16-000 - 177 -

remain insulated from markets creates an investment risk asymmetry. ELCON claims this 

puts QFs at a competitive disadvantage and shifts the consumer burden to more utility 

builds, which have generally been higher cost than merchant builds.

472

300. SC Solar Alliance states that utilities often rely on fuel price forecasts over time to 

justify rate base approval for generation assets that might run beyond price forecasts. SC 

Solar Alliance argues that allowing utilities this right, but not QFs, holds QFs to a much 

higher standard than utilities and therefore is discriminatory.473 

301. Commissioner Slaughter argues that, by removing the fixed, long-term contract 

option for independent power producers, the NOPR threatens to hamper the 

competitiveness of renewable-based energy firms challenging vertically integrated utilities 

in many localities across the country.474 

iii. Commission Determination

302. The discrimination claims are based on the incorrect assumption that electric 

utilities have not been required to lower their energy rates as prices have declined. To the 

contrary, as explained above, utilities typically charge their customers cost-based rates, 

and as their fuel and purchased power costs have declined, they typically have been 

required to provide corresponding reductions in the energy portion of their rates to their 

472 ELCON Comments at 21-22.

473 SC Solar Alliance Comments at 5-10.

474 Commissioner Slaughter Comments at 4.
Docket Nos. RM19-15-000 and AD16-16-000 - 178 -

customers.475 Requiring QF avoided cost energy rates to likewise change as purchasing 

electric utilities’ avoided energy costs change does not create a discriminatory difference, 

but rather puts QF rates on par with utility rates.

303. Further, we are not changing the requirement that QF avoided cost energy rates be 

set at the purchasing utility’s full avoided energy costs. As the Supreme Court held in 

API, “the full-avoided-cost rule plainly satisfies the nondiscrimination requirement.”476 

Rather, we are allowing the states the option to now choose to require QF avoided cost 

energy rates that vary with the purchasing utility’s avoided costs of energy, rather than QF 

avoided cost rates that are fixed for the life of the QF’s contract or LEO, to ensure the 

rates comply with PURPA. 

g. Effect of Variable Energy Rates on Financing

i. Comments in Support of the NOPR Proposal

304. Several commenters state that fixed energy payments are not necessary for QFs to 

obtain financing.

477 Alliant states that it is on track to be the third largest utility owneroperator of wind facilities in the United States, with 1.9 GW on its system and in addition 

is increasing the pace of solar resource development in its Wisconsin territory. Alliant 

475 See supra PP 40, 122, 288.

476 API, 461 U.S. at 413.

477 APPA Comments at 16-17; Indiana Commission Comments at 6.
Docket Nos. RM19-15-000 and AD16-16-000 - 179 -

states it therefore does not believe that the proposed change will slow renewable 

deployment and adoption.478 

305. Several commenters assert that PURPA’s must-purchase requirement itself should 

necessarily afford QF developers a degree of certainty and enables developers to attract 

capital at advantageous terms.479 The Idaho Commission states that, even if modified as 

proposed, QF contract terms would remain superior to competitively bid renewable

projects where the energy is not “must take” and curtailment and other reliability 

parameters are imposed.480

306. Finadvice and APPA argue that maintaining a fixed capacity rate, as proposed by 

the Commission, will help attract capital and ameliorate any negative effect that the 

variable energy rate proposal may impose.

481 Ohio Commission Energy Advocate argues, 

as evidence that QFs can still flourish under a variable energy rate, that the PJM market 

has successfully attracted new supplies and ensured resource adequacy through fixed 

capacity and variable energy rates.

482

307. The Idaho Commission states that variable energy prices protect the ratepayer 

while allowing the QF to ensure a stream of revenue through a longer-term contract. The 

478 Alliant Energy Comments at 6.

479 APPA Comments at 16-17; Finadvice Comments at 2; Idaho Commission

Comments at 4; Commissioner O’Donnell Comments at 3.

480 Idaho Commission Comments at 4.

481 APPA Comments at 16-17; Finadvice Comments at 2.

482 Ohio Commission Energy Advocate Comments at 3-4.
Docket Nos. RM19-15-000 and AD16-16-000 - 180 -

Idaho Commission affirms that the rapid growth of non-QF renewable projects and their 

ability to obtain financing should quell any concerns about a QF’s ability to obtain 

financing as long as PURPA’s “must take” provision remains.483 Commissioner 

O’Donnell asserts that QFs should bear some market risk as energy prices rise and fall in a 

way that balances risks to all parties.484

308. EEI argues that PURPA does not require the Commission or the states to 

implement regulations that guarantee a QF’s financeability. EEI represents that Congress 

intended QFs to be treated similarly to merchant generation and simply required QFs to 

have non-discriminatory access. According to EEI, because QFs are not subjected to the 

oversight or regulatory responsibilities applicable to electric utilities, it was not expected 

or intended that QFs be treated the same as electric utilities.485 Similarly, Duke argues 

that the central design criteria for PURPA rates and terms should be customer 

indifference, just and reasonableness, and non-discrimination. Duke Energy states that a

design that requires QF financeability as a criterion will inevitably lead to a QF boom and 

customer harm.486 Duke Energy further asserts that several factors affect financeability 

483 Idaho Commission Comments at 4.

484 Commissioner O’Donnell Comments at 3.

485 EEI Comments at 35.

486 Duke Energy Comments at 17-18.
Docket Nos. RM19-15-000 and AD16-16-000 - 181 -

and that, therefore, claims by QFs that they require fixed energy payments for financing 

purposes should be rejected.487

309. EEI claims QFs that require third-party financing will still be able to obtain 

financing if the Commission adopts the proposals in the NOPR, because they are 

additional options, in addition to those currently being used by states, that will be 

available to determine avoided costs. EEI maintains that a QF developer will be able to 

obtain financing under any of the options, provided it can build a cost-efficient plant that 

can profit at an avoided cost rate.488 EEI claims that independent power producers lacking 

the certainty of the mandatory purchase obligation are building most renewable generation 

today because merchant power plants may be developed and financed using a variety of 

hedging and risk management tools, such as commodity hedges, that lock in cash flows 

and facilitate construction at the outset.

489

310. APPA states that much of the renewable development that has occurred over the 

past 20 years has taken place within RTO/ISO footprints and therefore is largely unaided 

by PURPA obligations.

490

311. Duke Energy states that concern about the potential for fixed avoided cost contract 

rates exceeding actual avoided costs at the time of delivery have led both North Carolina 

487 Id. at 13.

488 EEI Comments at 35-36.

489 Id. at 36.

490 APPA Comments at 16-17.
Docket Nos. RM19-15-000 and AD16-16-000 - 182 -

and South Carolina to enact laws placing limits on the length of QF contracts.491 The 

Idaho Commission states that there is no evidence that variable energy prices would be 

fatal to QF development.492 The Idaho Commission states that it reduced contract length 

on large projects to two years because it did not interpret the Commission's current rules 

to allow for a variable energy rate inside a long-term contract. The Idaho Commission 

states that, because its experience dictated that the longer the contract term, the more 

inflated the avoided cost rate, the Idaho Commission set parameters to balance QF 

interests against utility ratepayer interests. The Idaho Commission states that an energy 

rate established at the time of contract formation that provides for “revisions to the energy 

rate at regular intervals, consistent with, for example, a purchasing electric utility’s 

[integrated resource planning (IRP)] to reflect updated avoided cost calculations” would 

allow states to consider longer term contracts without putting ratepayers at risk.493 

NorthWestern represents that the Montana Commission has lowered the length of QF 

contracts from 25 to 15 years in response to the current requirement that QFs are entitled 

to fixed avoided cost rates for energy in their contracts and a concern that rates calculated 

at the time a contract is signed are likely to change over the life of that contract.494

491 Duke Energy Comments at 9; LG&E/KU Comments at 4.

492 Idaho Commission Comments at 4.

493 Id. (citing NOPR, 168 FERC ¶ 61,184 at P 5 n.5).

494 NorthWestern Comments at 6-7.
Docket Nos. RM19-15-000 and AD16-16-000 - 183 -

ii. Comments in Opposition to the NOPR Proposal

312. Many commenters assert that the NOPR’s variable energy rate proposal will result 

in QFs being unable to obtain financing.495 Several commenters also assert that it is 

discriminatory that utilities and non-QF generators can rate-base long-term investments 

and recover actual operating costs, while the NOPR’s proposed rules would deprive QFs 

of a reasonable ability to forecast their cost recovery with no guarantees.

496

313. Several commenters assert that the NOPR lacks evidence on the record to conclude 

that the variable rate proposal would not affect the ability of QFs to obtain financing.497 

NIPPC, CREA, REC, and OSEIA argue that the NOPR contained no record evidence 

demonstrating how this proposal would continue to encourage QFs in a nondiscriminatory manner,

498 and lacks evidence on how QF generation can be financed 

495 Allco Comments at 9; AllEarth Comments at 2; Biogas Comments at 2; 

BluEarth Comments at 2; Biological Diversity Comments at 8; Commissioner Slaughter 

Comments at 4; Con Edison Comments at 3, 4; Covanta Comments at 7-8; DC 

Commission Comments at 6-8; Distributed Sun Comments at 1; EPSA Comments at 2; 

Energy Recovery at 4; Harvard Electricity Law Comments at 5; Massachusetts AG 

Comments at 8-9; New England Hydro Comments at 8; NIPPC, CREA, REC, and OSEIA 

Comments at 37-38; North Carolina DOJ Comments at 3, 6; North American-Central

Comments at 4-6; Public Interest Organizations Comments at 6-7; Resources for the 

Future Comments at 6-7. SC Solar Alliance Comments at 5-7; Southeast Public Interest 

Organizations Comments at 9-11; State Entities Comments at 2-3; Two Dot Wind 

Comments at 11-13.

496 Allco Comments at 9; Commissioner Slaughter at 4; Harvard Electricity Law 

Comments at 5; NIPPC, CREA, REC, and OSEIA Comments at 36-37; Public Interest 

Organizations Comments at 6-7; Solar Energy Industries at 29-30.

497 NIPPC, CREA, REC, and OSEIA Comments at 29, 46; Harvard Electricity Law 

Comments at 22, 25-27; Public Interest Organizations Comments at 6-7, 33-35. 

498 NIPPC, CREA, REC, and OSEIA Comments at 29.
Docket Nos. RM19-15-000 and AD16-16-000 - 184 -

without a fixed energy rate.499 Similarly, Harvard Electricity Law asserts that repealing 

the fixed-price PPA requirement is premised on irrelevant data and ignores the record, and 

disagrees with the Commission’s demonstration of information on non-QF capacity to 

show that QF development no longer relies on contracts with fixed energy rates.

500 

314. Public Interest Organizations assert that testimony from Southern Company,

American Forest and Paper Association, and Solar Energy Industries, upon which the 

NOPR relies, states that non-QF renewable PPAs generally entail fixed energy rates rather 

than variable energy rates.501 In particular, Public Interest Organizations state that 

testimony from Solar Energy Industries, refers to reliance on fixed rates for energy and/or 

capacity without describing them as alternatives but rather “an acknowledgement that a 

[power purchase agreement] may provide fixed capacity in addition to fixed energy 

revenue, not a suggestion that a QF can be developed without a predictable energy 

revenue stream.”502

315. Allco describes programs in California, Massachusetts, Connecticut, and Vermont 

that offer standard QF contract programs with variable energy rates, none of which, 

499 Id. at 46-48.

500 Harvard Electricity Law Comments at 22, 25 (citing NOPR, 168 FERC ¶ 61,184 

at PP 69-70, 76).

501 Public Interest Organizations Comments at 33-35 (citing NOPR, 168 FERC 

¶ 61,184, at P 70 n.114 (citing Tech. Conference, Docket No. AD16-16-000, Tr. at 153, 

200 (filed June 30, 2016))).

502 Id. at 35 (citing NOPR, 168 FERC ¶ 61,184, at P 70 n.115 (citing Solar Energy 

Industries Comments, Docket No. AD16-16-000, at 3 (filed June 30, 2016))).
Docket Nos. RM19-15-000 and AD16-16-000 - 185 -

according to Allco, have led to the construction of solar projects.503 Allco claims that 

these programs prove that, without the ability to obtain a fixed long-term forecasted rate, 

QF solar energy development will not exist.

504 Southeast Public Interest Organizations 

assert that Southeastern states with fixed QF energy rates have seen vigorous QF 

development, while Southeastern states with variable energy rates have seen virtually no

QF development, undermining the Commission’s assertion that QFs can be financed 

without fixed energy rates.

505

316. Covanta and Energy Recovery state that the NOPR’s variable rate proposal would 

have an especially negative effect on Waste to Energy facilities.506 Covanta states that, 

because Waste to Energy depends on finite local tax resources, a loss in energy revenue 

due to price variability cannot be easily replaced.507 Covanta states that, without adequate 

QF pricing and multi-year contracts (and consistent, predictable pricing throughout the life 

of the contract), local governments may be forced to close their Waste to Energy facilities

prematurely, to minimize loss and stranding that investment.

508 Energy Recovery states 

503 Allco Comments at 10.

504 Id. at 9-11.

505 Southeast Public Interest Organizations Comments at 9-11, 15-16.

506 Covanta Comments at 7-8; Energy Recovery Comments at 1, 4.

507 Covanta Comments at 7-8.

508 Id. at 8.
Docket Nos. RM19-15-000 and AD16-16-000 - 186 -

that the inability to secure suitable rates through a long-term contract has closed seventeen

Waste to Energy facilities in the last fifteen years.509

317. NIPPC, CREA, REC, and OSEIA state that the NOPR’s anecdotal reliance on tax 

incentives to encourage QF development is irrelevant because these incentives are 

declining or disappearing, thereby requiring QFs to rely even more on energy rates.

510 

NIPPC, CREA, REC, and OSEIA predict that the NOPR’s proposed rules would make QF 

development riskier and would thereby slow the development of new technologies such as 

energy storage, hydrogen fuels, and other advanced renewable energy technologies.511

318. Solar Energy Industries states that financing for QFs differs from financing for 

fossil fuel generators because “much of the cost of installation is incurred up-front, but 

once installed, the generation has little, if any, variable cost.”512 Likewise, Harvard 

Electricity Law observes that wind and solar QFs, for example, have higher capital costs, 

lower operating costs, and provide energy intermittently, and therefore have 

characteristics that may present different financing challenges as compared to non-QF 

natural gas fired capacity.513 Similarly, Public Interest Organizations argue that, unlike 

independent power producer natural gas generators with fixed capacity payments and 

509 Energy Recovery Comments at 3.

510 NIPPC, CREA, REC, and OSEIA Comments at 40-41.

511 Id. at 41-42.

512 Solar Energy Industries Comments at 30.

513 Harvard Electricity Law Comments at 26.
Docket Nos. RM19-15-000 and AD16-16-000 - 187 -

variable energy costs, renewable QFs rely on fixed energy payments to cover their capital 

costs given their own nominal variable energy costs.514

319. NIPPC, CREA, REC, and OSEIA state that the financeability of generation with 

fixed capacity prices and variable energy prices inside RTOs/ISOs is irrelevant to regions 

that lie outside of RTOs/ISOs.515 NIPPC, CREA, REC, and OSEIA criticize the NOPR’s 

reliance on an independent power producer natural gas turbine’s financeability outside the 

RTO/ISO context as irrelevant to QFs because these natural gas turbines receive fixed 

capacity payments and variable energy payments to account for the fluctuating price of 

fuel; whereas a QF would need a sufficient fixed capacity payment to support financing 

and an energy rate that removes market risk.

516

320. NIPPC, CREA, REC, and OSEIA state that the NOPR’s reference to hedging 

instruments to reduce risks from fluctuating prices is irrelevant.

517 NIPPC, CREA, REC, 

and OSEIA state that hedging makes projects less financeable because it increases 

transaction and compliance costs for small power producer QFs that cannot afford large 

legal divisions and trading floors to employ such hedges.518

514 Public Interest Organizations Comments at 33-34.

515 NIPPC, CREA, REC, and OSEIA Comments at 42-43.

516 Id.

517 Id. at 44-45 (citing NOPR, 168 FERC ¶ 61,184 at P 72 & n.117).

518 Id. at 45-46.
Docket Nos. RM19-15-000 and AD16-16-000 - 188 -

321. Resources for the Future states that wind projects have used bank hedges, synthetic 

PPAs, and proxy revenue swaps.519 Resources for the Future claims, however, that these 

products would be inaccessible to most wind QFs if fixed energy payments are eliminated. 

Resources for the Future argues that solar QFs would have even less access to such 

hedging given their smaller size and high transaction costs. Resources for the Future 

states that QFs under 5 MW in RTO/ISOs and QFs outside of RTO/ISOs thus would be 

unable to obtain financing.520

322. Solar Energy Industries states that QFs in RTO/ISO markets without a fixed energy 

rate would require a hedging instrument to finance their projects. Solar Energy Industries 

further states that QFs outside RTO/ISO markets without a fixed energy rate would be 

unable to finance their projects because they would have no access to such hedging 

mechanisms.521 Solar Energy Industries states that the NOPR failed to consider which 

markets offer financial products, whether these financial products are available to QFs 

outside RTOs/ISOs, and whether these products will be sufficient to provide financing to 

QFs.522

323. Solar Energy Industries states that financing for QFs differs from financing for 

fossil fuel generators because much of the cost of installation is incurred up-front, with 

519 Resources for the Future Comments at 6.

520 Id. at 6-7.

521 Solar Energy Industries Comments at 30.

522 Id. at 31.
Docket Nos. RM19-15-000 and AD16-16-000 - 189 -

virtually no variable costs. Solar Energy Industries states that, because of this difference, 

financiers “examine the QF’s projected revenue stream to ensure that the revenue stream 

is sufficient to recover the installed costs plus a competitive return.”523 Solar Energy 

Industries reasons that QFs must therefore know in advance their facility’s energy and 

capacity values and obtain a legally enforceable contract that fits into common 

underwriting models.524

324. North Carolina DOJ asserts that allowing avoided cost energy prices to fluctuate 

could eliminate fixed-price power sales contracts, thereby making compensation to QFs 

more volatile and discouraging renewable energy financing.525

325. Distributed Sun agrees with Commissioner Glick’s dissent on the NOPR that 

revoking the fixed energy price requirement would halt the construction of most

distributed energy resources.526 Solar Energy Industries states that it is not aware of a 

meaningful number of QFs that have been constructed using capacity rates alone or 

capacity rates with variable energy rates.527

326. Mr. Mattson argues that a variable rate or a rate based on a projected stream of 

revenues during the contract are not long-term contracts. Mr. Mattson argues that this 

523 Id.

524 Id.

525 North Carolina DOJ Comments at 3.

526 Distributed Sun Comments at 3.

527 Solar Energy Industries Comments at 28.
Docket Nos. RM19-15-000 and AD16-16-000 - 190 -

violates legislative intent and precedent and is not viable, suggesting that PURPA requires 

avoided cost data to be kept by a utility for public inspection.528

327. Western Resource Councils represents that PURPA, in the rural Northern Plains 

and Rocky Mountain West, is the only vehicle for small businesses to obtain project 

financing and that variable rates undermine the certainty of QFs obtaining financing.529

328. Public Interest Organizations assert that the NOPR has no basis to speculate that 

the Idaho Commission shortened contract lengths to two years because of the fixed rate 

requirement or that it would provide longer contracts if it could require variable energy 

rates.530 According to Public Interest Organizations, the fact that no solar and wind QFs 

have been developed since the Idaho Commission set a two year contract length, even 

while they are currently entitled to fixed rates, shows that allowing variable rates will 

further discourage wind and solar QF development.531 

329. sPower argues that, even with long-term contracts, QFs will not be viable without 

fixed energy rates and explains that, if the Commission seeks to encourage states to offer 

longer contract terms, it should just require longer terms.

532

528 Mr. Mattson Comments at 26.

529 Western Resource Councils Comments at 2.

530 Public Interest Organizations Comments at 36.

531 Id. at 35-38.

532 sPower Comments at 11.
Docket Nos. RM19-15-000 and AD16-16-000 - 191 -

330. The DC Commission states that, in the jurisdictions where the contract length has 

been adjusted to “short-term,” such as Idaho’s two-year contract,533 further elimination of 

the QF fixed price contract option would discourage or eliminate new small renewable 

energy facilities entering the markets, which is not consistent with PURPA’s objective of 

encouraging the construction of renewable generation.534

331. NIPPC, CREA, REC, OSEIA, and Public Interest Organizations argue that the fact 

that states have shortened the length of QF contracts in response to fixed energy prices 

means that the Commission should require a minimum contract length.535 Green Power 

supports the creation of longer-term standard contract lengths for both cogeneration and 

small power production facilities.536 Green Power recommends that cogeneration 

developers are offered 5, 8, or 10-year contracts and that small power producers 

developers are offered 10, 15, or 20-year contracts.537 Mr. Mattson proposes that longterm contracts, defined as 20 years or longer, be available to QFs at their discretion.538

332. CARE notes that a purchasing utility’s fixed capacity value may be zero if the state 

determines that the electric utility has no need for additional capacity resources. In that 

533 DC Commission Comments at 8 (citing NOPR, 168 FERC ¶ 61,184 at P 77).

534 Id.

535 NIPPC, CREA, REC, and OSEIA Comments at 47-48; Public Interest 

Organizations Comments at 6-7.

536 Green Power Comments at 2, 10.

537 Id. at 10.

538 Mr. Mattson Comments at 7-9.
Docket Nos. RM19-15-000 and AD16-16-000 - 192 -

circumstance, there would be no fixed element in an avoided cost contract, which CARE 

believes would be inconsistent with the Commission’s rationale justifying variable energy 

rate contracts.

539 EPSA similarly argues that, as noted in the NOPR, an electric utility is 

not required to pay for QF capacity that the state has determined is not needed. EPSA 

claims that the variable rate proposal therefore would create substantial uncertainty for QF 

developers and investors in non-ISO/RTO regions.540

333. American Biogas argues that LMP prices are not sufficient to sustain existing 

biogas projects or to increase their number.

541 Several commenters state that LMP cannot 

sustain QFs in general.542 

334. NIPPC, CREA, REC, and OSEIA argue that the NOPR proposal to base QF pricing 

on LMP or Western EIM will limit competition, because QFs will be stuck with no longterm assurance of investment recovery, and thus with no means to finance their projects, 

while regulated incumbent utilities will be able to rate-base their generation assets, thus 

guaranteeing long-term recovery of their investments.543 NIPPC, CREA, REC, and 

OSEIA maintain that prices for long-term QF contracts should be set by reference to longterm price indices or other indicators that, unlike highly-variable LMP and Western EIM 

539 CARE Comments at 4 n.7.

540 EPSA Comments at 12.

541 Biogas Comments at 2.

542 BluEarth Renewables Comments at 2; Biological Diversity at 8; Covanta 

Comments at 9; Public Interest Organization Comments at 43-44.

543 NIPPC, CREA, REC, and OSEIA Comments at 55-56.
Docket Nos. RM19-15-000 and AD16-16-000 - 193 -

prices, genuinely reflect the long-term costs of generation avoided by the purchasing 

utility.544

iii. Commission Determination

335. As an initial matter, the Commission agrees with commenters that PURPA does not 

guarantee QFs a rate that guarantees financing. PURPA only requires the Commission to 

adopt rules that encourage the development of QFs; it does not provide a guarantee that 

any particular QF will be developed or profitable. This is evident from the structure of 

PURPA, which caps QF rates at the purchasing utility’s avoided costs rather than 

providing for rates that guarantee the recovery of a QF’s costs. The legislative history 

confirms that Congress did not intend to guarantee QF financing. As stated in the PURPA 

Conference Report, “the Conferees recognize that [QFs] are different from electric 

utilities, not being guaranteed a rate of return on their activities generally or on the 

activities vis-a-vis the sale of power to the utility and whose risk in proceeding forward in 

the [QF] enterprise is not guaranteed to be recoverable.”545 

336. Notwithstanding that PURPA does not guarantee QF financeability, the 

Commission believes that the variable avoided cost energy rate option implemented by 

this final rule will still allow QFs to obtain financing. 

337. Before addressing specific comments on this issue, however, we reiterate that we 

are not eliminating fixed rate pricing for QFs. Under this final rule, QFs will continue to 

544 Id. at 53.

545 Conf. Rep. at 97-98 (emphasis added).
Docket Nos. RM19-15-000 and AD16-16-000 - 194 -

be able to require fixed avoided cost capacity rates in their contracts and LEOs. Capacity 

costs, as relevant here, include the cost of constructing the capacity being avoided by 

purchasing utilities as a consequence of their purchases from QFs. As will be discussed 

below, a combination of fixed avoided cost capacity rates and variable energy rates can 

provide important revenue streams that can support the financing of QFs. 

338. Furthermore, merely because QFs have had access to fixed avoided cost energy 

rates does not mean that QFs must have access to such rates to obtain future financing. 

Up to now, QFs have had the right under the PURPA Regulations to both fixed capacity 

and fixed energy rates, and we understand that most QFs executing long-term contracts 

have exercised this right. Commenters insisting that the Commission cannot allow states 

the option to impose variable avoided cost energy rates without evidence that QFs have 

obtained financing under such contract structures546 are attempting to impose a standard 

that could never be satisfied.

339. In any event, there is ample evidence outside of the PURPA context demonstrating 

that generation projects with fixed capacity rate-variable energy contracts are financeable. 

As the Commission explained in detail in the NOPR, since the time of the passage of 

PURPA a large new independent power production industry has developed in the United 

States. Like QFs, independent power producers sell power at wholesale, and have no 

ability to rate-base their facilities or to otherwise recover their costs through regulated 

546 See Solar Energy Industries Comments at 28; NIPPC, CREA, REC, and OSEIA 

Comments at 29, 46; Harvard Electricity Law Comments at 22, 25-27; Public Interest 

Organizations Comments at 6-7, 33-35.
Docket Nos. RM19-15-000 and AD16-16-000 - 195 -

rates to retail customers, unlike traditional utilities with franchised service territories and 

retail customers. Unlike QFs, however, independent power producers have had no right to 

require utilities to purchase their power or to impose fixed energy cost pricing in their 

power sales contracts.547 

340. The record shows that, even without the right to require long-term fixed energy 

rates, non-QF independent power producers nevertheless have been able to obtain 

financing for large amounts of generation capacity, including from renewables. EIA data 

shows that, in 2019, approximately 44% of all energy produced by natural gas-fired 

generation in the United States was generated by independently owned capacity.548 

Furthermore, EIA data demonstrates that net generation of energy by non-utility owned 

renewable resources in the United States grew by almost 700% between 2005 and 2018, 

which speaks to the reality that renewable resources are able to acquire financing even 

without the right to require long-term fixed energy rates.

549 Based on this data, we find 

that the right to require counterparties to pay fixed energy rates is not essential for the 

financing of independent power generation capacity.

547 See NOPR, 168 FERC ¶ 61,184 at P 76.

548 EIA, Electric Power Monthly with Data for December 2018, at tbl. 1.7.B

(February 2020), https://www.eia.gov/electricity/monthly/archive/february2020.pdf).

549 Id. P 74 (explaining that net generation of energy by non-utility owned 

renewable resourcesin the United States escalated from 51.7 TWh in 2005 when EPAct 

2005 was passed, to 340 TWh in 2018) (citing EIA, Electricity Data Browser,

www.eia.gov/electricity/data/browser).
Docket Nos. RM19-15-000 and AD16-16-000 - 196 -

341. We acknowledge that a number of different financing mechanisms were used for 

this independent power generation capacity, not all of which will be available to QFs. 

Nevertheless, we understand that a standard rate structure employed in the electric 

industry is a fixed capacity rate-variable energy rate structure, and that many independent 

power production facilities have been financed based on this structure.550 Accordingly, 

record evidence and historical data regarding the financing and construction of significant 

amounts of independent power production facilities supports the Commission’s 

conclusion that a fixed capacity rate-variable energy rate structure—which will apply in 

those states choosing the variable avoided cost energy rate option—also will support 

financing of QFs.

342. For the reasons described below, we do not find compelling the concerns expressed 

by some commenters that a fixed capacity rate-variable energy rate construct may not 

work for solar and wind resources, which have high fixed capacity costs and minimal 

variable energy costs.551 Similarly, we are not persuaded by comments that point out that 

550 American Public Power Association, How New Generation is Funded (Aug. 29, 

2018), https://www.publicpower.org/blog/how-new-generation-funded (“Beginning in 

2015, merchant generation [in RTOs/ISOs markets] began to increase dramatically from 

prior years, amounting to 19.3 percent of new capacity in 2015, 7.2 percent in 2016, and 

29.1 percent in 2017.”). In RTOs and ISOs with capacity markets, merchant generators 

are compensated through variable energy rates and fixed capacity rates, along with 

whatever ancillary service revenues they can earn. 

551 See Harvard Electricity Law Comments at 26; Public Interest Organizations 

Comments at 33-34; Solar Energy Industries Comments at 30.
Docket Nos. RM19-15-000 and AD16-16-000 - 197 -

energy rates in typical independent power production contracts are designed to recover the 

cost of a facility’s fuel, whereas variable energy rates would provide no such guarantee.552 

343. As an initial matter, as we have noted, the record demonstrates that the amount of 

renewable resources being developed outside of PURPA greatly exceeds the amount of

renewable resources developed as QFs.553 Renewable resources developed outside of 

PURPA may not have a legal right to long-term contracts with fixed energy rates, yet 

nevertheless have been able to obtain financing.

344. The Commission also disagrees with those commenters who assert that, as a 

consequence of the above factors, the Commission should “require[] the variable energy 

component to be structured in a way that removes market risk from the QF.”554 This 

argument runs directly counter to one of the fundamental premises of PURPA, which is 

that QFs must accept the market risk associated with their projects by being paid no more 

than the purchasing utility’s avoided cost, thereby preventing utility retail customers from 

subsidizing QFs.555 PURPA does not allow the Commission to require QFs to be paid 

rates above avoided costs in order to make certain types of QF technologies financeable. 

If a state determines that it is necessary to require variable avoided cost energy rates in 

552 NIPPC, CREA, REC, and OSEIA Comments at 42-43.

553 See supra P 240.

554 NIPPC, CREA, REC, and OSEIA Comments at 43.

555 See Conf. Rep. at 97-98 (stating that the “risk in proceeding forward in the [QF] 

enterprise is not guaranteed to be recoverable”); accord API, 461 U.S. at 416 (holding that 

QFs “would retain an incentive to produce energy under the full-avoided-cost rule so long 

as their marginal costs did not exceed the full avoided cost of the purchasing utility”).
Docket Nos. RM19-15-000 and AD16-16-000 - 198 -

order to avoid paying QFs an above-avoided cost rate, which is a bedrock requirement of 

PURPA, then the impact this may have on facilities not financeable with a fixed capacity 

rate-variable energy rate contract structure is a direct result of the requirements of PURPA

itself.

556 Concerns regarding the alleged mismatch between avoided costs and the costs of 

renewable technologies therefore are collateral attacks on the requirements of PURPA 

itself, not our proposed implementation of it. 

345. In the NOPR, the Commission noted the availability of various hedging devices 

that would allow QFs to fix or limit the variability of a variable avoided cost energy 

rate.557 We acknowledge those comments explaining that hedging tools increase project 

expense and may not be available to all QFs.558 However, the Commission never intended 

to suggest that hedging is cost-free or that it would be appropriate for all QFs. The 

commenters all agree that hedging is available for at least some QFs.559 For such QFs, 

hedging can help provide energy rate certainty if such certainty is required for financing. 

556 See Connecticut Authority Comments at 14 (“[C]ontracted QF rates that take 

into account New England market conditions would not deter lenders and investors. 

Many QFs have no fuel costs and low variable costs of production; therefore, it is 

reasonable to find that these QFs would earn substantial inframarginal rents on energy 

sales. Further, QFs may be able to sell RECs and/or participate in other Connecticut 

programs.”).

557 NOPR, 168 FERC ¶ 61,184 at P 72.

558 NIPPC, CREA, REC, and OSEIA Comments at 45-46; Resources for the Future 

Comments at 6-7; Solar Energy Industries Comments at 30.

559 Id.
Docket Nos. RM19-15-000 and AD16-16-000 - 199 -

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.

346. Public Interest Organizations cite testimony from the Technical Conference stating 

that Southern Company has negotiated non-QF renewable contracts with fixed energy 

rates rather than variable energy rates.560 However, that testimony does not support the 

contention that the Commission must provide for fixed avoided cost energy rates for QF 

contracts and other LEOs. As the cited testimony notes, Southern agreed to contracts with 

longer terms and with fixed energy rates only because the renewable energy developers 

agreed to a rate that was 50 to 60 percent of the projected long-term avoided cost.561

347. Certain commenters expressed concern that, when a purchasing electric utility is 

not avoiding the construction or purchase of capacity as a consequence of entering into a 

contract with a QF, under the NOPR’s proposed rules a state could limit the QF’s contract 

rate to variable energy payments.

562 However, in that event, the only costs being avoided 

by the purchasing electric utility would be the incremental costs of purchasing or 

560 Public Interest Organizations Comments at 33-34 (citing NOPR, 168 FERC 

¶ 61,184 at P 70 n.114 (citing Tech. Conference, Docket No. AD16-16-000, Tr. 200 (filed 

June 30))).

561 Tech. Conference, Docket No. AD16-16-000, Tr. at 200 (filed June 30). The 

Commission notes that the PURPA Regulations specifically permit QFs and utilities to 

agree to rates that differ from what the PURPA Regulations require. 18 CFR 292.301(b). 

As the testimony cited by the Public Interest Organizations suggests, QFs that believe 

fixed energy avoided cost rates are required to obtain financing are free to offer rate and/or 

other contractual concessions in exchange for a fixed rate.

562 CARE Comments at 4 n.7; EPSA Comments at 12. 
Docket Nos. RM19-15-000 and AD16-16-000 - 200 -

producing energy at the time the energy is delivered.563 Nothing in PURPA or the 

legislative history of PURPA suggests that the Commission should set QF rates so as to 

facilitate the financing of new QF capacity in locations where no new capacity is needed.

348. In the NOPR, the Commission also observed that the variable avoided cost energy 

rate proposal might cause states to make other changes to their administration of PURPA 

in ways that would improve the financeability of QF projects. Most notably, states that 

had limited the length of contract terms because of concerns about overpayments for 

energy might be willing to allow longer term contracts if the contracts have variable 

avoided cost energy rates. Longer term contracts with fixed avoided cost capacity rates, in 

turn, would provide greater revenue assurance to QFs.564 The comments submitted in 

response to the NOPR support our analysis. 

563 See, e.g., City of Ketchikan, 94 FERC ¶ 61,293, at 62,061 (2001) (“[A]voided 

cost rates need not include the cost for capacity in the event that the utility’s demand (or 

need) for capacity is zero. That is, when the demand for capacity is zero, the cost for 

capacity may also be zero.”).

564 NOPR, 168 FERC ¶ 61,184 at P 65. Contrary to assertions by some 

commenters, the Commission’s conclusion in the NOPR about the possible positive 

effects of the variable avoided cost energy rate proposal was not based on speculation. See 

Public Interest Organizations Comments at 36. Rather, the Commission relied on 

testimony presented at the Technical Conference. See Technical Conference Tr. at 142-43 

(Idaho Commission) (“No matter the starting point, allowing QFs to fix their avoided cost 

rates for long terms results in rates which will eventually exceed and overestimate avoided 

cost rates into the future. The longer the term, the greater the disparity. . . . [The Idaho 

Commission] recently reduced PURPA contract lengths to two years in order to correct 

the disparity. We didn’t reduce contract lengths to kill PURPA. We did it to allow 

periodic adjustment of avoided cost rates.”).
Docket Nos. RM19-15-000 and AD16-16-000 - 201 -

349. Further, there is some evidence that variable avoided cost energy rates in contracts 

and LEOs could result in longer-term contracts.565 To be clear, we are not finding that the 

variable avoided cost energy rate provision in this final rule will necessarily lead to longer 

term contracts and LEOs in every state, nor does our decision to adopt this provision rely 

on such a finding.566 However, the record supports the conclusion that the variable 

avoided cost energy rate provision could lead to longer term contracts in at least some 

states, and that likelihood provides support for the conclusion that QFs will be able to 

obtain financing for their projects under this provision if their costs are indeed below the 

purchasing utility’s avoided costs.

h. Other Claimed Benefits of Fixed Avoided Cost Energy 

Rates

i. Comments

350. Public Interest Organizations assert that maintaining the requirement to pay QFs 

fixed rates serves as a hedge for consumers because QFs, unlike utilities, bear their own 

risks and have provided “billions of dollars” in benefits to consumers. Public Interest 

Organizations assert that eliminating QFs’ rights to fixed rate contracts ignores these 

565 Idaho Commission Comments at 4 (allowing states to set variable QF energy 

avoided costs “would allow states to consider longer term contracts without putting 

ratepayers at risk”) (citing NOPR, 168 FERC ¶ 61,184 at 5 n.5).

566 We are not finding that variable avoided cost energy rates would be appropriate 

only if they cause states to require longer term contracts, and we are not adopting the 

suggestion made by certain commenters that the Commission order states to require longer

contract terms. See NIPPC, CREA, REC, and OSEIA Comments at 47-48; Public Interest 

Organizations Comments at 6-7; sPower Comments at 11.
Docket Nos. RM19-15-000 and AD16-16-000 - 202 -

benefits to consumers and puts them at risk.567 Likewise, Solar Energy Industries portrays 

a fixed energy rate as providing a hedge to a utility that the purchasing electric utility may 

use as a revenue stream in connected markets. Solar Energy Industries nevertheless 

argues that, in order to encourage QF development, the Commission must ensure that QFs 

know the energy price at the time of contracting and that utilities publish rates stating the 

energy, capacity, and environmental attributes of the QF rate.

568

ii. Commission Determination

351. Fixed and variable energy rates each can provide benefits to electric utility 

customers. These benefits are the converse of each other: variable avoided cost energy 

rates provide protection to customers when energy costs decline, and fixed avoided cost 

energy rates provide protection to customers when energy costs increase. By giving the 

states the flexibility to choose either variable or fixed avoided cost energy rates in QF 

contracts and LEOs, the Commission is giving each state the ability to choose the 

protection that is best suited for electric customers in their state, based on each state’s 

567 Public Interest Organizations Comments at 45-46 (citing S. Rep. No. 95-442, at 

9, 22-23, 33 (1977), as reprinted in 1978 U.S.C.C.A.N. 7903, 7906, 7919-21, 7930; 

Public Interest Organizations, Comments, Docket No. AD16-16-000, at 5, 19-21 (Oct. 17, 

2018)). In earlier comments in Docket No. AD16-16-000, cited by Public Interest 

Organizations in response to the NOPR, Public Interest Organizations asserted that longterm fixed QF contracts often act as a hedge that lowers QF financing expenses, which 

benefits ratepayers, and insulates ratepayers from fuel price fluctuations. Public Interest 

Organizations, Comments, Docket No. AD16-16-000, at 20-21 (Oct. 17, 2018).

568 Solar Energy Industries Comments at 31-32.
Docket Nos. RM19-15-000 and AD16-16-000 - 203 -

view of what the future may hold and the likelihood that variable energy avoided costs 

will exceed fixed energy avoided costs during the life of a QF contract or LEO. 

352. We acknowledge that fixed avoided energy cost rates can serve as a hedge against 

future fuel price increases in a way that protects ratepayers, assuming such price increases 

actually occur. Given that PURPA both places an avoided cost cap on QF rates, and 

requires that such rates must be just and reasonable to the electric consumers of the 

electric utility, we find it is appropriate to provide flexibility to states to decide how to 

apportion such risks to their ratepayers in a way that ensures QF avoided energy cost rates 

are consistent with PURPA’s requirements (i.e., by using either fixed or variable avoided 

cost energy rates to best meet those requirements).

353. We caution, though, that having made that choice, a state is not free to toggle a 

QF’s contractual rate structure back and forth unilaterally from one to the other as 

circumstances change; QFs are entitled to the certainty that once a state has made its 

choice with respect to a particular QF’s contract or LEO, that QF’s contract or LEO is not 

subject to change during the term of that contract or LEO except by mutual consent.

i. Potential Modifications to NOPR Proposal

i. Comments

354. The California Commission, Connecticut Authority, and Massachusetts DPU 

support the variable energy rate proposal and suggest that, in addition, states be given the 

discretion to require the avoided capacity rate to vary.569

569 California Commission Comments at 27-28; Connecticut Authority Comments 
Docket Nos. RM19-15-000 and AD16-16-000 - 204 -

355. In contrast, NIPPC, CREA, REC, and OSEIA urge the Commission, if it allows 

variable energy rates, to adopt strict parameters for setting capacity rates in order to 

provide some predictability to QFs to allow them to obtain financing. NIPPC, CREA, 

REC, and OSEIA recommend that the Commission require forecasted capacity rates be 

“offered in a long-term contract of at least 20 years after commencement of sales under 

the agreement” for “[a]ll years during the term of the QF’s long-term contract after which 

the utility forecasted to be capacity deficit in its load and resource balance, as forecasted 

in its resource plan in effect at the time of the legally enforceable obligation” and “[a]ny 

time the utility is planning or undertaking actions to acquire a major generation resource 

or a major capital investment at an aging facility at the time of creation of the legally 

enforceable obligation.”570

356. Commissioner O’Donnell urges the Commission to provide additional guidance to 

states on the minimum required contract duration that would enable a QF to obtain 

financing from investors while providing sufficient ratepayer protections.571

ii. Commission Determination

357. We decline to adopt the California Commission’s, Connecticut Authority’s, and 

Massachusetts DPU’s requests to permit a state to require variable avoided cost capacity 

rates in addition to variable avoided cost energy rates. There is a fundamental difference 

at 14-15; Massachusetts DPU Comments at 8-10.

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

571 Commissioner O’Donnell Comments at 3.
Docket Nos. RM19-15-000 and AD16-16-000 - 205 -

between avoided energy costs and avoided capacity costs. Unlike avoided energy costs, 

which fluctuate with changes in the variable cost of the purchasing utility’s marginal 

energy resource, a purchasing utility’s avoided capacity cost is determined at the time the 

utility incurs the obligation to purchase capacity from a QF rather than self-build a 

capacity resource or enter into a power purchase agreement with a third party. Although a 

purchasing utility’s avoided capacity cost may later change as additional capacity 

acquisitions are avoided, the cost of the capacity avoided by the purchasing utility as a 

consequence of purchasing capacity from a particular QF at a particular moment in time

does not change. 

358. As a simple illustrative example, if a utility is able to avoid constructing a new 

generation facility with a capacity cost of $10/MW-month as a result of purchasing power 

from a QF, its avoided capacity cost is the $10/MW-month capacity cost that it would 

have been incurred to construct the new facility. Once the utility commences its 

purchases from the QF, it may not need additional capacity, and its avoided capacity cost 

for the next QF would drop to $0/MW-month. It would not be appropriate to then reduce 

the original QF’s avoided capacity charge to $0/MW-month, however, because the only 

reason that the utility does not need additional capacity is because it already purchased 

capacity from the original QF in order to avoid the $10/MW-month capacity cost. That is, 

without the purchase from the original QF, the utility would have incurred a capacity cost 

of $10/MW-month, and that is the utility’s avoided capacity cost for the term of its 

contract with the original QF. It would be inappropriate, in other words, for avoided cost 
Docket Nos. RM19-15-000 and AD16-16-000 - 206 -

capacity rates to change after they are first set at the time a LEO (such as a contract) is 

established.

359. We also decline to adopt the suggestion of NIPPC, CREA, REC, and OSEIA to

adopt additional criteria for establishing avoided capacity costs, including minimum 

contract lengths. We believe that the existing rate-setting provisions adequately set out 

the criteria that should be considered by a state in determining avoided capacity costs.572 

To the extent that any party believes a state has not appropriately applied these criteria, 

that party has recourse to the enforcement provisions of PURPA sections 210(g) and 

(h).

573

360. We decline to specify a minimum required contract length given that it is up to 

states to decide appropriate contract lengths in a way that accurately calculates avoided 

costs so as to meet all statutory requirements.

8. Consideration of Competitive Solicitations to Determine Avoided 

Costs 

a. NOPR Proposal

361. The Commission in the NOPR proposed to revise the PURPA Regulations in 18 

CFR 292.304 to add subsection (b)(8). In combination with new subsection (e)(1), this 

subsection would permit a state the flexibility to set avoided cost energy and/or capacity 

572 See 18 CFR 292.304(e).

573 See also Policy Statement Regarding the Commission's Enforcement Role Under 

Section 210 of the Public Utility Regulatory Policies Act of 1978, 23 FERC ¶ 61,304.
Docket Nos. RM19-15-000 and AD16-16-000 - 207 -

rates using competitive solicitations (i.e., requests for proposals or RFPs), conducted 

pursuant to appropriate procedures.

362. The Commission recognized that one way to enable the industry to move toward 

more competitive QF pricing is to allow states to establish QF avoided cost rates through a 

competitive solicitation process. The Commission previously has explored this issue. In 

1988, the Commission issued a notice of proposed rulemaking proposing to adopt 

regulations that would allow bidding procedures to be used in establishing rates for 

purchases from QFs.574 That rulemaking proceeding, along with several related 

proceedings, ultimately was withdrawn as overtaken by events in the industry.575 

363. Since then, the Commission held in a 2014 order addressing the specific facts of the 

particular competitive solicitation at issue that an electric utility’s obligation to purchase 

power from a QF under a LEO could not be curtailed based on a failure of the QF to win 

an only occasionally-held competitive solicitation.

576 In a separate proceeding involving a 

574 Regulations Governing Bidding Programs, FERC Stats. & Regs. ¶ 

32,455 (1988) (cross-referenced at 42 FERC ¶ 61,323) (Bidding NOPR); see also 

Administrative Determination of Full Avoided Costs, Sales of Power to Qualifying 

Facilities, and Interconnection Facilities, FERC Stats. & Regs. ¶ 32,457 (1988) (crossreferenced at 42 FERC ¶ 61,324) (ADFAC NOPR).

575 See Regulations Governing Bidding Programs, 64 FERC ¶ 61,364 at 63,491-92 

(1993) (terminating Bidding NOPR proceeding); see also Administrative Determination of 

Full Avoided Costs, Sales of Power to Qualifying Facilities, and Interconnection 

Facilities, 84 FERC ¶ 61,265 (1998) (terminating ADFAC NOPR proceeding).

576 See, e.g., Hydrodynamics, Inc., 146 FERC ¶ 61,193, at PP 31-35 (2014) 

(Hydrodynamics). 

Competitive solicitation processes have been used more recently in a number of 

states, including Georgia, North Carolina, and Colorado. Georgia’s competitive 
Docket Nos. RM19-15-000 and AD16-16-000 - 208 -

different competitive solicitation, the Commission declined to initiate an enforcement 

action where the state competitive solicitation was an alternative to a PURPA program.577

364. Given this precedent, the Commission proposed to amend its regulations to clarify 

that a state could establish QF avoided cost rates through an appropriate competitive 

solicitation process. Consistent with its general approach of giving states flexibility in the 

manner in which they determine avoided costs, the Commission did not propose in the

NOPR to prescribe detailed criteria governing the use of competitive solicitations as tools 

to determine rates to be paid to QFs, as well as to determine other contract terms. The 

Commission stated that states arguably may be in the best position to consider their 

particular local circumstances, including questions of need, resulting economic impacts, 

amounts to be purchased through auctions, and related issues. 

365. Nevertheless, in considering what constitutes proper design and administration of a

competitive solicitation, the Commission found it was appropriate to establish certain 

minimum criteria governing the process by which competitive solicitations are to be 

conducted in order for a competitive solicitation to be used to set QF rates. In that regard, 

the Commission noted that it has addressed competitive solicitations in prior orders in a 

solicitation process is described at Ga. Comp. R. & Regs. 515-3-4.04(3) (2018). North 

Carolina’s competitive solicitation process is described at 4 N.C. Admin. Code 11.R8-71 

(2018). Colorado’s competitive solicitation process is described at sPower Development 

Co., LLC v. Colorado Pub. Utils. Comm’n, 2018 WL 1014142 (D. Colo. Feb. 22, 2018). 

577 Winding Creek Solar LLC, 151 FERC ¶ 61,103, reconsideration denied, 153 

FERC ¶ 61,027 (2015). But see Winding Creek Solar LLC v. Peterman, 932 F.3d 861 (9th

Cir. 2019).
Docket Nos. RM19-15-000 and AD16-16-000 - 209 -

number of contexts that provide potential guidance to states and others. For example, the 

Commission’s policy for the establishment of negotiated rates for merchant transmission 

projects,578 the Bidding NOPR, and the Hydrodynamics case579 all suggest factors that 

could be considered in establishing an appropriate competitive solicitation that is 

conducted in a transparent and non-discriminatory manner. 

366. These factors, as proposed in the NOPR, include, among others: (a) an open and 

transparent process; (b) solicitations should be open to all sources to satisfy the purchasing 

electric utility’s capacity needs, taking into account the required operating characteristics 

of the needed capacity;580 (c) solicitations conducted at regular intervals; (d) oversight by

an independent administrator; and (e) certification as fulfilling the above criteria by the 

state regulatory authority or nonregulated electric utility. The Commission proposed that 

a state may use a competitive solicitation to set avoided cost energy and capacity rates,

578 Allocation of Capacity on New Merchant Transmission Projects and New CostBased, Participant-Funded Transmission Projects, 142 FERC ¶ 61,038 (2013).

579 See Hydrodynamics, 146 FERC ¶ 61,193 at P 32 n.70 (citing Bidding NOPR, 

FERC Stats. & Regs. ¶ 32,455 at 32,030-42). The Commission notes that, while QFs not 

awarded a contract pursuant to an competitive solicitation would retain their existing 

PURPA right to sell energy as available to the electric utility, if the state has concluded 

that such QF capacity puts tendered after an competitive solicitation was held are “not 

needed,” the capacity rate may be zero because an electric utility is not required to pay a 

capacity rate for such puts if they are not needed. See Hydrodynamics, 146 FERC 

¶ 61,193 at P 35 (referencing City of Ketchikan, 94 FERC ¶ 61,293 at 62,061 (“[A]voided 

cost rates need not include the cost for capacity in the event that the utility’s demand (or 

need) for capacity is zero. That is, when the demand for capacity is zero, the cost for 

capacity may also be zero.”)).

580 See 18 CFR 292.304(e); Windham Solar, 157 FERC ¶ 61,134 at PP 5-6.
Docket Nos. RM19-15-000 and AD16-16-000 - 210 -

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). 

367. In addition, the Commission sought comment on whether it should provide further 

guidance on whether, and under what circumstances, a competitive solicitation can be 

used as a utility’s exclusive vehicle for acquiring QF capacity.

581

b. Comments

i. Comments in Opposition

368. Several commenters oppose the NOPR proposal to allow states the ability to set 

avoided cost energy and capacity rates through a competitive solicitation such as an 

RFP.582

369. Allco states that allowing a state commission to use a competitive solicitation price 

is simply giving another tool to a state commission to eliminate QF projects.583 Allco also 

contends that this proposal creates an apples and oranges scenario where a competitive 

581 The Commission proposed that, even if a competitive solicitation were used as 

an exclusive vehicle for an electric utility to obtain QF capacity, QFs that do not receive 

an award in the competitive solicitation would be entitled to sell energy to the electric 

utility at an as-available avoided cost energy rate. 

582 Allco Comments at 12; Blue Earth Comments at 1-2; Boulder Comments at 6; 

CA Cogeneration Comments at 10-11; Green Power Comments at 1-3; Industrial Energy 

Consumers Comments at 13.

583 Allco Comments at 12.
Docket Nos. RM19-15-000 and AD16-16-000 - 211 -

solicitation could be won by solar projects of 80 MWs at a low, steeply discounted price 

that may never get built, resulting in a state commission publishing that as an avoided cost 

for a 1 MW solar project connected to the distribution system.584 Allco points to 

California’s Renewable Marketing Adjustment Tariff program as an example of a 

competitive solicitation price failure.585

370. CA Cogeneration states that relying on a competitive solicitation violates PURPA’s 

mandatory purchase obligation, and the regulations must always preserve the right of a QF 

to negotiate a contract for the purchase of its output at an avoided cost rate.586 CA 

Cogeneration states that reliance on a competitive solicitation also fails to provide the 

necessary financial and operational encouragement for combined heat and power.587

371. Covanta asserts that the Commission’s proposed competitive solicitation process 

would disadvantage technologies like Waste to Energy that are not growing, or are closing 

facilities.588

372. Southeast Public Interest Organizations argue that, in the states that currently 

require some form of competitive solicitation, many utilities do not regularly hold 

competitive solicitations, do not make competitive solicitations open to all QFs, or do not 

584 Id.

585 Id.

586 CA Cogeneration Comments at 10.

587 Id. at 11.

588 Covanta Comments at 9.
Docket Nos. RM19-15-000 and AD16-16-000 - 212 -

provide QFs the ability to sell to the utility outside of a competitive solicitation process.589 

Southeast Public Interest Organizations maintain that the competitive solicitation process 

can be overly burdensome and costly for smaller facilities. Southeast Public Interest 

Organizations assert that no state requires, and no utility conducts, a competitive 

solicitation to determine how best to meet the ongoing energy needs that it currently meets 

through the operation of its existing generation fleet and market purchases.590 In 

particular, Southeast Public Interest Organizations represent that: (1) Florida does not

require an independent evaluator as part of its competitive solicitation process; (2)

Colorado and Oklahoma allow utilities to apply for waivers of the competitive solicitation 

requirement; and (3) North Carolina allows the incumbent utility to participate in the 

competitive bidding process and to receive preferential treatment in the form of waiving 

post bid security required for any independently owned projects.591 Southeast Public 

Interest Organizations conclude that, while a well-designed and well-implemented 

competitive solicitation process could be an appropriate procurement and rate-setting tool 

in some cases, competitive solicitations should never be the only way to set rates or for 

QFs to sell their output, and close consideration should be given to determinations of 

589 Southeast Public Interest Organizations Comments at 26.

590 Id. at 26-27.

591 Id. at 27.
Docket Nos. RM19-15-000 and AD16-16-000 - 213 -

utility capacity needs that could be manipulated to limit renewable energy 

procurements.592

373. Mr. Mattson states that precedent and legislative intent remove competitive 

solicitations from being a PPA option.593 Both Mr. Mattson and Two Dot Wind point to 

the Commission’s ruling in Hydrodynamics that “requiring a QF to win a competitive 

solicitation as a condition to obtaining a long-term contract imposes an unreasonable 

obstacle to obtaining a legally enforceable obligation.”594 Two Dot Wind also states that 

competitive solicitations have not worked in Montana, and that the NOPR’s suggestion 

that competitive bidding can replace PURPA is not supported by the factual record in 

Montana.595

374. Industrial Energy Consumers expresses concern that the parameters for competitive 

solicitations are not sufficiently developed to ensure a well-structured, fairly administered, 

transparent, and non-discriminatory process for procurement, and therefore opposes 

allowing a competitive solicitation process to determine avoided costs at this time.596

592 Id. at 25-26.

593 Mr. Mattson Comments at 23.

594 Id.; Two Dot Wind Comments at 10 (citing Hydrodynamics, 146 FERC 

¶ 61,193).

595 Two Dot Wind Comments at 9-10.

596 Industrial Energy Consumers Comments at 13.
Docket Nos. RM19-15-000 and AD16-16-000 - 214 -

ii. Comments in Support

375. Several commenters support the NOPR proposal to allow states the ability to set 

energy and capacity rates through a competitive solicitation such as an RFP.597

376. Multiple commenters, including EEI, NRECA, and the Oregon Commission, 

support the notion that the states are in the best position to tailor the competitive 

solicitation process to their needs, and that the Commission should not provide detailed 

criteria governing the use of competitive solicitations.598 EEI states that the fact that 

competitive solicitations may be used to set avoided costs is an idea nearly as old as 

PURPA.599 EEI also supports the Commission’s proposal for a state to allow a 

competitive solicitation to be used as the exclusive vehicle for acquiring QF capacity.600 

NRECA notes that numerous NRECA members have already had success using 

competitive solicitations to establish both energy and capacity rates in states where 

competitive solicitations are permitted.601

377. Growth and Opportunity Center states that competitive solicitation processes, in 

place of avoided cost calculations, provide better signals to investors of where their 

597 Alaska Power Comments at 1; Distributed Sun Comments at 2; EEI Comments 

at 32-33; El Paso Electric Comments at 4; NARUC Comments at 3; NRECA Comments at 

11; South Dakota Commission Comments at 2-3.

598 EEI Comments at 32-33; NRECA Comments at 11; Oregon Commission 

Comments at 3-4.

599 EEI Comments at 32.

600 Id. at 33.

601 NRECA Comments at 11.
Docket Nos. RM19-15-000 and AD16-16-000 - 215 -

electricity is most valuable because competitive solicitations reflect more informed 

estimates of the real-time needs of electricity consumers. Growth and Opportunity Center 

contends that the proposed rule changes, by giving states more latitude to use competitive 

solicitations in complying with PURPA, should result in prices for consumers that more 

accurately reflect market costs for electricity.602 Growth and Opportunity Center also 

asserts that in states using competitive solicitation processes, nondiscrimination rules 

should be enforced to ensure that solicitations are competitive and that no providers 

receive preferential treatment.603

378. The Michigan Commission states that it recently approved using competitive 

solicitations to determine avoided capacity costs for a large electric utility in Michigan.604

The Michigan Commission states that it believes that that recently approved structure 

aligns with the Commission’s proposal in the NOPR.

605

379. Portland General asserts that, because the output of an competitive solicitation

represents a resource’s true market costs, a competitive solicitation is the correct method 

to determine avoided cost.606 Portland General states that, given the competitive nature of 

competitive solicitations, bidders are highly motivated, which results in the procurement 

602 Growth and Opportunity Center Comments at 9. 

603 Id. at 10.

604 Michigan Commission Comments at 4.

605 Id. at 5.

606 Portland General Comments at 11.
Docket Nos. RM19-15-000 and AD16-16-000 - 216 -

of resources with high benefit-to-cost ratios. Portland General cites as an example its 

recent competitive solicitation, which resulted in a $40.70-levelized price and reflects a 

combination of technologies (wind, solar, and battery), whereas QFs, which Portland 

General asserts provide lower capacity, are currently offered at a $45.19 levelized price 

for solar energy.607

380. Xcel urges the Commission’s to give the states the option of procuring all needed 

capacity through competitive bidding processes.608 Xcel strongly believes that states must 

have the ability to control capacity additions to ensure that customer needs and state 

policy goals are met.609 Xcel explains that in many states, including some in which the 

Xcel operating companies operate, resource procurement is accomplished largely through 

state-administered IRP processes, which are utilized to ensure a resource mix that meets 

the overall public interest in affordable and clean energy. Xcel states that these carefully 

calibrated processes can be upset when QFs bring capacity on to a utility’s system that 

does not align with the state’s vision of its optimal resource mix and when those QFs also 

attempt to collect above-market payments from utilities and therefore customers. Xcel 

states that Colorado’s procurement efforts have been so successful that in 2016 more than 

400 bids for 238 distinct projects were submitted for Public Service Company of Colorado 

alone, and that this process resulted in some of the lowest prices for renewables seen as of 

607 Id.

608 Xcel Comments at 10.

609 Id. at 8.
Docket Nos. RM19-15-000 and AD16-16-000 - 217 -

that date, with a median wind price of $19.30/MWh and a median solar price of 

$30.96/MWh. Xcel argues that unsolicited puts by QFs, in contrast, can impede the 

ability of states to meet their resource planning goals and can undermine the competitive 

markets that states like Colorado have already created or are striving to create.610

381. North Carolina Commission Staff states that North Carolina has implemented a 

competitive solicitation process for solar energy that complements the PURPA reforms 

adopted by the state, with the first solicitation concluding in April 2019.611 North 

Carolina Commission Staff states that an independent administrator estimated the initial 

nominal savings for the competitive solicitation with a 20-year contract versus traditional 

avoided cost pricing to exceed $370 million for the utilities involved.612

382. Duke Energy shares its state-specific experience with North Carolina’s competitive 

solicitation for renewable energy as a positive example.613 Duke Energy states that Duke 

Energy Carolinas, LLC and Duke Energy Progress, LLC recently completed their Tranche 

1 Competitive Procurement of Renewable Energy RFP and procured approximately 550 

MW of new solar capacity for 20-year fixed price contract terms at a projected savings of 

610 Id. at 9. 

611 North Carolina Commission Staff Comments at 3-4.

612 Id. at 4.

613 Duke Energy Comments at 10-12.
Docket Nos. RM19-15-000 and AD16-16-000 - 218 -

approximately $261 million relative to administratively determined forecasts of avoided 

costs over this same period.614

iii. Comments Requesting Modifications/Clarifications

(a) Requests for Clarification and/or Separate 

Proceedings

383. NIPPC, CREA, REC, and OSEIA argue that the NOPR fails to explain (1) whether 

the Commission is proposing to merely clarify that a state could use the lowest offer 

prices submitted in a competitive solicitation to set the avoided costs of energy and 

capacity on a prospective basis for any QF seeking a contract until the next competitive 

solicitation, or (2) whether the Commission is proposing a radical change in its precedent 

by revising its rules to provide that a QF may only sell under a long-term contract if that 

QF wins a competitive solicitation, which NIPPC, CREA, REC, and OSEIA assert would 

be contrary to the Hydrodynamics615 and Winding Creek616 cases.617

384. NIPPC, CREA, REC, and OSEIA request that any requirement to win a 

competitive solicitation to obtain a long-term PURPA contract should exempt small 

facilities.618 NIPPC, CREA, REC, and OSEIA further state that the Commission should:

(1) require that the competitive solicitation include no utility-ownership options; or (2) if 

614 Id. at 12.

615 Hydrodynamics, 146 FERC ¶ 61,193.

616 Winding Creek Solar LLC v. Peterman, 932 F.3d 861.

617 NIPPC, CREA, REC, and OSEIA Comments at 62-63.

618 Id. at 67.
Docket Nos. RM19-15-000 and AD16-16-000 - 219 -

utility-owned generation may result, the competitive solicitation must be: (i) administered 

and scored (not just overseen) by a qualified independent party, not the utility; (ii) any 

utility or utility-affiliate ownership bid must be capped at its bid price and not allowed 

traditional cost-plus ratemaking treatment; and (iii) the product sought, minimum bidding 

criteria, and detailed scoring criteria must be made known to all parties at the same 

time.619 Additionally, NIPPC, CREA, REC, and OSEIA contend that an option for longterm contracts should remain available for both small QFs and existing QFs outside of a

competitive solicitation.

620

385. The Michigan Commission states that it would welcome guidance on whether, and 

under what circumstances, a competitive solicitation can be used as a utility’s exclusive 

vehicle for acquiring QF capacity.621 Similarly, the Montana Commission recommends 

that the Commission provide as much guidance to states as possible regarding the 

requirements for transparency and non-discrimination.622

386. The California Commission states that the NOPR does not provide states any more 

flexibility than they already have, and the Commission’s final order adopting revised 

regulations should clearly state this.623

619 Id.

620 Id. at 67-68.

621 Michigan Commission Comments at 5.

622 Montana Commission Comments at 3.

623 California Commission Comments at 23.
Docket Nos. RM19-15-000 and AD16-16-000 - 220 -

387. Several commenters suggest that the Commission should conduct focused 

additional processes on this topic.624 Advanced Energy Economy suggests that the 

Commission conduct one or more workshops or technical conferences, to explore in detail 

the specific factors that would make a utility competitive solicitation process a truly 

competitive process of a “comparative quality” to competitive wholesale energy and 

capacity markets.625 Advanced Energy Economy contends that such workshops or 

technical conferences could ultimately be the basis for developing proposed regulations 

better guiding the states and electric utilities in implementing open and competitive 

solicitation processes to obtain relief from the mandatory purchase obligation under 

PURPA section 210(m)(1)(C).626 Industrial Energy Consumers argues that, if the 

Commission seeks to allow states to rely on competitive solicitation processes, the 

Commission should undertake a separate inquiry, with necessary technical conferences, to 

develop specific parameters to govern such processes.627 If the Commission relies directly

on competitive solicitation processes in the final rule, Industrial Energy Consumers states 

that if, after undertaking the competitive solicitation, the utility rejects all offers and 

decides to self-build, then the all-inclusive price of the self-build option should at least

624 Advanced Energy Economy Comments at 13; EPSA Comments at 15-16; 

Industrial Energy Consumers Comments at 13-14.

625 Advanced Energy Economy Comments at 13.

626 Id.

627 Industrial Energy Consumers Comments at 13-14.
Docket Nos. RM19-15-000 and AD16-16-000 - 221 -

establish the avoided cost rate for QFs seeking to develop in that area.628 EPSA argues 

that the Commission should require further proceedings, including another technical 

conference, to discuss the protections that would be necessary in order to have a genuinely 

level playing field for competitive solicitations.629

388. Commissioner Slaughter states that PURPA sits at the intersection of competition 

and regulatory policy in an area of vital and urgent interest, and that the Commission

should establish fair, non-discriminatory guidelines for competitive solicitations that 

would help states and other stakeholders maximize the benefits of competition from lowcost energy sources, particularly utility-scale renewable energy facilities.630 

Commissioner Slaughter states that such guidelines could form the basis for transitioning 

many local markets from administratively determined prices to environments of dynamic 

price discovery in which the rapidly decreasing cost of utility-scale renewable energy can 

put maximum pressure on both new and pre-existing fossil fuel-based sources of 

electricity.631

389. EPSA states that the Commission should ensure that competitive solicitations are 

properly designed to ensure that QFs have meaningful opportunities to compete against 

628 Id. at 14.

629 EPSA Comments at 16.

630 Commissioner Slaughter Comments at 1-2.

631 Id. at 3.
Docket Nos. RM19-15-000 and AD16-16-000 - 222 -

resources owned by incumbent utilities on a level playing field.632 EPSA states that the 

Commission should use this opportunity to do a full assessment of how competitive 

solicitations are working and could be enhanced, while providing continued protections to 

prevent discrimination against QFs.633 EPSA also emphasizes that, regardless of whatever 

competitive solicitation rules the Commission ultimately adopts, the Commission must 

continue to exercise its “backstop” oversight and enforcement authority to ensure that any 

requirements are implemented in a consistent and appropriate manner by individual 

states.634

(b) Requests Regarding Proposed Criteria

390. Several commenters requested that the Commission clarify the criteria that 

solicitations be conducted at regular intervals.635 Several commenters request that the 

Commission reconsider or remove that criteria.636 sPower argues that the Commission 

should require that such competitive solicitations be conducted at a minimum every two 

years.637 Colorado Independent Energy asserts that competitive solicitations should be 

held at regular intervals to test the market, and that the Commission should consider the 

632 EPSA Comments at 3.

633 Id. at 14.

634 Id. at 16-17.

635 APPA Comments at 17-18; Basin Comments at 9; Montana Commission 

Comments at 3; sPower Comments at 9-10.

636 NorthWestern Comments at 7-8.

637 sPower Comments at 9-10.
Docket Nos. RM19-15-000 and AD16-16-000 - 223 -

entire market, not just projects 80 MW and under, in evaluating whether there are full and 

competitive opportunities.

638

391. Several commenters oppose the requirement for an independent administrator.639 

APPA argues that the entire PURPA administrative construct is designed to entrust to 

state regulatory authorities the responsibility to carry out the duties they are assigned 

under the Commission’s regulations.640 NRECA believes that states are in the best 

position to determine the need for “oversight by an independent administrator” and 

recommends this criterion be deleted.641 NRECA requests that, if the Commission retains 

the requirement that competitive solicitation processes include some type of oversight, 

instead of requiring oversight by an independent administrator, the Commission should 

allow states the flexibility to allow electric utilities to retain a third-party consultant for 

this purpose.642 NRECA contends that many cooperatives have long-standing 

relationships with third-party consultants that assist the cooperatives in evaluating power 

supply options, and requiring those cooperatives to now use some other entity (i.e., the 

638 Colorado Independent Energy Comments at 9-12.

639 APPA Comments at 18; NRECA Comments at 11.

640 APPA Comments at 18 (citing 16 U.S.C. 824a-3(f) (expressly calling for state 

regulatory authorities and nonregulated electric utilities to implement Commission-issued 

PURPA regulations)).

641 NRECA Comments at 11.

642 Id. at 12.
Docket Nos. RM19-15-000 and AD16-16-000 - 224 -

independent administrator) would be disruptive and costly.643 Colorado Independent 

Energy notes that, while independent evaluators are helpful, they are often employed by 

utilities and thus sometimes reluctant to offer third party criticism of the bid evaluation 

process.644

392. The Montana Commission requests clarification of the term “independent 

administrator” and “certified” as those terms are used in the proposed revisions to 

§ 292.304(b).645

393. sPower disagrees that a competitive solicitation should “take into account the 

required operating characteristics of the needed capacity” in order to produce accurate 

avoided cost rates and recommends that a final rule remove that language from condition 

(ii) in the Commission’s list of conditions that a competitive solicitation must meet.646

394. Colorado Independent Energy states that, in addition to the guidelines provided in 

the NOPR, the Commission should include additional guidelines, including that fairness 

of an “all-source” competitive solicitation must also be determined based on bid 

evaluation and not just on a competitive solicitation. Colorado Independent Energy 

asserts that competitive solicitation submissions can be technology-specific, but not the 

evaluation or the analysis of the need to be met by a competitive solicitation. Colorado 

643 Id.

644 Colorado Independent Energy Comments at 8.

645 Montana Commission Comments at 3.

646 sPower Comments at 8.
Docket Nos. RM19-15-000 and AD16-16-000 - 225 -

Independent Energy asserts that a true all-source selection process must allow resource 

planning models to optimize among all bids received without bias toward QF-eligible 

technologies such as renewable generation or cogeneration.647

395. Several commenters stated that competitive solicitations must be assessed using the 

criteria set forth in Allegheny.

648 EPSA further states that, while the Allegheny principles 

provide a good starting point, additional protections will be required to level the playing 

field between independent generators and utilities.649 R Street asserts that, if an auction 

can meet the Allegheny standard, then generators in that state would not be eligible for QF 

designations. R Street suggests that QFs should not be able to force their power on utilities 

if they lose such fairly administered auctions.

650 

396. Solar Energy Industries asserts that the Commission should require a purchasing 

electric utility to provide the state commission, and make available for public inspection, a 

post-solicitation report that: (1) identifies the winning bidders; (2) includes a copy of any 

reports issued by the independent evaluator; and (3) demonstrates that the solicitation 

program was implemented without undue preference for the interests of the purchasing 

utility or its affiliates. Solar Energy Industries further assert that the solicitation program 

647 Colorado Independent Energy at 2.

648 EPSA Comments at 14-15 (citing Allegheny, 108 FERC ¶ 61,082); R Street Comments 

at 3-4; Solar Energy Industries Supplemental Comments, Docket No. AD16-16-000, at 32-37

(filed Aug. 28, 2019).

649 EPSA Comments at 15.

650 R Street Comments at 3-4.
Docket Nos. RM19-15-000 and AD16-16-000 - 226 -

should include clear details regarding the manner in which the bids will be scored and 

clearly specify price and non-price criteria under which bids are evaluated including: (1) 

acceptable delivery points and any scoring deductions for delivery to other points; (2) 

credit evaluation criteria and development securing requirements; and (3) performance 

requirements.651

397. Public Interest Organizations argue that the Commission’s proposal does not 

require that state competitive solicitation procedures meet the statutory floor established 

through PURPA that rates both (1) encourage small power producers and (2) not 

discriminate relative to the utility’s own generation and other non-QF generators.652 To 

ensure competitive solicitations actually meet the statutory criteria, the Commission must 

ensure that competitive solicitations meet four minimum standards.653 First, Public 

Interest Organizations state that solicitations must account for utility-owned and non-QF 

generation and cannot be a limited competition between QFs without the ability to 

displace non-QF generation.654 As an example of an incorrectly-conducted, and 

unlawfully-discriminatory, bidding process, Public Interest Organizations cite the Nevada 

competitive solicitation process that is limited to QFs to meet a small, segregated portion 

651 Solar Energy Industries Supplemental Comments, Docket No. AD16-16-000, at

21 (filed August 28, 2019).

652 Public Interest Organizations Comments at 69-70.

653 Id. at 70.

654 Id.
Docket Nos. RM19-15-000 and AD16-16-000 - 227 -

of the utility’s energy and unmet capacity requirements.655 Second, to ensure that QFs 

receive the same price that other generation receives, Public Interest Organizations state 

that all sources of supply must compete in the competitive solicitation— including the 

utility’s own generation.656 Third, Public Interest Organizations state that the solicitation 

process cannot be used in any way to curtail or delay a utility’s obligation to purchase 

from QFs.657 Fourth, the “required operating characteristics of the needed capacity” factor 

suggested in the NOPR cannot be used as a surrogate to define characteristics of only nonQF generation or to allow a utility to pick among favored generators.658

398. Biogas states that, if QFs are to enter into competitive solicitations as a vehicle for 

PURPA, then there must be some correcting for the inequitable tax and regulatory 

provisions afforded to incumbent utilities and select renewable technologies, in order to 

ensure a fair market opportunity.659

399. American Dams requests that QFs competing against a utility that can rate base the 

cost of new generation should be entitled to similar valuation provided that QF costs are at 

or less than those of the utility.660

655 Id. at 71-72.

656 Id. at 72.

657 Id. at 72-73.

658 Id. at 73.

659 Biogas Comments at 2.

660 American Dams Comments at 3.
Docket Nos. RM19-15-000 and AD16-16-000 - 228 -

(c) Other Requests

400. In their comments to the NOPR, Solar Energy Industries reference their August 28, 

2019 comments in Docket No. AD16-16-000,

661 in which they describe the “SEIA 

Counterproposal.” That document proposes that, where a utility seeks to meet identified 

capacity needs through an open, fairly designed, and independently administered 

competitive solicitation: (i) the purchasing electric utility would only have to pay QFs for 

capacity to the extent that the purchasing electric utility failed to meet identified need 

through the competitive solicitation; and (ii) the QF would be paid for its output (energy 

and capacity) at the market rate established through the competitive solicitation process.662

401. Solar Energy Industries request that the Commission supplement proposed 18 CFR

292.304(b)(5) to require that: (1) participants are provided with complete and transparent 

information regarding transmission constraints, levels of congestion, and interconnections;

and (2) the solicitation is linked with the purchasing utility’s IRP and is conducted for the 

entirety of a utility’s anticipated capacity needs.663

402. Solar Energy Industries request that the Commission expressly implement 

safeguards to prevent utility self-dealing and affiliate abuse, with regard to both price and 

non-price terms.664 Solar Energy Industries reference their previous comments in this 

661 Solar Energy Industries Supplemental Comments, Docket No. AD16-16-000,

at 17-40 (filed Aug. 28, 2019).

662 Solar Energy Industries Comments at 38.

663 Id. at 39.

664 Id.
Docket Nos. RM19-15-000 and AD16-16-000 - 229 -

proceeding, which they state describe practices of PacifiCorp,665 NorthWestern,666

Duke,667 and Xcel668 purportedly showing that these utilities have attempted to reduce 

QFs’ ability to sell while simultaneously seeking to build and rate base their own 

substantial renewable resources.669

403. ELCON states that it continues to see shortcomings in competitive procurement 

practices across regions.670 A current example ELCON provides is Dominion Energy 

Virginia’s 2019 RFP which, ELCON argues, limited competition in a manner that all but 

guarantees that a Dominion self-build option will prevail because it restricts participation 

to new resources only and does not permit an independent third party to evaluate bids.671 

Another example ELCON provides is a recent Entergy Louisiana solicitation through 

which a natural gas generating facility was approved despite opposition from Louisiana 

industrial consumers who argued that the competitive solicitation was improperly 

designed to limit resource options to new construction comparable to a self-build.672

665 Solar Energy Industries Supplemental Comments, Docket No. AD16-16-000, at

25-28 (filed August 28, 2019).

666 Id. at 28-29.

667 Id. at 29-31.

668 Id. at 21.

669 Solar Energy Industries Comments at 40. 

670 ELCON Comments at 27.

671 Id.

672 Id. at 28.
Docket Nos. RM19-15-000 and AD16-16-000 - 230 -

404. ELCON asserts that, to be competitive, a competitive solicitation must be 

transparent, face independent oversight, have safeguards against affiliate abuse involving 

transactions between franchised utilities and their market-based affiliates, and have welldefined technical parameters.673 ELCON states that experiences with competitive 

solicitations thus far expose the challenges of achieving a workably competitive process. 

ELCON urges the Commission to set a high bar, with enforcement to verify that a process 

is sufficiently competitive.674

405. NorthWestern states that it supports the Commission’s proposal to use competitive 

solicitations or RFPs to establish avoided capacity costs, but not avoided energy costs, 

because NorthWestern believes that an energy-only competitive solicitation has no 

relation to the market whereas a capacity competitive solicitation does.675 NorthWestern 

believes that use of a competitive solicitation should be the preferred vehicle for setting 

avoided capacity rates for QFs because this will ensure that the capacity is acquired at the 

least cost thereby benefiting customers.676

406. Institute for Energy Research states that it would go even further than the NOPR 

proposal and require that competitive solicitations be the default whenever possible, with 

states having to justify case-by-case why a non-competitive solicitation is needed, because 

673 Id. at 28-29.

674 Id.

675 NorthWestern Comments at 7.

676 Id.
Docket Nos. RM19-15-000 and AD16-16-000 - 231 -

solicitation is the best expression of the Congressional mandate to encourage 

competition.677

407. Harvard Electricity Law states that the NOPR’s proposed 18 CFR

292.304(b)(8)(ii), requiring solicitations must be open to “all sources”—could be read as 

inconsistent with the Commission’s CPUC orders678 and the 2019 CARE v. CPUC

decision.679 Harvard Electricity Law argues that, if the Commission amends its avoided 

cost rules to allow states to set avoided cost rates based on competitive solicitations, it 

should clarify that states may set tiered rates, as the Commission and the U.S. Court of 

Appeals for the Ninth Circuit has allowed in the above cases.680

408. The Oregon Commission recommends that the Commission emphasize the need for 

states to have adequate safeguards to protect bidders’ confidential and commercially 

sensitive proprietary information when using competitive solicitations to determine or 

inform avoided cost rates.681

677 Institute for Energy Research Comments at 1.

678 Cal. Pub. Utils. Comm’n, 133 FERC ¶ 61,059, clarification and reh’g denied, 

133 FERC ¶ 61,059 (2010), reh’g denied, 134 FERC ¶ 61,044 (2011) (CPUC) .

679 Californians for Renewable Energy v. Cal. Pub. Utils. Comm’n, 922 F.3d 929, 

937 (9th Cir. 2019) (CARE v. CPUC) (holding that “where a state has [a renewable 

portfolio standard (RPS)] and the utility is using a QF’s energy to meet the RPS, the utility 

cannot calculate avoided costs based on energy sources that would not also meet the 

RPS[,]” which “comports with PURPA’s goal to put QFs on an equal footing with other 

energy providers”).

680 Harvard Electricity Law Comments at 31.

681 Oregon Commission Comments at 4.
Docket Nos. RM19-15-000 and AD16-16-000 - 232 -

409. sPower states that the issue of using a competitive solicitation process to establish 

avoided cost rates has sometimes been conflated with using a competitive solicitation

process to establish a LEO, and sPower encourages the Commission to continue to 

analyze these distinct issues separately.682

410. Resources for the Future stresses that competitive solicitations alone would 

minimize QF costs but would not establish avoided cost rates, which depend on much 

more than the cost of QF generation.683 However, used in concert with forward curves, 

Resources for the Future states that competitive solicitations could provide an effective 

complementary method.684

c. Commission Determination

411. In this final rule, we affirm the NOPR proposal to revise the PURPA Regulations 

to explicitly permit a state the flexibility to set avoided energy and/or capacity rates using 

competitive solicitations (i.e., RFPs), conducted pursuant to appropriate procedures in a 

transparent and non-discriminatory manner. A primary feature of a transparent and nondiscriminatory competitive solicitation is that a utility’s capacity needs are open for 

bidding to all capacity providers, including QF and non-QF resources, on a level playing 

field. This level playing field ensures that any QF’s capacity rates that result from the 

competitive solicitation are just and reasonable and non-discriminatory avoided cost rates. 

682 sPower Comments at 3.

683 Resources for the Future Comments at 8-9.

684 Id. at 9.
Docket Nos. RM19-15-000 and AD16-16-000 - 233 -

412. Consistent with our general approach of giving states flexibility in the manner in 

which they determine avoided costs, we do not prescribe detailed criteria governing the 

use of competitive solicitations as tools to determine rates to be paid to QFs, as well as to 

determine other contract terms. States arguably are in the best position to consider their 

particular local circumstances, including questions of need, resulting economic impacts, 

amounts to be purchased through auctions, and related issues. 

413. In considering what constitutes proper design and administration of a competitive 

solicitation, however, we find it appropriate to establish certain minimum criteria 

governing the process by which competitive solicitations are to be conducted in order for 

an competitive solicitation to be used to set QF rates. These factors, which we proposed 

in the NOPR and adopt here, include, among others: (a) an open and transparent process; 

(b) solicitations should be open to all sources to satisfy that purchasing electric utility’s 

capacity needs, taking into account the required operating characteristics of the needed 

capacity; (c) solicitations conducted at regular intervals; (d) oversight by an independent 

administrator; and (e) certification as fulfilling the above criteria by the state regulatory 

authority or nonregulated electric utility. 

414. We affirm that such competitive solicitations must be conducted in a process 

that includes, but is not limited to, the factors identified above that will be set forth in 

18 CFR 292.304(b)(8). This rule does not undo any competitive solicitations conducted 

prior to the effective date of this final rule that may not have met these criteria. This rule 

applies only to competitive solicitations conducted after the effective date of the final rule. 
Docket Nos. RM19-15-000 and AD16-16-000 - 234 -

We also provide modifications and clarifications to the NOPR proposal, as described 

below.

i. Requests for Clarification and/or Separate 

Proceedings

415. As an initial matter, in the NOPR, the Commission addressed competitive 

solicitations in two related but distinct contexts. The first, to be discussed in this section, 

relates to the proposal to explicitly permit a state the flexibility to set avoided cost energy 

and/or capacity rates using competitive solicitations (i.e., RFPs), conducted pursuant to 

appropriate procedures. The second, to be discussed below, in section IV.G.2 of this final 

rule, concerns the NARUC proposal that urged the Commission to give meaning to 

PURPA section 210m(1)(C) by establishing a “yardstick” by which a vertically integrated 

utility outside of an RTO or ISO could apply to terminate the mandatory purchase 

obligation if it conducts sufficiently competitive RFPs for energy or capacity. 

416. More generally, we support the use of competitive solicitations as a means to foster 

competition in the procurement of generation and to encourage the development of QFs in 

a way that most accurately reflects a purchasing utility’s avoided costs. We believe that 

allowing QFs to compete to provide capacity and energy needs, through a properly 

administered competitive solicitation, may help ensure an accurate determination of the 

purchasing electric utility’s avoided cost, and therefore result in prices meeting the 

PURPA’s statutory requirements. We also believe that it is reasonable for states to choose 

to require QFs to be responsive to price signals as to where and when capacity is needed. 
Docket Nos. RM19-15-000 and AD16-16-000 - 235 -

We believe that a properly administered competitive solicitation can help provide such 

price signals.

417. Furthermore, we believe that competitive solicitations may be an especially 

appropriate tool for developing competition in the markets outside of RTOs and ISOs, 

where there are no organized competitive markets in place where QFs can make sales. 

418. We emphasize, however, that neither the Commission’s current regulations, nor 

those adopted in this final rule, require a state or a purchasing electric utility to use a 

competitive solicitation to determine avoided cost rates for QFs. Consistent with other 

changes in our regulations discussed above, we give states the flexibility to use a properly 

structured competitive solicitation for this purpose, but we do not mandate that they do so.

419. Furthermore, in light of the substantial experience the industry has with 

competitive solicitations within and outside of the PURPA context, and the voluminous 

comments the Commission has received regarding competitive solicitations, we find that 

there is not currently a need for a separate proceeding or additional procedures to address 

competitive solicitation issues, such as holding workshops or technical conferences. 

Should further procedures appear beneficial in light of actual competitive solicitation

experience under PURPA and the regulations adopted today, such a proceeding may be 

appropriate in the future.

ii. Proposed Criteria

420. We continue to find that competitive solicitations as discussed in this final rule may 

accurately reflect a purchasing electric utility’s avoided costs and ensure that the resulting 

rates for winners of such competitive solicitations are consistent with PURPA. A 
Docket Nos. RM19-15-000 and AD16-16-000 - 236 -

competitive solicitation may more accurately value QF capacity over time by subjecting it 

to competition with other sources. Such competitive solicitations may provide more 

certainty both to QFs regarding when and how often they will be eligible to compete and 

to purchasing utilities regarding how they may expect to fulfill their capacity needs. 

421. The Commission clarifies that, if a utility acquires all of its capacity through 

properly conducted competitive solicitations (using the factors described above), and does 

not add capacity through self-building and purchasing power from other sources outside of

such solicitations, the competitive solicitations could be the exclusive vehicle for the 

purchasing electric utility to pay avoided capacity costs from a QF. In this situation, using 

properly conducted competitive solicitations as the exclusive vehicle to determine the 

purchasing electric utility’s avoided cost capacity rates would allow QFs a chance to 

compete to provide the utility’s capacity needs on a level playing field with the utility. 

We clarify that it is up to the states to determine whether to require that a utility’s total 

planned self-build and power purchase options must compete in the competitive 

solicitations, and we will not direct such a requirement here. 

422. If a state decides to require utility self-build and power purchase options to 

participate in competitive solicitations, then a QF that does not obtain an award in a 

competitive solicitation would have no right to an avoided cost capacity rate more than 

zero because the utility’s full capacity needs would have been met by the competitive 

solicitation.

685 However, QFs would continue to have the right to put energy to the utility 

685 This would be consistent with City of Ketchikan, 94 FERC at 62,061

(“[A]voided cost rates need not include the cost for capacity in the event that the utility’s 
Docket Nos. RM19-15-000 and AD16-16-000 - 237 -

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.

423. If the state does not require utility self-build and purchase options to participate in 

competitive solicitations, then QFs that lose in a competitive solicitation still may have the 

right to avoided cost capacity rates more than zero if the state determines that the utility 

still has capacity needs after the competitive solicitation that otherwise could be met 

through the utility’s self-build or purchase options.

424. The Commission has held and we reaffirm here that, when capacity is not needed, 

the avoided capacity cost rate can be zero.686 Competitive solicitations conducted 

pursuant to the rules adopted in this final rule that are held whenever capacity is needed

provide QFs a level playing field on which to compete to sell capacity. This approach 

further shields purchasing electric utilities from situations like those explained by Xcel, 

where QFs could simply sit out the competitive solicitation process (or participate but not 

have their bids accepted), but then seek to sell capacity to the purchasing electric utility 

and to receive a separate higher administratively-determined avoided cost rate including 

an avoided cost capacity rate, and even potentially displace non-QF competitive 

demand (or need) for capacity is zero. That is, when the demand for capacity is zero, the 

cost for capacity may also be zero.”).

686 Id. at 62,061 (“[A]voided cost rates need not include the cost for capacity in the 

event that the utility’s demand (or need) for capacity is zero. That is, when the demand for 

capacity is zero, the cost for capacity may also be zero.”).
Docket Nos. RM19-15-000 and AD16-16-000 - 238 -

solicitation winners.687 This approach benefits ratepayers because allowing QFs to 

compete in properly conducted, competitive solicitations that are held whenever capacity 

is needed allows the purchasing utility to obtain needed capacity efficiently. To be clear, 

the competitive solicitation is not to be a means to determine a QF’s right to put asavailable energy to the utility. But the competitive solicitation can be the means to 

determine what, if any, rate the QF will be paid for capacity. 

425. Multiple commenters point out that using competitive solicitations could be a 

beneficial way to carry out the Congressional intent behind PURPA. However, many of 

these same commenters claim that the competitive solicitations carried out to date do not 

live up to this standard. In other words, commenters assert that the competitive 

solicitations conducted to date have often not been properly conducted and instead have 

been unfair. As described above, assertions about specific states’ competitive solicitation

processes include that:

- the competitive solicitations conducted in Florida are unfair because they do not 

require an Independent Evaluator as part of the competitive solicitation process;688

- the competitive solicitations conducted in Colorado and Oklahoma are unfair 

because purchasing electric utilities are allowed to apply for waivers of the 

competitive solicitation requirement;

689

687 See Xcel Comments at 2-3, 9-10.

688 Southeast Public Interest Organizations Comments at 27.

689 Id.
Docket Nos. RM19-15-000 and AD16-16-000 - 239 -

- the competitive solicitations conducted in North Carolina are unfair because the 

incumbent purchasing electric utility can receive preferential treatment in the form 

of waivers of the post bid security otherwise required for any independently owned 

projects;

690 and

- the competitive solicitations conducted in Nevada are unfair because the process is 

limited to QFs to meet a small, segregated portion of the utility’s energy and unmet 

capacity requirements.691 

426. Commenters also make assertions about unfair practices of purchasing electric 

utilities, including that the purchasing electric utilities have attempted to reduce QFs’

ability to sell while the purchasing electric utilities are simultaneously seeking to build 

and rate base their own substantial renewable resources.

427. The criteria proposed in the NOPR were aimed at ensuring that competitive 

solicitations are conducted fairly. In this final rule, the Commission finds that, in order to 

use the results of a competitive solicitation to set avoided cost rates, the competitive 

solicitation must be conducted in a transparent and non-discriminatory manner. Such a

competitive solicitation must be conducted in a process that includes, but is not limited to, 

the following factors: (i) the solicitation process is an open and transparent process that 

includes, but is not limited to, providing equally to all potential bidders substantial and 

meaningful information regarding transmission constraints, levels of congestion, and 

690 Id.

691 Public Interest Organizations Comments at 71-72.
Docket Nos. RM19-15-000 and AD16-16-000 - 240 -

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 postsolicitation report.

428. Without judging the competitive solicitations conducted to date, we find that 

henceforth any competitive solicitation that does not comply with these factors will be 

viewed as not transparent and discriminatory, and not a basis for either setting the avoided 

cost capacity rate that a QF may charge the purchasing electric utility or limiting which 

generators can receive a capacity rate. Phrased differently, we will presume that any 

future competitive solicitation that does not comply with the factors adopted in this final 

rule does not comply with the Commission’s regulations implementing PURPA. 

429. In addition, to further promote fairness, the Commission makes several 

clarifications, as described below.

430. We clarify that competitive solicitations must also be conducted in accordance with 

the Allegheny principles under which the Commission evaluates a competitive solicitation: 

(1) transparency, a requirement that the solicitation process be open and fair; 

(2) definition, a requirement that the product, or products, sought through the competitive 

solicitation be precisely defined; (3) evaluation, a requirement that the evaluation criteria 

be standardized and applied equally to all bids and bidders; and (4) oversight, a 
Docket Nos. RM19-15-000 and AD16-16-000 - 241 -

requirement that an independent third party design the solicitation, administer bidding, 

and evaluate bids prior to selection.

692 While the NOPR’s proposed guidelines for 

competitive solicitations were generally inclusive of the Allegheny principles, in order to 

more precisely define what is and what is not a properly conducted competitive 

solicitation that can be used to determine what generators will be entitled to an avoided 

cost capacity rate, and what that rate will be, we specifically clarify here that the 

Allegheny principles apply as well.

431. We also revise the proposed language in 18 CFR 292.304(d)(8)(i) to clarify that

participants must be provided with substantial and meaningful information regarding 

transmission constraints, levels of congestion, and interconnections, subject to appropriate 

confidentiality safeguards. We believe that it is important that all participants in the 

competitive solicitation have access to these data as a necessary predicate for a 

nondiscriminatory competitive solicitation process, and we find that requiring that this 

information be provided will help ensure that a competitive solicitation is open and 

transparent. We acknowledge the risk that competitive solicitation participants could use 

this information to gain a competitive advantage that could be used outside of the 

competitive solicitation, but find that this risk can be minimized through the use of nondisclosure agreements and placing reasonable limits on those persons permitted to review 

the information, just as is done in other Commission proceedings where this issue arises.

692 Allegheny, 108 FERC ¶ 61,082 at P 18.
Docket Nos. RM19-15-000 and AD16-16-000 - 242 -

432. We also clarify that the requirement that the competitive solicitation process be 

open and transparent includes that the electric utility provide the state commission, and 

make available for public inspection, a post-solicitation report that: (1) identifies the 

winning bidders; (2) includes a copy of any reports issued by the independent evaluator; 

and (3) demonstrates that the solicitation program was implemented without undue 

preference for the interests of the purchasing utility or its affiliates. We find this 

consistent with the requirement that competitive solicitations be open and transparent, to 

not only ensure that utilities are not discriminating against QFs, but also to help all 

stakeholders and the public at large better understand the utility’s competitive solicitation

processes and thus to be confident in the fairness of the process and of the results. 

433. Regarding the requirement that solicitations must be open to all sources to satisfy 

the purchasing electric utility’s capacity needs, taking into account the required operating 

characteristics of the needed capacity, we decline to remove the phrase “taking into 

account the operating characteristics of the needed capacity.” There may be times when a 

utility needs capacity with specific attributes, such as specific ramping capability, that 

cannot be filled by certain types of generators. However, we agree with Public Interest 

Organizations that this phrase may not be used to define characteristics of only non-QF 

generation or to allow a utility to select favored generators.693

434. We decline to be overly prescriptive as to what constitutes “regular intervals.” In 

general, utilities should be reviewing their capacity needs frequently, and the state or 

693 Public Interest Organizations Comments at 73.
Docket Nos. RM19-15-000 and AD16-16-000 - 243 -

nonregulated electric utility is in the best position to determine the frequency of that 

review. However, there may be times when a utility’s review of capacity needs reveals 

that no capacity is needed, and it would not make sense for a competitive solicitation to be 

mandated at such a time.

435. We similarly decline to be overly prescriptive as to what constitutes an 

“independent administrator.” Commenters argue on both sides whether the NOPR 

proposal goes too far or not far enough. On the one hand, NRECA argues that states are 

in the best position to determine the need for oversight by an independent administrator 

and recommends this criterion be deleted.694 On the other hand, Colorado Independent 

Energy notes that independent administrators are often employed by utilities and thus 

sometimes reluctant to offer third party criticism of the bid evaluation process.695 We 

clarify that the independent administrator, who is responsible for administering the 

competitive solicitation, must be an entity independent from the purchasing electric utility 

in order to help ensure fairness. Whether the entity is called an independent administrator 

or a third-party consultant, the substantive requirement of this factor is that the 

competitive solicitation not be administered by the purchasing electric utility itself or its 

694 NRECA Comments at 11. In this final rule, we note, for ease of readability we 

have used the word “state” to refer to both state regulatory authorities and to nonregulated 

electric utilities. Thus, in the context of nonregulated electric utilities in particular, to say 

that the “state” can fairly administer the competitive solicitation is to say that the 

nonregulated electric utility can, essentially, be both the purchasing electric utility and 

potentially the independent administrator of its own competitive solicitation. That is a 

result we cannot countenance. 

695 Colorado Independent Energy Comments at 8.
Docket Nos. RM19-15-000 and AD16-16-000 - 244 -

affiliates, but rather by a separate, unbiased, and unaffiliated entity not subject to being 

influenced by the purchasing utility. We recognize, however, that such an independent 

administrator will need to be selected and paid. Though we are not directing a process, we 

note that the selection and payment could be done under the auspices of a state regulatory 

authority or by mutual agreement between the utility and the competitive solicitation 

participants. 

436. In response to the Montana Commission’s request for clarification as to what 

“certified” means within the guideline that requires certification of the competitive 

solicitation by the state regulatory authority or nonregulated electric utility as fulfilling the 

above criteria, we clarify that, after a thorough review of the competitive solicitation

procedures used and the competitive solicitation results, certification of the competitive 

solicitation requires a written, formally-issued finding by the state that the competitive 

solicitation and its results comply with PURPA and this Commission’s PURPA

regulations – and must include the independent administrator’s report to the same effect. 

437. We decline at this time to add any additional requirements for competitive 

solicitations. We continue to believe that states may be in the best position to consider 

their particular local circumstances. We think that the guidelines adopted here, in 

conjunction with the Allegheny principles and other clarifications made here, provide an 

adequate framework for competitive solicitations to be conducted efficiently, transparently 

and in a nondiscriminatory manner.

438. We also clarify that, if a competitive solicitation is not conducted fairly and in 

accordance with the guidelines here, then an aggrieved entity may challenge the state’s 
Docket Nos. RM19-15-000 and AD16-16-000 - 245 -

competitive solicitation in the appropriate forum, which could include any one or more of 

the following: (1) initiating or participating in proceedings before the relevant state 

commission or governing body; (2) filing for judicial review of any state regulatory 

proceeding in state court (under PURPA section 210(g)); or, alternatively (3) filing a 

petition for enforcement against the state at the Commission and, if the Commission 

declines to act, later filing a petition against the state in U.S. district court (under PURPA 

section 210(h)(2)(B)).

iii. Other Requests

439. We decline to grant Solar Energy Industries request to require that solicitations be 

linked with the purchasing electric utility’s IRP. Where a state has an IRP,696 it may make 

sense to link the competitive solicitation processes with the IRP so that the competitive 

solicitation is conducted for the entirety of a utility’s anticipated capacity needs. On the 

other hand, IRPs may come in a variety of forms. For example, an IRP may merely be a 

general projection of short- and long-term load growth and potential resources to meet 

such growth, and each generation project may be subject to specific approval based on 

actual specific need. In order to provide states flexibility in conducting these processes, 

we will not require such links between competitive solicitations and IRPs, although such 

links certainly are permitted if a state deems it to be appropriate.

696 16 U.S.C. 2621(a), (d)(7) (requiring states to consider whether to employ 

integrated resource planning).
Docket Nos. RM19-15-000 and AD16-16-000 - 246 -

440. Regarding facilities not designed primarily to sell electricity to the purchasing 

electric utility, such as waste to power small power production facilities and cogeneration 

facilities, we find that an exemption from competitive solicitation processes is 

unnecessary. We do not exempt small power production facilities from the competitive 

solicitation process; we are not persuaded that such an exemption is appropriate given that 

exempting large classes of small power producers could frustrate the price discovery 

function of the competitive solicitation. A large number of exempted small facilities 

could disrupt the competitive solicitation process. We clarify, however, that QFs whose 

capacity is 100 kW or less already are entitled to standard rates regardless of whether they 

compete in a competitive solicitation and we do not change that regulation in this final 

rule.

697 Given that we view competitive solicitations as an important price discovery tool 

and that states already are required to establish standard rates for such entities, there is no 

need to determine prices for QFs at 100 kW or less through a competitive solicitation.

441. The Commission clarifies that any competitive solicitation conducted may not 

force alteration of existing QF contracts. A QF receiving a capacity payment is entitled to 

that payment for the duration of the term of its contract, and a competitive solicitation is 

necessarily forward looking based on the results of that auction.

697 See 18 CFR 292.304(c).
Docket Nos. RM19-15-000 and AD16-16-000 - 247 -

C. Relief from Purchase Obligation in Competitive Retail Markets

1. NOPR Proposal

442. The Commission in the NOPR proposed to add regulatory text at the end of 

§ 292.303(a) of the PURPA Regulations to provide that a utility’s purchase obligation 

may be reduced to the extent the purchasing electric utility’s supply obligation has been 

reduced by a state retail choice program. The Commission stated that it was reasonable 

for electric utilities’ PURPA capacity purchase obligations to be reduced to the extent 

retail choice reduces their supply obligations. To the extent Provider of Last Resort 

(POLR) supplies are obtained through solicitations having a particular contract term such 

as one year, the Commission proposed that the length of the utility’s PURPA purchase 

contract should match the term of the POLR supply solicitation contracts in order to more 

accurately reflect the utility’s avoided costs.

443. The Commission proposed, through this change, to provide that state regulatory 

authorities and nonregulated electric utilities have flexibility to respond to the possibility 

that, over time, a utility’s POLR supply obligation may decrease (or increase). The 

Commission intended that this proposal would apply prospectively from the effective date 

of a final rule and would not disturb contracts in effect at the time the utility’s supply 

obligation is reduced.

2. Comments

444. APPA, DTE Electric, EEI, Institute for Energy Research, NorthWestern, NRECA, 

Pennsylvania Commission, Portland General, and We Stand for Energy filed comments in 

support of the Commission’s proposal to provide that the purchase obligation may be 
Docket Nos. RM19-15-000 and AD16-16-000 - 248 -

reduced to the extent the purchasing electric utility’s supply obligation has been reduced 

by a state retail choice program.698

445. New England Small Hydro, NIPPC, CREA, REC, and OSEIA, and Public Interest 

Organizations filed opposing comments arguing that the Commission lacks the statutory 

authority to implement this proposal because the Commission lacks discretion to reduce 

an electric utility’s mandatory purchase obligation except through PURPA section 

210(m).699 New England Small Hydro claims that PURPA section 210(a) clearly states 

that electric utilities must purchase the electric energy from QFs, and that the Commission 

does not have the authority to deviate from the statute.700 NIPPC, CREA, REC, and 

OSEIA argues that the Commission’s existing regulations adequately address the concern 

at issue because any reduction in the long-term capacity needs of the utility due to retail 

access should be reflected in avoided capacity rates offered to QFs.701 Public Interest 

Organizations claim that the Commission proposes to remove state authority by requiring 

QF contracts with a POLR to match the term of the POLR’s other supply contracts.702 

698 APPA Comments at 20; DTE Electric Comments at 4-5; EEI Comments at 41-

42; Institute for Energy Research Comments at 1-2; NorthWestern Comments at 8; 

NRECA Comments at 13-14; Pennsylvania Commission Comments at 6-7; Portland 

General Comments at 12-13; and We Stand Comments at 1.

699 New England Small Hydro Comments at 15-16; NIPPC, CREA, REC, and 

OSEIA Comments at 68-69; and Public Interest Organizations Comments at 74-75.

700 New England Small Hydro at 16 (citing Chevron U.S.A., Inc. v. Nat. Res. Def. 

Council, 467 U.S. 837 (1984)).

701 NIPPC, CREA, REC, and OSEIA Comments at 69.

702 Public Interest Organizations Comments at 74.
Docket Nos. RM19-15-000 and AD16-16-000 - 249 -

Public Interest Organizations also state that even if the Commission had such authority, 

there is no evidence in the record to support matching QF contract lengths with a POLR’s 

other supply contracts. Public Interest Organizations also assert that the Commission’s 

proposal unlawfully discriminates against QFs to the extent that it fails to treat QF 

contracts in parity with any of a POLR’s other supply contracts.703

446. Biogas and Covanta argue that the rationale for this proposal is unclear and that the 

NOPR fails to justify the reduction of a utility’s obligation to purchase QF power based on 

the amount of any non-utility generator’s supply into the utility’s service territory.704 

Covanta states that the NOPR incorrectly concludes that all public power is renewable 

power.705 Biogas and Covanta assert that the existence of a competitive retail market does 

not mean there is a competitive retail market for biogas or waste-to-energy QFs.706 

Biogas and Covanta also argue that the NOPR would reduce that already limited market 

by providing greater leverage to the purchasing electric utility, and urge the Commission 

to remove barriers to local government options for energy purchase rates.

447. Ohio Commission Energy Advocate states that under Ohio law, an electric 

distribution utility is required to provide consumers within its certified territory a standard 

service offer of all competitive retail electric services necessary to maintain essential 

703 Id. at 75.

704 Biogas Comments at 2; Covanta Comments at 9.

705 Covanta Comments at 9.

706 Biogas Comments at 2; Covanta Comments at 9-10.
Docket Nos. RM19-15-000 and AD16-16-000 - 250 -

electric services to customers, including a firm supply of electric generation services.707 

Ohio Commission Energy Advocate claims that all PUCO-regulated electric distribution 

utilities satisfy this obligation through competitive solicitation for default service within 

the context of an electric security plan.708 Ohio Commission Energy Advocate believes 

that the electric distribution utility should retain the full purchase obligation because the 

regulated utility maintains the obligation to serve as the POLR for all “wires-connected” 

customers.709 Ohio Commission Energy Advocate also states that it is concerned by the 

lack of alternatives to the mandatory purchase obligation and would question any 

interpretation of PURPA that contemplates a scenario where no entity has a purchase 

obligation for a QF.710

448. ELCON, California Utilities, Chamber of Commerce, Connecticut Authority, and 

Michigan Commission request further clarification on how the Commission’s proposal 

will be implemented. ELCON states that industrial customers conditionally support the 

reduction in obligation to purchase based on a state retail choice program, subject to the 

development of clear and enforceable criteria that exclude mandatory purchase obligation 

relief for default supply obligations that utilities meet with their own generation.711 

707 Ohio Commission Energy Advocate Comments at 5.

708 Id. at 6.

709 Id. at 6-7.

710 Id.

711 ELCON Comments at 19.
Docket Nos. RM19-15-000 and AD16-16-000 - 251 -

Similarly, California Utilities state that because of the various ways states have developed 

restructured retail markets, the Commission should provide additional guidance as to the 

various ways that state commissions can address load reductions due to retail choice while 

protecting legacy utilities.712 California Utilities explain that they need Commission 

guidance to ensure that cost recovery for past and future mandated QF purchases is 

equitable to the remaining retail customers in the legacy utilities’ distribution service areas 

and that future PURPA mandates or costs are fairly allocated consistent with costcausation principles.713 Chamber of Commerce states that the Commission should clarify 

that the reduction in a utility’s QF purchase obligation is measured against the amount of a 

utility’s load that has elected an alternative supplier, as opposed to eligible load.714 

Chamber of Commerce claims that in certain states, only a portion of an electric utility’s 

load is eligible to select an alternative electricity supplier and that such percentage would 

serve as the limit for any corresponding reduction in a utility’s QF purchase obligation. 

Michigan Commission states that its retail choice program caps retail choice at 10 percent 

of an electric utility’s retail customer demand, and seeks clarification on (1) whether the 

reduction in a utility’s purchase obligation would equal the reduction in its supply 

obligation, be based on the percentage of its customer demand participating in the state’s 

712 California Utilities Comments at 5.

713 Id. at 7.

714 Chamber of Commerce Comments at 5.
Docket Nos. RM19-15-000 and AD16-16-000 - 252 -

retail choice program, or some other metric; and (2) how fluctuations in the state’s retail 

choice program and resulting purchase obligation should be addressed.715

449. Connecticut Authority supports the proposal to modify distribution utilities’ mustpurchase obligations.716 Connecticut Authority states that since Connecticut’s electric 

industry restructuring, distribution utilities’ purchases of QF output have not been used to 

serve retail customers, rather the distribution utility acts as an intermediary selling output 

into the New England markets. Connecticut Authority asserts that the Commission should 

clarify that the state regulatory authority is responsible for determining the appropriate 

adjustment to the distribution utility’s must-purchase obligation and providing notice of 

such determination to the Commission.717

450. Connecticut Authority claims that QF output is different from, and cannot be 

substituted in for, distribution utility-provided default standard or last resort services. 

Connecticut Authority explains that standard service is procured in six-month tranches, 

last resort service is procured in three-month tranches, and that distribution utilities do not 

self-manage their default service supply portfolios.718

451. Connecticut Authority states that while it agrees that matching the contract terms 

for default service supply and QF supply could potentially reduce the burden of over715 Michigan Commission Comments at 5-6.

716 Connecticut Authority Comments at 16.

717 Id. at 17.

718 Id.
Docket Nos. RM19-15-000 and AD16-16-000 - 253 -

estimated avoided costs and give states flexibility to respond quickly to changes to a 

distribution utility’s default supply obligation, the Commission should not mandate any 

term length for the mandatory purchase obligation.719 Instead, Connecticut Authority 

asserts that the Commission should allow the state to establish the term based on statespecific circumstances.

452. California Utilities request that the Commission reaffirm that all alternative retail 

suppliers, including Electric Service Providers (ESP) and Community Choice Aggregators 

(CCA), are electric utilities subject to the PURPA purchase obligation.720 California 

Utilities explain that ESPs and CCAs are the two types of entities that California allows to 

sell power to retail customers in the distribution service territories of CPUC-regulated 

utilities, and argues that such entities meet the definition of electric utility used in 

PURPA.721

453. California Utilities state that the Commission should clarify that a state has no 

authority to exempt any traditional or alternative retail supplier from the PURPA 

mandatory purchase obligation in order to ensure QFs that there is a robust market to sell 

their energy and capacity to entities that actually serve load in the event a legacy utility is 

relieved of all or part of its PURPA obligations.722 California Utilities also state that the 

719 Id. at 18.

720 California Utilities at 9.

721 Id. at 9-10.

722 Id. at 11.
Docket Nos. RM19-15-000 and AD16-16-000 - 254 -

Commission should clarify that alternative retail suppliers must make avoided cost 

information publicly available to allow QFs to locate and identify potential buyers that 

may have higher avoided costs than legacy utilities that have lost load and may no longer 

have capacity needs.

454. California Utilities argue that for states such as California that allow alternative 

retail suppliers to opt out of procuring capacity and require legacy utilities to provide 

capacity on their behalf, it would be unfair for legacy utilities to pay a QF any amount for 

energy greater than the LMP unless the price differential for which the legacy utility can 

sell the energy in the market is paid for by the alternative retail supplier that was short on 

capacity.723 California Utilities explain that this would prevent cost shifts to customers 

who remain with the legacy utility such that all costs associated with the mandatory 

PURPA purchases made by the legacy utility on behalf of the alternative retail supplier 

would be borne by customers of the alternative retail supplier.724 California Utilities also 

argue that the Commission should clarify that if legacy utilities are required to procure 

capacity from QFs on behalf of alternative retail suppliers, states must require alternative 

retail suppliers to pay for such QF purchases at the avoided cost rate set by the state for 

the legacy utility for capacity.

455. California Utilities urge the Commission to adopt a stranded cost regulation 

addressing PURPA obligations incurred by legacy utilities that lose load to retail 

723 Id. at 12.

724 Id. at 13.
Docket Nos. RM19-15-000 and AD16-16-000 - 255 -

competition consistent with the cost recovery guarantee in PURPA section 

210(m)(7)(A).725 California Utilities argue that such regulation should be clear that 

prudently incurred costs include any costs associated with a purchase under a statemandated contract. California Utilities propose new language to § 292.304(g) regarding 

implementation of the cost recovery mandate in section 210(m)(7)(A) of PURPA stating, 

in part, that “[a] state commission may not find any costs associated with any legally 

enforceable obligation that it has imposed on an electric utility imprudent.”726

3. Commission Determination

456. In this final rule, we decline to adopt the proposed regulation permitting states with 

retail competition to allow relief from the purchase obligation. We instead clarify that the 

Commission’s existing PURPA Regulations already require that states, to the extent 

practicable, must account for reduced loads in setting QF rates.

457. Specifically, 18 CFR 292.304(e)(3) already does and will continue to allow states,

when setting avoided cost rates, to take into account “the ability of the electric utility to 

avoid costs, including the deferral of capacity additions.” We regard this existing 

regulation as allowing a state to consider reductions in a purchasing electric utility’s 

supply obligations given retail competition and the purchasing electric utility’s POLR 

obligations under state law. We further clarify that this clarification is not intended to be 

reflected as a MW-for-MW reduction (or increase) based on yearly changes in load and 

725 Id. at 14.

726 Id. at 15.
Docket Nos. RM19-15-000 and AD16-16-000 - 256 -

therefore does not and may not serve to terminate a purchasing utility’s mandatory 

purchase obligation under PURPA section 210(a).

727

D. Evaluation of Whether QFs are at Separate Sites

1. Rebuttable Presumption of Separate Sites

a. NOPR Proposal

458. The Commission proposed to allow entities challenging a QF certification to rebut 

the presumption that affiliated facilities located more than one mile apart are considered to 

be separate QFs. The Commission proposed that this change would be effective as of the 

date of the final rule, which means that such challenges could only be made to QF 

certifications and recertifications that are submitted after the effective date of the final rule

in this proceeding.

459. The Commission proposed that an entity can seek to rebut the presumption only for 

those facilities that are located more than one mile apart and less than 10 miles apart. The 

Commission believed that, just as there are some facilities that may be so close that it is 

reasonable to irrebuttably treat them as a single facility (those a mile or less apart), so 

there are some facilities that are sufficiently far apart that it is reasonable to treat them as 

irrebuttably separate facilities.728 That latter distance, the Commission believed, is 10

miles or more apart. Thus, if two affiliated facilities are one mile or less apart, they would

727 18 CFR 292.304(e)(3).

728 NOPR, 168 FERC ¶ 61,184 at P 101. As discussed in detail in section IV.D.1.d

below, this final rule will change the references to “separate facilities” or “the same 

facility” to “at separate sites” or “at the same site.”
Docket Nos. RM19-15-000 and AD16-16-000 - 257 -

continue to be irrebuttably presumed to be a single facility at a single site. If affiliated 

facilities are 10 miles or more apart, they would be irrebuttably presumed to be separate 

facilities at separate sites. 

460. The Commission proposed that if affiliated facilities are more than one mile apart 

and less than 10 miles apart, there would still be a presumption, but it would be a 

rebuttable presumption, that they are separate facilities at separate sites. Purchasing 

electric utilities and others thus would be able to file a protest attempting to rebut the 

presumption for facilities more than one mile apart and less than 10 miles apart and argue 

that they should be treated as a single facility. The Commission could also act sua sponte. 

The Commission proposed that self-certifications will remain effective after a protest has 

been filed, until such time as the Commission issues an order revoking the certification.

461. The Commission proposed allowing an entity seeking QF status to provide further 

information in its certification (both self-certification and application for Commission 

certification), to preemptively defend against rebuttal by asserting factors that 

affirmatively show that the affiliated facilities are indeed separate facilities at separate 

sites.729 Anyone challenging the QF certification would be allowed to assert factors to 

show that the facilities are actually part of the same, single facility.

729 While a QF with a net power production capacity of 1 MW or less is not 

required to formally certify its QF status (either through a self-certification or application 

for Commission certification), if the QF’s status is later challenged (i.e., by a petition for 

declaratory order), the QF would be able to respond by affirmatively demonstrating that 

its facilities are not located at the same site as other affiliated facilities and thus that the 

QF does not exceed the 80 MW size limitation.
Docket Nos. RM19-15-000 and AD16-16-000 - 258 -

462. The Commission proposed limiting protests challenging QF status by requiring any 

entity filing a protest to specify facts that make a prima facie demonstration that the 

facility described in the self-certification, self-recertification, or Commission certification 

does not satisfy the requirements for QF status. General allegations or unsupported 

assertions would not be a basis for denial of certification. The Commission further 

proposed limiting protests to QF status by requiring that once the Commission has 

affirmatively certified an applicant’s QF status through either a Commission certification 

proceeding or in response to protests challenging QF status, any later protest to a QF’s 

existing certification asserting that facilities further than one mile apart are part of a single 

QF must demonstrate changed circumstances that call into question the continued validity 

of the earlier certification. 

463. The Commission proposed that physical and ownership factors may be asserted to 

rebut or defend against rebuttal. Noting that no single factor would be dispositive, the 

Commission proposed the following factors: (1) physical characteristics including such 

common characteristics as: infrastructure, property ownership, interconnection 

agreements, control facilities, access and easements, interconnection facilities up to the 

point of interconnection to the distribution or transmission system, collector systems or 

facilities, points of interconnection, motive force or fuel source, off-take arrangements, 

property leases, and connections to the electrical grid; and (2) ownership/other 

characteristics, including such characteristics as whether the facilities in question are: 

owned or controlled by the same person(s) or affiliated persons(s), operated and 

maintained by the same or affiliated entity(ies), selling to the same electric utility, using 
Docket Nos. RM19-15-000 and AD16-16-000 - 259 -

common debt or equity financing, constructed by the same entity within 12 months, 

managing a power sales agreement executed within 12 months of a similar and affiliated 

facility in the same location, placed into service within 12 months of an affiliated project’s 

commercial operation date as specified in the power sales agreement, or sharing 

engineering or procurement contracts. The Commission solicited comments on whether 

the Commission should rely on some or any of these factors, or other factors, or whether 

the various factors should be considered together and weighed.

464. The Commission stated that it will continue to rely on its definition of “affiliate” 

provided in 18 CFR 35.36(a)(9), and noted that subsection (iii) provides that the 

Commission may determine, after appropriate notice and opportunity for hearing, that a 

person stands in such relation to a specified company that there is likely to be an absence 

of arm’s-length bargaining in transactions between them as to make it necessary or 

appropriate in the public interest or for the protection of investors or consumers that the 

person be treated as an affiliate.730 The Commission intended, when applying its rules on 

separate facilities, to consider this provision of its regulations, when entities otherwise 

would not be deemed affiliates under the other provisions of the definition, to determine 

whether a person nevertheless should be treated as an affiliate. In doing so, the 

Commission stated that it could take into consideration many of the same factors that 

would reasonably be considered in evaluating whether facilities located over one and less 

than 10 miles apart are a single facility or separate facilities. 

730 18 CFR 35.36(a)(9)(iii). 
Docket Nos. RM19-15-000 and AD16-16-000 - 260 -

465. The Commission believed that this change, together with the proposed definition of 

“electrical generating equipment” and revision to the FERC Form No. 556, would more 

closely align with Congress’s requirement that QFs seeking to certify as small power 

production facilities are in fact below the 80 MW statutory limit for such facilities.731

b. Commission Determination

466. As further discussed and revised in the following sections, we adopt the NOPR 

proposal. Henceforth, if a small power production facility seeking QF status is located 

one mile or less from any affiliated small power production QFs that use the same energy 

resource, it will be irrebuttably presumed to be at the same site as those affiliated small 

power production QFs. If a small power production facility seeking QF status is located 

ten miles or more from any affiliated small power production QFs that use the same 

energy resource, it will be irrebuttably presumed to be at a separate site from those

affiliated small power production QFs. If a small power production facility seeking QF 

status is located more than one mile but less than ten miles from any affiliated small 

power production QFs that use the same energy resource, it will be rebuttably presumed to 

be at a separate site from those affiliated small power production QFs. 

467. We adopt the proposal to allow a small power production facility seeking QF status 

to provide further information in its certification (both self-certification and application 

731 See 16 USC 796(17)(A)(ii) (defining small power production facility as, inter 

alia, “a facility which is an eligible solar, wind, waste, or geothermal facility, or a facility 

which—. . . has a power production capacity which, together with any other facilities 

located at the same site (as determined by the Commission), is not greater than 80 

megawatts”).
Docket Nos. RM19-15-000 and AD16-16-000 - 261 -

for Commission certification) or recertification (both self-certification and application for

Commission recertification), to preemptively defend against anticipated challenges by 

identifying factors that affirmatively show that its facility is indeed at a separate site from 

affiliated small power production QFs that use the same energy resource and that are 

more than one but less than 10 miles from its facility. We will correspondingly allow any 

interested person or entity to challenge a QF certification (both self-certification and 

application for Commission certification) or recertification (both self-recertification or 

application for Commission recertification) that makes substantive changes to the existing 

certification as further described below).

732

468. As explained in section IV.D.1.f below, we adopt the NOPR’s proposed factors, 

with certain additions. 

469. We adopt the proposal to clarify that challenges to QF status require that the 

interested person or entity filing a protest must specify facts that make a prima facie 

demonstration that the facility described in the certification (both self-certification and 

application for Commission certification) or recertification (both self-recertification and 

application for Commission recertification) does not satisfy the requirements for QF 

status. Additionally, any protest must be adequately supported, with supporting 

documents, contracts, or affidavits, as appropriate. General allegations or unsupported 

assertions will not provide a basis for denial of certification or recertification. We 

732 We note that a protester must separately file for intervention seeking to be made 

a party to the proceeding; the filing of a protest does not make that person or entity a 

party. 18 CFR 385.102(c), 385.211(a)(2).
Docket Nos. RM19-15-000 and AD16-16-000 - 262 -

additionally limit protests, as described more fully in section IV.E below, by clarifying 

that protests may be made to an initial certification (both self-certification and application 

for Commission certification) filed on or after the effective date of this final rule, but only 

to a recertification (both self-recertification and application for Commission 

recertification) filed on or after the effective date of this final rule that makes substantive 

changes to the existing certification. We adopt the proposal to limit protests by requiring 

that once the Commission has affirmatively certified an applicant’s QF status in response 

to a protest opposing a self-certification or self-recertification, or in response to an 

application for Commission certification or recertification, any later protest to a 

recertification (self-recertification or application for Commission recertification) making 

substantive changes to a QF’s existing certification must demonstrate changed

circumstances from the facts on which the Commission acted on the certification filing 

that call into question the continued validity of the earlier certification.733 Finally, the 

Commission retains the discretion to summarily reject protests where a protest reiterates

arguments already made against the same QF that the Commission previously denied or 

otherwise rejected.

733 An interested person or entity can choose to file a petition for declaratory order, 

with fee, at any time (that is, not only within 30 days from the date of the filing of the 

Form No. 556). However, if the Commission has affirmatively certified an applicant’s QF 

status in response to a protest opposing a self-certification or self-recertification, or in 

response to an application for Commission certification or recertification, any later 

petition for declaratory order protesting the QFs existing certification must demonstrate 

changed circumstances from the time the Commission acted on the certification that call 

into question the continued validity of the earlier certification.
Docket Nos. RM19-15-000 and AD16-16-000 - 263 -

c. Need for Reform

i. Comments

470. Multiple parties have expressed concern that some QF developers of small power 

production facilities are circumventing the one-mile rule, and thereby circumventing 

PURPA, by strategically siting small power production facilities that use the same energy 

resource slightly more than one mile apart in order to qualify as separate small power 

production facilities.734 Several commenters state that the NOPR-proposed changes will 

reduce the opportunity for gaming.735 

471. Several commenters argue, to the contrary, that there is no evidence of gaming of 

the current one-mile rule.736 Con Edison argues that utilities are not overwhelmed with 

QFs using the one-mile rule and there is little to no evidence to the contrary.737 sPower 

734 See APPA Comments at 21; Center for Growth and Opportunity Comments at 

5-6; Consumers Energy Comments at 4; East River Comments at 1-2; EEI Comments at 

43; ELCON Comments at 35; Governor of Idaho Comments at 1; Idaho Commission 

Comments at 5-7; Idaho Power Comments at 13; Missouri River Energy Comments at 5; 

Mr. Moore Comments at 2; Northern Laramie Range Alliance Comments at 2; 

NorthWestern Comments at 9; NRECA Comments at 14-15; Portland General Comments 

at 14.

735 APPA Comments at 21; Center for Growth and Opportunity Comments at 5-6; 

Consumers Energy Comments at 4; East River Comments at 1-2; EEI Comments at 43; 

ELCON Comments at 35; Governor of Idaho Comments at 1; Idaho Commission 

Comments at 5-7; Idaho Power Comments at 13; Missouri River Energy Comments at 5; 

Mr. Moore Comments at 2; Northern Laramie Range Alliance Comments at 2; 

NorthWestern Comments at 12; NRECA Comments at 14-15; Portland General

Comments at 14.

736 Solar Energy Industries Comments at 51; Southeast Public Interest 

Organizations Comments at 31; SC Solar Alliance Comments at 19.

737 Con Edison Comments at 5.
Docket Nos. RM19-15-000 and AD16-16-000 - 264 -

states that it is difficult to see how developers that comply with this clear bright-line rule 

could be said to be circumventing.738 New England Small Hydro argues that the 

Commission is attempting to address perceived abuses of the 80 MW limitation by 

burdening projects that do not abuse the system.739

ii. Commission Determination

472. The record shows that, since the establishment of the one-mile rule in the PURPA 

Regulations in 1980, the development of large numbers of affiliated renewable resource 

facilities, requires a revision of the one mile-rule. We find that the final rule will reduce 

the opportunity for developers of small power production facilities to circumvent the 

current one-mile rule by strategically siting small power production facilities that use the 

same energy resource slightly more than one mile apart.

740 While such circumvention

may not be an everyday occurrence, we agree with commenters that the record 

demonstrates it is still a sufficient possibility under the current regulations that the 

Commission is justified in addressing it in order to comply with the statute.

741 The final 

738 sPower Comments at 5.

739 New England Small Hydro Comments at 17.

740 The regulation, in practice, is only of consequence if the facilities located “at the 

same site” would exceed a power production capacity of 80 MW, as that is the size limit 

for a small power production facility to qualify as a QF. 16 U.S.C. 796(17)(A)(ii).

741 See APPA Comments at 21; Center for Growth and Opportunity Comments at 

5-6; Consumers Energy Comments at 4; East River Comments at 1-2; EEI Comments at 

43; ELCON Comments at 35; Governor of Idaho Comments at 1; Idaho Commission 

Comments at 5-7; Idaho Power Comments at 13; Missouri River Energy Comments at 5; 

Mr. Moore Comments at 2; Northern Laramie Range Alliance Comments at 2; 

NorthWestern Comments at 9; NRECA Comments at 14-15; Portland General Comments 
Docket Nos. RM19-15-000 and AD16-16-000 - 265 -

rule, as adopted, still retains the presumption that small power production QFs more than 

one mile apart are located at separate sites, but simply makes the presumption rebuttable 

for small power production QFs located more than one mile but less than 10 miles apart, 

allowing the Commission the ability to address those circumstances.

d. Site Definition

i. Comments

473. Solar Energy Industries state that, in El Dorado County Water Agency, the 

Commission found that “the critical test under PURPA relates to whether the facilities are 

located at one site rather than whether they are integrated as a project.”742 Solar Energy 

Industries argue that the proposed rule, as drafted, abandons the focus on whether the 

facilities are located at one site and transforms it into an analysis as to whether affiliated 

QFs are part of the same project. Solar Energy Industries similarly contend that it is 

arbitrary to change from a “same site” to an “integrated project” standard.743

474. NIPPC, CREA, REC, and OSEIA state that the existing rule is a reasonable means 

of implementing the statutory phrase “same site,” particularly given the statutory directive 

to encourage QF development, and state that they prefer the current bright line rule.744 

Allco argues that the proposed rule is divorced from the statutory use of “site.” Allco 

at 14.

742 Solar Energy Industries Comments at 60 (quoting El Dorado Cty. Water 

Agency, 24 FERC ¶ 61,280, at 61,578 (1983)).

743 Id. at 61-62.

744 NIPPC, CREA, REC, and OSEIA Comments at 70.
Docket Nos. RM19-15-000 and AD16-16-000 - 266 -

asserts that the Commission lacks authority to define the term “site” in a manner other 

than one reasonably related to its ordinary meaning and argues that the Commission’s 

definition of site arbitrarily limits QF development for no apparent reason.745 The DC 

Commission would like the Commission to leave the resolution of certain disputes over 

whether QFs are separate to state commissions.746 Idaho also requests that states be given 

as much discretion as possible.747

475. EEI states that the interpretation of “same site” is determined by the Commission, 

and that there is nothing in the statute that prevents the Commission from modifying its 

interpretation of the term “same site.”748

ii. Commission Determination

476. We modify the NOPR proposal to change terminology relating to the determination 

of whether small power production facilities are separate facilities to focus not on whether 

they are separate facilities, but rather to mirror the statutory language and thus focus on 

whether they are at “the same site.” In that regard, we change references to “separate 

facilities” or “the same facility” to “at separate sites” or “at the same site.” 

477. The NOPR refers to determining whether affiliated facilities are “separate 

facilities” or “a single facility.” However, both the statute and the existing regulations 

745 Allco Comments at 16.

746 DC Commission Comments at 9.

747 Idaho Comments at 1.

748 EEI Comments at 42.
Docket Nos. RM19-15-000 and AD16-16-000 - 267 -

contemplate that the Commission will determine what is “the same site,”749 and do not 

require the Commission to determine whether two facilities are a single facility. The 

statute defines a small power production facility as an eligible facility, which, together 

with other facilities located at the same site (as determined by the Commission), has a 

power production capacity no greater than 80 MW,750 and the Commission’s regulations 

have long approached the matter as defining how to determine “the same site.”751 We find 

that the Commission’s determination of whether or not a small power production facility 

is a QF (i.e., exceeds a power production capacity of 80 MW) should continue to be

focused on whether the small power production facility seeking QF status and other 

nearby affiliated small power production QFs are at the same site or at separate sites.

478. We also modify the NOPR proposal to change the irrebuttable and rebuttable 

presumptions regarding affiliated facilities to instead apply to affiliated small power 

production qualifying facilities. As noted, the NOPR refers to determining whether 

affiliated facilities are “separate facilities” or “a single facility.” We find that only 

affiliated small power production QFs are relevant to the determination of whether the 

small power production facility seeking QF status and other nearby facilities are at the

same site or separate sites.

752 Correspondingly, as further detailed below, we will allow 

749 16 U.S.C. 796(17)(A)(i); 18 CFR 292.204(a).

750 16 U.S.C. 796(17)(A)(i).

751 18 CFR 292.204(a).

752 We note, however, that, in the context of a PURPA section 210(m) proceeding, 

all affiliates are relevant in evaluating whether a QF has nondiscriminatory access to a 
Docket Nos. RM19-15-000 and AD16-16-000 - 268 -

entities challenging a QF certification (both self-certification and application for 

Commission certification) or recertification (both self-recertification and application for 

Commission recertification) to rebut the presumption that a small power production 

facility seeking QF status is at a separate site from any affiliated small power production 

QFs that use the same energy resource and that are located more than one but less than 10 

miles from it.

753

479. We therefore modify the language proposed in the NOPR. In sum, we find that if a 

small power production facility seeking QF status is located one mile or less from any 

affiliated small power production QFs that use the same energy resource, it will be 

irrebuttably presumed to be “at the same site” as those affiliated small power production 

QFs (rather than a single facility at a single site, as proposed in the NOPR). The 

Commission finds that if a small power production facility seeking QF status is located ten 

miles or more from any affiliated small power production QFs that use the same energy 

resource, it will be irrebuttably presumed to be at a separate site from those affiliated 

small power production QFs (rather than separate facilities at separate sites, as proposed 

by the NOPR). We find that if a small power production facility seeking QF status is 

located more than one but less than ten miles from any affiliated small power production 

QFs that use the same energy resource, it will be rebuttably presumed to be at a separate 

competitive market.

753 Though not at issue here, we also note that the facilities need to use the same 

energy resource. 18 CFR 292.204(a)(1).
Docket Nos. RM19-15-000 and AD16-16-000 - 269 -

site from those affiliated small power production QFs (rather than separate facilities at 

separate sites, as proposed in the NOPR). 

480. Purchasing electric utilities and others will be able to file a protest and identify 

factors attempting to rebut the presumption for a small power production facility seeking 

QF status that has an affiliated small power production QF that uses the same energy 

resource more than one but less than 10 miles from it, and argue that the small power 

production facility seeking QFs status should be treated as “at the same site” as the

affiliated small power production QF located more than one but less than 10 miles from it

(rather than as a single facility, as proposed in the NOPR). We will allow a small power 

production facility seeking QF status to provide further information in its certification 

(both self-certification and application for Commission certification) or recertification 

(both self-recertification and application for Commission recertification) to preemptively 

defend against rebuttal by identifying factors that affirmatively show that its facility is

indeed at a separate site from an affiliated small power production QF located more than 

one but less than 10 miles from it (rather than separate facilities at separate sites, as 

proposed in the NOPR). 

481. Regarding the requests to allow states to decide whether affiliated small power 

production QFs are located at separate sites, we note that, in PURPA section 201, now 

codified in section 3 (17) of the FPA, Congress authorized the Commission to determine 

whether the applicant and other facilities are located at the same site. This Commission 

will therefore continue to make these determinations.
Docket Nos. RM19-15-000 and AD16-16-000 - 270 -

e. Distance Between Facilities

i. Comments

482. Several commenters contend that the proposal to institute a rebuttable presumption 

for facilities that are more than one mile but less than 10 miles apart is arbitrary and lacks 

sufficient supporting evidence.754 ELCON notes that the choice of 10 miles as the 

threshold is not supported by any evidence.755

483. Regarding the proposed rebuttable presumption for QFs more than one but less 

than 10 miles apart, Terna Energy argues that the NOPR effectively increases the 

“exclusion zone” around a QF’s electrical generating equipment from approximately three 

square miles (3.1415 square miles, the circle with one-mile radius around the QF’s 

electrical generating equipment, assuming a point generating source) to over 300 square 

miles (i.e. a 10-mile radius circle), a 100-times increase to the “exclusion area” for a 

single QF.756

484. New England Small Hydro notes that hydroelectric generators are located where 

river conditions are ideal for generating and that, while they are not generally located 

754 Allco Comments at 16; Ares Comments at 7; Borrego Solar Comments at 4; 

ELCON Comments at 19; Public Interest Organizations Comments at 93; SC Solar 

Alliance Comments at 17; Solar Energy Industries Comments at 60, 62.

755 ELCON Comments at 35-36.

756 Terna Energy Comments at 4.
Docket Nos. RM19-15-000 and AD16-16-000 - 271 -

within one mile, there may be some projects owned by affiliates that are within 10 miles 

of each other.757

485. Borrego Solar opposes applying the proposed changes to the one-mile rule to 

distributed generation and finds that it would restrict the ability of developers to follow 

market signals when locating projects and significantly increase the regulatory burden. 

Borrego Solar notes that there are several reasons that otherwise different projects from 

the same company would be within 10 miles of each other, including land zoning 

restrictions, available substation capacity, and optimal topology or insolation.758 Borrego 

Solar notes that it is common for projects on the distribution system to be within two miles 

of a substation or three-phase lines to reduce interconnection costs. Borrego Solar states 

that it is also common for multiple unaffiliated developers to site their projects in a single 

area within just a few miles of each other, and later sell those projects to a single entity 

much later in the process, inadvertently violating the Commission’s rules.759 Borrego 

Solar would like the Commission to exclude projects directly interconnected to the 

distribution system or initially developed by different entities from any presumption of 

common development. Borrego Solar urges the Commission to, at a minimum, establish a 

streamlined, low-cost option for challenging any presumption of common development, to 

757 New England Small Hydro Comments at 17.

758 Borrego Solar Comments at 3-4.

759 Id. at 4.
Docket Nos. RM19-15-000 and AD16-16-000 - 272 -

avoid casting a chill over project development and driving developers and long-term 

owners out of the market due to the risks of having the projects disqualified.760

486. North Carolina DOJ argues that the proposed rule, by discouraging facilities from 

being placed close to one another, also runs counter to a North Carolina policy based on 

efficient use of electric resources.761 North Carolina DOJ and North Carolina 

Commission Staff state that the rules in North Carolina incentivize the installation of 

production facilities close to substations so projects naturally appear in clusters 

surrounding transmission and distribution infrastructure.762 North Carolina DOJ says that 

the proposed rule fails to take into account the complex and regionally specific factors 

driving the siting, financing, operation, and maintenance of production facilities.763

487. Industrial Energy Consumers state that the NOPR does not distinguish between 

merchant small power production QFs built to sell electricity to third parties and selfsupply QFs built primarily to support manufacturing or industrial processes. Industrial 

Energy Consumers state that there are many manufacturing company sites that are of a 10-

mile length. Industrial Energy Consumers state that the Commission’s proposed changes 

to the one-mile rule should be clarified to exclude “self-supply” QFs.764

760 Id. at 5.

761 North Carolina DOJ Comments at 8.

762 Id.; North Carolina Commission Staff Comments at 6.

763 North Carolina DOJ Comments at 6.

764 Industrial Energy Consumers Comments at 16.
Docket Nos. RM19-15-000 and AD16-16-000 - 273 -

488. Solar Energy Industries believes that for facilities less than one mile apart the 

Commission should continue to waive the rule where appropriate.765

489. Regarding the proposed irrebuttable presumption that facilities located more than 

10 miles apart are separate facilities, NorthWestern urges the Commission to consider 

increasing the distance. NorthWestern explains that its operations in Montana are 

geographically very expansive and 10 miles in Montana is not a substantial distance, 

especially when compared to other states that are geographically much smaller. 

NorthWestern states that Montana’s electric system has more than 24,450 miles of electric 

transmission and distribution lines to serve approximately 374,000 customers, and that its 

electric operations are very rural and cover more than 97,500 square miles.766 

NorthWestern therefore recommends that the Commission consider expanding this 

distance to accommodate utilities in the West that have very large service territories.767

ii. Commission Determination

490. We adopt the NOPR proposal that an entity can seek to rebut the presumption of 

separate sites only for an entity seeking small power production QF status with an 

affiliated small power production QF or QFs that are located more than one and less than 

10 miles from it. 

765 Solar Energy Industries Comments at 60-61 (citing Windfarms, Ltd., 13 FERC ¶ 

61,017, at 61,032 (1980) (Windfarms)).

766 NorthWestern Comments at 10.

767 Id.
Docket Nos. RM19-15-000 and AD16-16-000 - 274 -

491. We recognize, as we have previously for the one-mile rule,

768 that it is debatable as

to where exactly these thresholds are most appropriately set. PURPA requires that no

small power production facility, together with other facilities located “at the same site,”

exceed 80 MWs, and Congress has tasked the Commission with defining what constitutes 

facilities being at the same site for purposes of PURPA. We find that providing set 

geographic distances will limit unnecessary disputes over whether facilities are at the 

same site, and therefore must choose reasonable distances at which small power 

production facilities will be considered irrebuttably at the same site or irrebuttably at 

separate sites. There are some affiliated small power production facilities using the same 

energy resource that are so close together that it is reasonable to treat them as irrebuttably 

at the same site. The Commission finds that one mile or less is a reasonable distance to 

treat such facilities as irrebuttably at the same site. Likewise, there are some small power 

production facilities that are affiliated and may use the same energy resource but that are 

sufficiently far apart that it is reasonable to treat them as irrebuttably at separate sites. The 

Commission finds that 10 miles or more is a reasonable distance to treat such facilities as 

irrebuttably at separate sites. For affiliated small power production facilities using the 

same resource that are more than one mile but less than 10 miles apart, the Commission 

finds that the distinction between same site or separate site is not as clear, and therefore 

finds that it is reasonable to treat them as rebuttably at separate sites, and to allow 

interested parties to provide evidence to attempt to rebut that presumption. The 

768 See Windfarms, 13 FERC at 61,032. 
Docket Nos. RM19-15-000 and AD16-16-000 - 275 -

Commission finds that establishing these reasonable distances, and particularly 

establishing the ability to rebut the presumption of separate sites for affiliated small power 

production facilities more than one mile but less than 10 miles apart, better allows the 

Commission to address the evolving shape and configuration of resources, such as 

modular solar or wind power plants, that are being developed as QFs, and provides for 

improved administration of PURPA. The Commission therefore finds that the one-mile 

and 10-mile limits are reasonable inflection points for differentiating between the same 

site and separate sites.

492. The Commission understands that there may be many reasons that guide 

developers’ decisions on where to site facilities, and for siting them near to (or far from) 

each other. The Commission reiterates that for affiliated small power production QFs that 

are more than one and less than 10 miles apart, there is still a presumption that they are at 

separate sites, though the Commission today makes that presumption a rebuttable 

presumption.769 We also adopt today the proposal to allow an entity seeking QF status to 

provide further information in its certification (both self-certification and application for 

Commission certification) or recertification (both self-recertification and application for 

Commission recertification) to preemptively defend against rebuttal by identifying factors 

769 For hydroelectric generating facilities, the regulations currently provide that the 

same energy resources essentially means “the same impoundment for power generation,” 

see 18 CFR 292.204(a)(2)(i), and it is unlikely that hydroelectric generating facilities 

located more than a mile apart would rely on the same impoundment. Should that 

circumstance arise, though, the applicant facility could seek waiver, arguing that the 

facilities should not be considered to be at the same site. See 18 CFR 292.204(a)(3). 
Docket Nos. RM19-15-000 and AD16-16-000 - 276 -

that affirmatively show that its facility is indeed at a separate site from affiliated small 

power production QFs more than one but less than 10 miles from it. Additionally, we note 

that we are retaining waiver provision in 18 CFR 292.204(a)(3), allowing the Commission 

to waive the method of calculation of the size of the facility for good cause.770

493. Borrego Solar raises the concern that unaffiliated developers may site their projects 

within a few miles of each other, and later sell those projects to a single entity much later 

in the process, inadvertently violating the Commission’s rules. The Commission finds

that it is reasonable to expect the single purchasing entity in the example to be on notice 

about the size and locations of its QF acquisitions and the requirements of both PURPA 

and the Commission’s regulations, just as it would need to consider other regulatory 

requirements associated with its acquisition. Moreover, ownership by a single entity of 

multiple small power production QFs in close proximity to each other that together exceed 

a power production capacity of 80 MW, and whether this improperly circumvents the 

Commission’s regulations, is precisely what the new rebuttable presumption is seeking to 

address.

494. Regarding Industrial Energy Consumers’ request that the Commission’s changes be 

clarified to exclude “self-supply” QFs, the Commission declines to do so. PURPA limits 

the power production capacity of a small power production QF, together with any other 

facilities located at the same site (as determined by the Commission), to 80 MW.771 The 

770 See 18 CFR 292.204(a)(3).

771 16 U.S.C. 796 (17)(A)(ii).
Docket Nos. RM19-15-000 and AD16-16-000 - 277 -

Commission finds that Industrial Energy Consumer’s argument that “self-supply” QFs are 

built primarily to support manufacturing and industrial processes does not negate the fact 

that the “self-supply” QFs in question are small power production facilities limited to 80 

MW. Similarly, its argument also does not justify different application of the same site 

determination. The Commission will therefore apply the same site determinations to all 

small power production QFs. The Commission notes that, as with other small power 

production QFs, an individual “self-supply” QF may assert relevant factors to show why it 

should not be considered to be at the same site as an affiliated small power production QF

that is more than one but less than 10 miles away from it. For example, if a self-supply 

facility seeking QF status was within 10 miles of an affiliated small power production QF, 

but the energy from each facility was used primarily to supply different end users, the selfsupply facility seeking QF status could argue that this fact supports that it is at a separate 

site from the affiliated small power production QF, and the Commission would consider 

this fact in its evaluation.

495. Regarding Terna Energy’s contention that the new rule causes a 100-times increase 

to the “exclusion zone” around a QF’s electrical generating equipment, we believe that the 

rule providing for a rebuttable presumption for affiliated small power production QFs 

located more than one but less than 10 miles apart, as promulgated today, is necessary to 

address allegations of improper circumvention of the one-mile rule that both previously 

and in comments have been presented to the Commission.

496. We reject NorthWestern’s request to increase the distance of the irrebuttable 

presumption of separate sites to more than 10 miles. Northwestern argues that 10 miles is 
Docket Nos. RM19-15-000 and AD16-16-000 - 278 -

not a significant distance compared to the geographic expansiveness of its system. We 

believe this is an irrelevant comparison; what matters is not how large or small the 

purchasing electric utility’s service territory is or how rural it may be or how many miles 

of transmission lines it may have, but the question presented by the statute, i.e., whether or 

not the affiliated small power production QFs are located at the same site. As described 

above, we have decided that 10 miles is a reasonable and appropriate distance at which to 

apply the irrebuttable presumption of separate sites, irrespective of how expansive, or 

diminutive, the purchasing electric utility’s system may be.

f. Factors

i. Comments

497. Several commenters state that they support the factors for evaluating whether or not 

facilities are at the same site, which are described in the NOPR.

772 SC Solar Alliance and 

the Southeast Public Interest Organizations support considering a common point of 

interconnection or a single real estate parcel or owner as factors weighing towards a 

determination that multiple projects are a single facility.773

498. Several commenters offer additional factors for consideration.774 North Carolina 

Commission Staff states that the Commission should also consider whether the QF is 

772 APPA Comments at 21-22; Connecticut Authority Comments at 19-20; Idaho 

Commission Comments at 6-7; NARUC Comments at 5; Portland General Comments at 

15.

773 SC Solar Alliance Comments at 17; Southeast Public Interest Organization 

Comments at 34.

774 Allco Comments at 16; Idaho Commission Comments at 6-7; North Carolina 
Docket Nos. RM19-15-000 and AD16-16-000 - 279 -

attempting to game the system by getting rates for which they would otherwise be 

ineligible, as well as where the facilities were constructed and when common ownership 

commenced.775 Northern Laramie Range Alliance suggests that relevant factors could 

include, for example, direct or indirect ownership by the same party or parties, 

interconnection at a single substation, simultaneous site acquisition and/or state and local 

permitting.

776 Allco proposes that the criteria to determine if sites are separate should be 

whether they share infrastructure, private roads or interconnection agreements in 

common.777 NRECA proposes that the types of evidence could include evidence of 

contemporaneous construction, shared interconnection, common communication and 

control, use of the same step-up transformer, and common permitting and land leasing.778 

The Idaho Commission proposes that relevant factors include whether they share an 

interconnection agreement, obtained local, state or federal permits under the same 

application or as the same entity, and if they have a revenue sharing agreement.

779 

Commission Staff Comments at 6; Northern Laramie Range Alliance Comments at 3; 

NRECA Comments at 15-16.

775 North Carolina Commission Staff Comments at 6.

776 Northern Laramie Range Alliance Comments at 3.

777 Allco Comments at 16.

778 NRECA Comments at 15-16.

779 Idaho Commission Comments at 6-7.
Docket Nos. RM19-15-000 and AD16-16-000 - 280 -

Portland General suggests that the Commission include past ownership of projects as a 

factor.780 

499. Regarding the relative weight of the factors, the Southeast Public Interest 

Organizations would like the Commission to identify which factors would be definitive in 

a QF being able to proactively demonstrate that their site is separate.781 Both Basin and 

EEI would like the Commission to clarify that the list of factors to be considered is not 

exhaustive or weighted.782 NorthWestern contends that the Commission should specify 

that a showing of any one factor is sufficient to rebut the presumption. NorthWestern 

argues that the Commission should have the flexibility to deal with this issue on a caseby-case basis and expand or modify the list of factors where appropriate.783

500. NorthWestern states that it has concerns about the Commission’s reliance on 18 

CFR 35.36(a)(9), because, according to NorthWestern, developers carefully structure the 

ownership of their companies to ensure that they are not, technically, legal affiliates when, 

in fact, considering the totality of the circumstances, they are affiliates. For these reasons, 

NorthWestern strongly urges the Commission to consider the physical characteristic 

factors identified for determining the distance between facilities in order to also determine 

780 Portland General Comments at 15.

781 Southeast Public Interest Organization Comments at 34.

782 Basin Comments at 12; EEI Comments at 45.

783 NorthWestern Comments at 11.
Docket Nos. RM19-15-000 and AD16-16-000 - 281 -

if facilities are owned by affiliates.784 NorthWestern states that, for example, if one 

facility only owns five percent voting interest in another facility, but the two facilities 

have one interconnection request and use the same collector system, the Commission 

should be able to find that there are sufficient facts so that they are treated as affiliates for 

purposes of the one-mile rule.785

501. Several commenters opposed the Commission’s proposed factors.786 SC Solar 

Alliance states that the range of factors included under the categories of “ownership/other 

characteristics” and “physical characteristics” is overly broad and could be subject to 

inconsistent or problematic interpretation. For example, SC Solar Alliance states that the 

term “infrastructure” is undefined and ambiguous, and “control facilities,” “access and 

easements,” “collector systems or facilities,” and “property leases” are all vague and 

imprecise.787 SC Solar Alliance agrees with Solar Energy Industries’ emphasis that under 

no scenario should common financing be relevant, as unquestionably distinct facilities are 

frequently financed as part of a bundled portfolio.788

784 Id. at 12.

785 Id.

786 Ares Comments at 5-7; Borrego Solar Comments at 3-4; NIPPC, CREA, REC, 

and OSEIA Comments at 73; Solar Energy Industries Comments at 62; SC Solar Alliance 

Comments at 16-18; Southeast Public Interest Organizations Comments at 34.

787 SC Solar Alliance Comments at 17.

788 Id. at 16 (citing Solar Energy Industries Supplemental Comments, Docket No. 

AD16-16, at 55-56 (August 28, 2019)).
Docket Nos. RM19-15-000 and AD16-16-000 - 282 -

502. NIPPC, CREA, REC, and OSEIA strongly oppose use of common interconnection 

facilities as a factor because separately owned facilities are likely to share interconnection 

facilities to reduce costs and build off of existing infrastructure. NIPPC, CREA, REC, and 

OSEIA state that, given that there are only a limited number of qualified maintenance 

providers and other service contractors, the fact that two facilities use the same contractors 

should not be relevant to common ownership and control of two facilities. NIPPC, 

CREA, REC, and OSEIA state that the fact that two facilities are constructed within 12 

months of each other could merely be evidence that the market conditions at the time 

favored construction of the facilities, not that the facilities are intended to be one 

facility.789

503. SC Solar Alliance states that the extensive list of “ownership/other characteristics” 

as written is highly problematic. Control and maintenance, particularly in North and 

South Carolina where there are a substantial number of distributed solar facilities, is often 

contracted for by a limited number of solar maintenance companies. Allowing the 

existence of a common maintenance company to in any way dictate QF status is entirely 

unreasonable and bears no relationship to the question at hand.790 Similarly, other factors 

included in the NOPR, including the sale of electricity to a common utility, a common 

financing lender, the use of a mutual contractor for project construction, the timing of 

contract execution, and the timing of facilities being placed into service do not provide 

789 NIPPC, CREA, REC, and OSEIA Comments at 73-74.

790 SC Solar Alliance Comments at 17-18.
Docket Nos. RM19-15-000 and AD16-16-000 - 283 -

relevant evidence as to common ownership requiring facilities to be considered a single 

QF. Applying these factors would create an unnecessary and undue burden on QFs, 

particularly smaller distribution-connected QFs that have been constructed relatively 

nearby and which often rely on a limited number of local contractors and partners to 

complete this necessary work.791

504. The Southeast Public Interest Organizations are concerned that the use of common 

contractors, financing entity, maintenance companies, or sales to the same entity and such 

could be used against QFs that are built in the same area but are otherwise separate 

sites.792

505. SC Solar Alliance states that the Commission’s statement that “no single factor 

would be dispositive” is troubling, and that it is inconceivable that QF ownership would 

not be dispositive in any such rebuttable presumption. SC Solar Alliance states that it 

would be wholly unjust and unreasonable to consider a solar facility owned by one solar 

developer to be considered part of a solar facility owned by a distinct and unaffiliated 

solar developer. SC Solar Alliance states that any rebuttable presumption should include 

“separate ownership” as a dispositive indication of separate facilities.793

506. North Carolina DOJ states that the element of common control is a challenging 

question because of the limited number of companies available to operate renewable 

791 Id.

792 Southeast Public Interest Organizations Comments at 34.

793 SC Solar Alliance Comments at 17.
Docket Nos. RM19-15-000 and AD16-16-000 - 284 -

energy facilities. North Carolina DOJ asserts that a handful of firms are responsible for 

the operation and maintenance work for close to half of the country’s solar energy 

production facilities.794

507. NIPPC, CREA, REC, and OSEIA state that the Commission should include 

substantially more specific parameters about what evidence a project would need to 

submit to demonstrate single-project status and should make clear that this test has no 

applicability unless generators within one to 10 miles are owned by the same company or 

affiliates of the same company. NIPPC, CREA, REC, and OSEIA assert that “the decisive 

factors are the ‘stream of benefits’ from the project and control of the venture,” which the 

Commission defined “to include entitlement to profits, losses, and surplus after return of 

initial capital contribution.”795 These criteria could be used to objectively evaluate 

whether two QFs within 10 miles are commonly owned or controlled, as opposed to also 

putting two separately owned and controlled facilities at risk of violating the rule based 

solely on physical characteristics.796

ii. Commission Determination

508. We adopt the physical and ownership factors proposed in the NOPR, including as 

noted above the ability of a QF to preemptively identify the factors in its filing in 

794 North Carolina DOJ Comments at 8.

795 NIPPC, CREA, REC, and OSEIA Comments at 73 (citing CMS Midland, Inc., 

50 FERC ¶ 61,098, at 61,278-279 (1990), aff’d Mich. Municipal Coop. Group v. FERC, 

990 F.2d 1377 (D.C. Cir. 1993)).

796 Id.
Docket Nos. RM19-15-000 and AD16-16-000 - 285 -

anticipation of protests to its filing. As explained above in section IV.D.1.d we are 

modifying the NOPR proposal to change terminology relating to the determination of 

whether facilities are separate facilities to focus not on whether they are separate 

facilities, but rather to mirror the statutory language and thus focus on whether they are at 

“the same site.” Accordingly, we adopt these factors as relevant indicia of whether 

affiliated small power production facilities are “at the same site.” In addition, we modify 

the NOPR proposal to identify the following additional physical factors as indicia that 

small power production facilities should be considered to be located at the same site: 

(1) evidence of shared control systems; (2) common permitting and land leasing; and 

(3) shared step-up transformers. 

509. Specifically, we adopt the factors listed below as examples of the factors the 

Commission may consider in deciding whether small power production facilities that are 

owned by the same person(s) or its affiliates are located “at the same site”: (1) physical 

characteristics, including such common characteristics as: infrastructure, property 

ownership, property leases, control facilities, access and easements, interconnection 

agreements, interconnection facilities up to the point of interconnection to the distribution 

or transmission system, collector systems or facilities, points of interconnection, motive 

force or fuel source, off-take arrangements, connections to the electrical grid, evidence of 

shared control systems, common permitting and land leasing, and shared step-up 

transformers; and (2) ownership/other characteristics, including such characteristics as 

whether the facilities in question are: owned or controlled by the same person(s) or 
Docket Nos. RM19-15-000 and AD16-16-000 - 286 -

affiliated persons(s),797 operated and maintained by the same or affiliated entity(ies), 

selling to the same electric utility, using common debt or equity financing, constructed by 

the same entity within 12 months, managing a power sales agreement executed within 12 

months of a similar and affiliated small power production qualifying facility in the same 

location, placed into service within 12 months of an affiliated small power production QF 

project’s commercial operation date as specified in the power sales agreement, or sharing 

engineering or procurement contracts. 

510. We adopt the NOPR proposal to allow a small power production facility seeking 

QF status to provide further information in its certification (both self-certification and 

application for Commission certification) or recertification (both self-recertification and 

application for Commission recertification) to preemptively defend against rebuttal, by 

identifying factors that affirmatively show that its facility is indeed at a separate site from 

affiliated small power production QFs more than one but less than 10 miles away from it. 

Any party challenging the QF certification (both self-certification and application for 

Commission certification) or recertification (both self-recertification and application for 

Commission recertification) that makes substantive changes to the existing certification 

would, in its protest, be allowed to correspondingly identify factors to show that the small 

797 Definitionally, if the facilities are not owned by the same person(s) or its 

affiliates, then the issue of compliance with the one-mile rule, even as revised in this final 

rule, becomes irrelevant. See 18 CFR 292.204(a)(1). That is, two facilities owned by two 

different persons are definitionally not located at the same site.
Docket Nos. RM19-15-000 and AD16-16-000 - 287 -

power production facility seeking QF status and affiliated small power production QFs 

more than one but less than 10 from that facility are actually at the same site. 

511. We reiterate that, as a general matter, no one factor is dispositive.798 Rather, we 

will conduct a case-by-case analysis, weighing the evidence for and against, and the more 

compelling the showing that affiliated small power production QFs should be considered 

to be at the same site as the small power production facility seeking QF status in a specific 

case, the more likely the Commission will be to find that the facilities involved in that 

case are indeed located “at the same site.”

g. Exemptions

i. Comments

512. Ares notes that small power producers have certain exemptions from utility 

regulation, including exemptions from FPA sections 203 and 204 if under 30 MW and 

exemptions from FPA sections 205 and 206 if under 20 MW (or 30 MW in special cases), 

as well as exemptions from some state utility laws and PUHCA if under 30 MW.799 Ares 

is concerned that the rebuttable presumption and the factors will make many small power 

QFs ineligible for these exemptions.800 Ares argues that the aggregation of small power 

QFs may result in many required applications for market-based rate authority for sales that 

are minor. Ares argues that the Commission has no basis for, did not consider, and has 

798 But see supra note 797.

799 Ares Comments at 4-5.

800 Id. at 5-6.
Docket Nos. RM19-15-000 and AD16-16-000 - 288 -

sought no comments on the removal of regulatory obligations when small power QFs are 

aggregated under the new ten-mile proposal.801

513. Solar Energy Industries note that many facilities could lose their FPA and PUHCA 

exemptions if there are multiple facilities within 10 miles, which is particularly harmful to 

QFs that are not selling to their host utility. Solar Energy Industries state that PURPA 

section 210(e)(1) instructs that the Commission shall exempt QFs from regulation if such 

exemption “is necessary to encourage cogeneration and small power production.”802

ii. Commission Determination

514. The Commission’s current one-mile rule is a rule used to measure, ultimately, 

whether or not small power production facilities are within PURPA’s limit on small power 

production QFs of 80 MW, and thus whether such facilities are QFs, and the Commission 

has consistently applied the one-mile rule generally to the regulations issued pursuant to 

PURPA.

803 There is no persuasive reason it should not be equally applied in the context 

of the regulations implementing section 210(e) of PURPA. That being said, we are not 

removing or amending the exemptions provided by the regulations implementing PURPA 

section 210(e). If a QF qualifies for exemptions pursuant to PURPA section 210(e) and 

801 Id. at 11-12.

802 Solar Energy Industries Comments at 55.

803 SunE B9 Holdings LLC, 157 FERC ¶ 61,044, at P 16 & n.24 (2016) (citing 

Windfarms, 13 FERC ¶ 61,017 at 61,031).
Docket Nos. RM19-15-000 and AD16-16-000 - 289 -

the Commission’s implementing regulations,804 then that QF is entitled to those 

exemptions. But, if a small power production facility does not meet the 80 MW limit for 

whatever reason, including because an affiliated small power production QF is located at 

the same site, then it does not qualify for such exemption because it would not be a QF.805 

There is nothing inappropriate about this consequence; a facility that is not a QF is not 

entitled to the exemptions available to QFs. We further note that there will now be a

rebuttable presumption that affiliated small power production QFs located more than one 

but less than 10 miles apart are indeed located at separate sites. That is no different than 

the one-mile rule as it has long existed. What is different is that, with this final rule, the 

presumption will be rebuttable while before it was irrebuttable; the presumption that the 

facilities are at separate sites, though, remains unchanged. Only if a party rebuts that 

presumption and shows that the small power production facility seeking QF status and 

affiliated small power production QFs should be viewed as located at the same site will 

the capacity of such facilities be counted together. In that event, if the small power 

production facility seeking QF status and affiliated small power production QFs located at 

the same site have a combined power production capacity that exceeds 80 MW, the entity 

seeking QF status would not qualify as a QF and would properly not be entitled to the 

exemptions that are available to QFs.

804 18 CFR 292.601, 292.602.

805 See 16 U.S.C. 796(17)(A)(ii).
Docket Nos. RM19-15-000 and AD16-16-000 - 290 -

2. Electrical Generating Equipment

a. NOPR Proposal

515. The Commission proposed defining “electrical generating equipment” to refer to all 

boilers, heat recovery steam generators, prime movers (any mechanical equipment driving 

an electric generator), electrical generators, photovoltaic solar panels and/or inverters, fuel 

cell equipment and/or other primary power generation equipment used in the facility, 

excluding equipment for gathering energy to be used in the facility. The Commission 

expected that each wind turbine on a wind farm and each solar panel in a solar facility 

would be considered “electrical generating equipment” because each wind turbine and 

each solar panel is independently capable of producing electric energy. The Commission

sought comments on this approach, and on what equipment – if not individual wind 

turbines and solar panels – should be considered “electrical generating equipment” for 

wind and solar plants.

516. The Commission also proposed specifying how to measure the distance between 

facilities that have multiple, separate sets of “electrical generating equipment” such as 

wind farms and solar facilities. The Commission proposed measuring the distance 

between the nearest “electrical generating equipment” of any two facilities such that, for 

the facilities to be presumed irrebuttably separate, all such equipment of one QF must be 

at least 10 miles away from all such equipment of another QF. The Commission believed

this is the appropriate way to measure the distance between affiliated sets of “electrical 

generating equipment” because this reflects the distance between the components directly 

tied to producing electric energy. 
Docket Nos. RM19-15-000 and AD16-16-000 - 291 -

517. The Commission sought comment on this approach, and whether alternative 

approaches would be more appropriate. For example, some parties had suggested in QF

certification proceedings that the Commission could use the geographic center of the plant 

footprint or a weighted average of the locations of the individual pieces of “electrical 

generating equipment.”806 The Commission was concerned these approaches could be 

easily gamed, but sought comment on whether they may be constructed in a way that 

would prevent gaming, and whether such formulations would be preferable to the 

proposed approach.

b. Comments

518. Many commenters support the definition of “electrical generating equipment”

proposed in the NOPR.807 However, ELCON objects to both the proposed definition of 

“electric generating equipment” and the approach to measuring distance.808

519. Many commenters support the method for measuring distance between sites 

proposed in the NOPR, which would require measuring the distance between the nearest 

“electrical generating equipment” of any two affiliated facilities.809 Several commenters 

806 See Beaver Creek Wind II, LLC, 160 FERC ¶ 61,052, at P 9 (2017).

807 Alliant Energy Comments at 19; APPA Comments at 23; Basin Comments at 

11; Connecticut Authority Comments at 19-20; EEI Comments at 49; Idaho Commission 

Comments at 6; Kentucky Commission Comments at 7; NRECA Comments at 17; 

Portland General Comments at 16-17; Southeast Public Interest Organizations Comments

at 37-38.

808 ELCON Comments at 36.

809 Alliant Energy Comments at 19; APPA Comments at 23; Basin Comments at 

11; Connecticut Authority Comments at 19-20; EEI Comments at 49; Kentucky 

Commission Comments at 7; NARUC Comments at 4-5; Portland General Comments at 
Docket Nos. RM19-15-000 and AD16-16-000 - 292 -

note their opposition to measuring the distance between sites using the geographic center 

of the plant or a weighted average of the locations of individual pieces of “electrical 

generating equipment,” both methods the Commission sought comment on in the 

NOPR.810 The Southeast Public Interest Organizations request clarification of whether to 

measure from the edge of a solar panel or the center of a solar array.811

520. Several commenters request that the Commission discuss how energy storage 

(sometimes referred to as battery storage) would be considered in relation to the proposed 

definition of electrical generating equipment.812 The California Commission requests that 

a battery storage facility be excluded from consideration as electrical generating 

equipment provided the storage is charged solely by the small power production facility, 

and that energy stored by the storage facility be considered to be of the same energy 

source of that energy before it was stored.813 The California Commission also requests 

that the Commission affirm that storage does not permit a facility to exceed the maximum 

size criteria of a small power production facility.814 EEI requests that the Form 556 

16-17; Southeast Public Interest Organizations Comments at 37-38.

810 Connecticut Authority Comments at 21; Kentucky Commission Comments at 7; 

NorthWestern Comments at 12-13; NRECA Comments at 18; Portland General 

Comments at 18.

811 Southeast Public Interest Organizations Comments at 38. 

812 Alliant Energy Comments at 19; EEI Comments at 46-47; Energy Storage 

Comments at 3; NorthWestern Comments at 13.

813 California Commission at 16-17.

814 Id. at 15.
Docket Nos. RM19-15-000 and AD16-16-000 - 293 -

collect data on storage resources as well as electrical generating equipment for purposes of 

measuring distance to an affiliated small power production QF.815

c. Commission Determination 

521. We adopt the NOPR proposal that “electrical generating equipment” refers to all 

boilers, heat recovery steam generators, prime movers (any mechanical equipment driving 

an electric generator), electrical generators, photovoltaic solar panels, inverters, fuel cell 

equipment and/or other primary power generation equipment used in the facility, 

excluding equipment for gathering energy to be used in the facility. Each wind turbine at

a wind facility and each solar panel in a solar facility would be considered “electrical 

generating equipment” because each wind turbine and each solar panel is independently 

capable of producing electric energy. 

522. We require the distance between the facility seeking small power production QF 

status and any affiliated small power production QFs using the same energy resource to be 

measured by the distance between the nearest “electrical generating equipment” of each 

such facility, such that, for the entity seeking QF status to be presumed irrebuttably at a

separate site from any affiliated small power production QF, all such equipment of the 

affiliated small power production QF must be at least 10 miles away from all such 

equipment of the entity seeking small power production QF status. The Commission finds 

that this is the most appropriate way to measure the distance between affiliated sets of 

815 EEI at 51-52.
Docket Nos. RM19-15-000 and AD16-16-000 - 294 -

“electrical generating equipment” at small power production facilities because this reflects 

the distance between the components directly tied to producing electric energy. 

523. The point used in the distance calculation will always be from the edge of the 

electrical generating equipment closest to the affiliated small power production QF’s 

nearest electrical generating equipment. Thus, we clarify that for a solar facility, the 

measurement should be from the edge of the small power production facility seeking QF 

status’ solar panel or inverter that is closest to the edge of the nearest “electrical 

generating equipment” of that affiliated small power production QF. For a wind facility, 

the measurement should similarly be from the edge of the small power production facility

seeking QF status’ wind turbine or inverter closest to the edge of the nearest “electrical 

generating equipment” of the affiliated small power production QF. For a wind facility, 

we clarify that the relevant point for measuring distance of an individual wind turbine is 

the tower (not the projection of the blade’s wingspans onto the ground). We also clarify 

that only horizontal distances are taken into consideration for purposes of this rule (such 

that elevation changes have no effect on facility distance).

524. We find that the role of battery storage in QFs, including with regard to the 

distance between QFs, is beyond the scope in this proceeding.

E. QF Certification Process 

1. NOPR Proposal

525. In the NOPR, the Commission proposed to revise 18 CFR 292.207(a) to allow 

interested persons to intervene in, and to file a protest of a self-certification or selfrecertification of a facility without the necessity of filing a separate petition for 
Docket Nos. RM19-15-000 and AD16-16-000 - 295 -

declaratory order and without having to pay the filing fee required for a declaratory order. 

Because an applicant for self-certification or self-recertification is required to serve a copy 

of its submission on interested electric utilities (principally those with which it is 

interconnected and those to which it will be selling) as well as the relevant state regulatory 

authorities, the Commission proposed to allow interested persons 30 days from the date of 

filing at the Commission to intervene and/or to file a protest (without paying a filing 

fee).816 

526. Any party submitting a protest would have the burden of specifying facts that make 

a prima facie demonstration that the facility described in the self-certification or selfrecertification does not satisfy the requirements for QF status. General allegations that the 

facility is not a QF without reference to the specific regulatory provision that has not been 

satisfied (and without an explanation why the provision has not been satisfied), or 

unsupported assertions that the self-certification does not satisfy an aspect of the PURPA 

Regulations, would not satisfy this burden and would not be a basis for denial of 

certification. However, if this prima facie burden is met, then the burden would shift to 

the applicant submitting the self-certification or self-recertification to demonstrate that the 

claims raised in the protest are incorrect and that certification is, in fact, warranted.

527. QF self-certification is effective upon filing and would remain effective if a protest 

is filed, until such time as the Commission rules that certification is revoked. The 

Commission proposed that it would issue an order within 90 days of the date the protest is 

816 18 CFR 292.207(c)(1). 
Docket Nos. RM19-15-000 and AD16-16-000 - 296 -

filed. The Commission also reserved the right to request more information from the 

protester, the entity seeking QF status, or both.817 If the Commission requests more 

information, the time period for the Commission order would be extended to 60 days from 

the filing of a complete answer to the information request. 

528. There may be instances, however, when the Commission may need additional time 

to review the record in light of the nature of the protests. In those cases, the Commission 

proposed that, in addition to any extension resulting from a request for information, the 

Commission also may toll the 90-day period during which the Commission commits to act 

within one additional 60-day period. The Commission proposed to delegate to the 

Commission’s Secretary, or the Secretary’s designee, the authority to toll the 90-day 

period for this purpose. 

529. The Commission believed these procedures would allow for timely but thorough 

review of protested self-certifications and self-recertifications. The Commission sought

comment on whether these procedures impose an undue burden on the QF even though the 

QF remains certified pending the review.

817 Such information requests could be issued by the Commission or by staff under 

any applicable delegated authority. For example, under 18 CFR 375.307(b)(3)(ii), the 

Director of the Office of Energy Market Regulation is authorized to “[i]ssue and sign 

requests for additional information regarding applications, filings, reports and data 

processed by the Office of Energy Market Regulation.”
Docket Nos. RM19-15-000 and AD16-16-000 - 297 -

2. Comments

530. Many commenters raise the issue of granting legacy treatment, colloquially known 

as “grandfathering,” to existing QF certifications and their future recertifications.818 Most 

of these comments support granting legacy treatment to current QFs and their future 

recertifications.819 Several commenters note that the application of the rule to existing or 

recertifying QFs will create uncertainty and cause disruptions of the sale of these QFs.820

531. New England Small Hydro warns that applying the proposed rule to existing QFs 

could trigger financing defaults if those QFs lose their status.821 The Southeast Public 

Interest Organizations state that the proposed rebuttable presumption has implications for 

existing solar QFs in the Southeast, noting that QFs would be required to seek 

recertification as their existing PPAs expire, adding a significant burden.822 The Southeast 

Public Interest Organizations provide maps showing the ten-mile radius of utility-scale 

818 Ares Comments at 12; Basin Comments at 11; BluEarth Comments at 2; DC 

Commission at 9; New England Small Hydro Comments at 17; Industrial Energy 

Consumers Comments at 17; NIPPC, CREA, REC, and OSEIA Comments at 74; Solar 

Energy Industries Comments at 61-63; SC Solar Alliance Comments at 18; Southeast 

Public Interest Organizations Comments at 29-31; Terna Energy Comments at 16-18.

819 Ares Comments at 12; BluEarth Comments at 2; New England Small Hydro 

Comments at 17; Industrial Energy Consumers Comments at 17; NIPPC, CREA, REC, 

and OSEIA Comments at 74; Solar Energy Industries Comments at 61-63; SC Solar 

Alliance Comments at 18; Southeast Public Interest Organizations Comments at 29-31; 

Terna Energy Comments at 16-18.

820 New England Small Hydro Comments at 17; NIPPC, CREA, REC, and OSEIA 

Comments at 74; Terna Energy Comments at 16-18.

821 New England Small Hydro Comments at 17.

822 Southeast Public Interest Organizations Comments at 29.
Docket Nos. RM19-15-000 and AD16-16-000 - 298 -

projects could lead to many overlapping affiliated territories under the new rules.823 SC 

Solar Alliance also notes the large number of small solar QFs overlapping within a tenmile radius across North Carolina and South Carolina and finds that the application of the 

more-than-one-but-less-than-10-miles rebuttable presumption to recertifications will be 

burdensome and unwieldy.824 NIPPC, CREA, REC, and OSEIA warn that the application 

of the new rule to existing QFs will effectively bar the transfer or sale (or potentially any 

number of less significant changes) of existing assets that were lawfully qualified under 

the one-mile rule but would pass the 80 MW aggregate threshold under the new rule. 

NIPPC, CREA, REC, and OSEIA find this to be a violation of the existing QFs 

contractual and constitutional rights.825 

532. Terna Energy states that granting legacy treatment to existing QFs and their 

recertifications is necessary to protect investment decisions and contracts made under the 

long-standing one-mile rule.826 Terna Energy contends that, without clarification on the 

legacy treatment of recertifications, QFs could lose their status even for non-substantive 

revisions to their FERC Form No. 556s such as contact information, street address, 

ownership or operation.827 Terna Energy warns that absent the clarification of legacy 

823 Id. at 30-31.

824 SC Solar Alliance Comments at 18.

825 NIPPC, CREA, REC, and OSEIA Comments at 75.

826 Terna Energy Comments at 1-2.

827 Id. at 2.
Docket Nos. RM19-15-000 and AD16-16-000 - 299 -

treatment for existing QF recertifications, QFs might go to extremes to avoid updating 

their FERC Form No. 556s with information changes.828

533. Solar Energy Industries state that retroactively applying a more-than-one-but-lessthan-10-miles rebuttable presumption to physical facilities that were developed based on 

the original one-mile rule will inject instability, will erode trust from the investment 

community, and will discourage the development of QFs as well as investment in the 

industry in general.829 Ares notes that not granting legacy treatment to existing QFs is 

inconsistent with past Commission actions on PURPA, such as the granting of legacy 

treatment to existing QF contracts in Order No. 671 or other QF related proceedings.830

534. New England Small Hydro supports granting legacy treatment to existing QFs to 

avoid upsetting the settled expectations of existing generation.831 New England Small 

Hydro gives the example of three hypothetical projects, each located nine miles apart that, 

when capacities are totaled, exceed 80 MW. If there is an ownership change that triggers 

the need for a recertification but the entities remain affiliates, under the Commission’s 

proposed rule, all three projects would lose QF status. According to New England Small 

Hydro, this could trigger defaults under financing documents and the utility might be able 

to terminate the power contract, because many PPAs for QFs require the project to remain 

828 Id. at 7.

829 Solar Energy Industries Comments at 62.

830 Ares Comments at 12.

831 New England Small Hydro Comments at 17.
Docket Nos. RM19-15-000 and AD16-16-000 - 300 -

a QF for the term of the PPA. New England Small Hydro states that, as a result, a minor 

ownership change could have cascading negative effects to QFs.832

535. Terna Energy requests that existing QFs be granted legacy treatment as long as they 

do not make changes to electrical generating equipment of the facility, because that is the 

equipment that determines compliance with the one-mile rule. Terna Energy argues that 

otherwise an existing QF could be subject to challenge anytime it makes a non-substantive 

revision to its FERC Form No. 556, including a change to contact information, street 

address, ownership, or operator, effectively eliminating legacy treatment.

833 Terna Energy 

states that granting legacy treatment is necessary to protect the sanctity of investments and 

contracts made in reliance upon the Commission’s current PURPA regulations and the 

one-mile rule.834 Terna Energy submits revised language for 18 CFR 292.204(a)(2) and 

(3) to clarify that existing QF recertifications, unless they change the electrical generating 

equipment, should not be subject to the new rules.835

536. Basin, on the other hand, asks the Commission to be clear that recertifications filed 

by QFs will trigger application of the proposed rule.836 Basin also recommends the 

Commission allow petitions seeking de-certification of QFs that have previously filed 

832 Id.

833 Terna Energy Comments at 2.

834 Id. at 1-2.

835 Id. at 8-9.

836 Basin Comments at 11.
Docket Nos. RM19-15-000 and AD16-16-000 - 301 -

self-certifications because some QFs self-certify at an early stage of project development 

and ultimately never proceed to development.837

537. The DC Commission would like the Commission to clarify whether the changes to 

the one-mile rule will apply to QFs under construction when the rule goes into effect.

838

The DC Commission would like the Commission to leave the issue of legacy treatment of

existing QFs up to the states.839 

538. Several commenters oppose the NOPR proposal to allow a party to protest a selfcertification or self-recertification of a facility without being required to file a separate 

petition for declaratory order and pay the associated filing fee.840 Several commenters 

argue that this proposal will lead to a flood of challenges that will discourage the growth 

of QFs.841 Several commenters state that there will be substantial costs associated with 

this proposal that will fall on ratepayers and QFs.842 Several commenters state that the 

837 Id.

838 DC Commission Comments at 9.

839 Id.

840 Allco Comments at 21; BluEarth Comments at 3; CARE Comments at 7; Con 

Edison Comments at 5; Distributed Sun Comments at 3; ENGIE Comments at 4; Public 

Interest Organizations Comments at 9, 97-98; Western Resource Councils Comments at 

144; Solar Energy Industries Comments at 57-59.

841 Allco Comments at 21; BluEarth Comments at 3; Distributed Sun Comments at 

3; Public Interest Organizations Comments at 97; Western Resource Councils Comments 

at 144.

842 Con Edison Comments at 5; ENGIE Comments at 4; Public Interest 

Organizations Comments at 97; Solar Energy Industries Comments at 58.
Docket Nos. RM19-15-000 and AD16-16-000 - 302 -

proposed changes will lead to increased administrative burden and expense843 or litigation

risk.844 Several commenters state that the proposed changes will lead to uncertainty845 and 

deter development.846

539. Solar Energy Industries state that the proposed changes to the one-mile rule will 

substantially increase the regulatory burden on QFs and the self-certification process will 

no longer be quick.847 Solar Energy Industries is concerned that QFs may need to defend 

numerous self-certifications over a facility’s lifetime, and assert that QFs could be forced 

to recertify any time the information represented in the Form No. 556 changes, including 

843 Ares Comments at 6; Borrego Solar Comments at 4; Con Edison Comments at 

5; Public Interest Organizations Comments at 97-98; Solar Energy Industries Comments 

at 51-52, 54, 57-58; SC Solar Alliance Comments at 15-18; Southeast Public Interest 

Organizations Comments at 29, 35; sPower Comments at 14.

844 Con Edison Comments at 5; Distributed Sun Comments at 3; ELCON

Comments at 19-20; NIPPC, CREA, REC, and OSEIA Comments at 71-72; Public 

Interest Organizations Comments at 97-98; Solar Energy Industries Comments at 58-60; 

SC Solar Alliance Comments at 16, 18; Southeast Public Interest Organizations 

Comments at 29,35; sPower Comments at 14.

845 Ares Comments at 9; Distributed Sun Comments at 3; ELCON Comments at 19-

20, 38; NIPPC, CREA, REC, and OSEIA Comments at 69-72; Public Interest 

Organizations Comments at 97-98; Solar Energy Industries Comments at 58-60, 62-63; 

SC Solar Alliance Comments at 16, 18; Southeast Public Interest Organizations 

Comments at 29, 35, 38, 93, 97-98; sPower Comments at 14.

846 Allco Comments at 16; Borrego Solar Comments at 4-5; Biological Diversity 

Comments at 9; Con Edison Comments at 4-5; Distributed Sun Comments at 3; NIPPC, 

CREA, REC, and OSEIA Comments at 72-73; North Carolina DOJ Comments at 8; 

Public Interest Organizations Comments at 93, 99; Solar Energy Industries Comments at 

51-52, 59-63; SC Solar Alliance Comments at 2, 18; Southeast Public Interest 

Organizations Comments at 31-36, 38, 93.

847 Solar Energy Industries Comments at 52.
Docket Nos. RM19-15-000 and AD16-16-000 - 303 -

ownership changes to affiliated facilities located within 10 miles.848 Solar Energy 

Industries state that the burden will be increased exponentially if the one-mile rule is 

expanded in a ten-mile rule.849 Solar Energy Industries state that the NOPR’s estimate of 

an additional eight hours and $632 per docket for each QF self-certification or recertification is a substantial underestimation.850 Solar Energy Industries estimate that it 

would require an additional approximately 90 to 120 hours per year to comply with the 

new requirements. Solar Energy Industries state that a QF could be forced to recertify any 

time the information represented changes, including ownership changes to affiliated 

facilities located within 10 miles. Solar Energy Industries note that a QF may have to 

engage in multiple defenses of its status, each time needing to engage legal counsel and 

devote internal company resources to preserve the status of its already-installed plant.851

Solar Energy Industries assert that the flood of self-certification filings and updates would 

be a substantial burden on Commission staff and provide little value to the Commission or 

the public.852 Solar Energy Industries also state that, unless and until the Commission 

makes a determination on the burden associated with collecting, reporting, and updating 

the Connected Entity853 information, it would be unjust and unreasonable for the 

848 Solar Energy Industries at 57.

849 Id. at 53.

850 Id. at 52.

851 Id. at 58.

852 Id. at 53-54.

853 Id. at 54 (citing Data Collection for Analytics and Surveillance and Market-
Docket Nos. RM19-15-000 and AD16-16-000 - 304 -

Commission to impose similar burdens on QF entities through the FERC Form No. 556.854 

Solar Energy Industries state that the increased regulatory burden that will arise for these 

entities is similar in scope and the Commission has not provided a rationale for the 

increased information collection requirements.855

540. Allco describes the Commission’s Regulatory Flexibility Act (RFA) analysis of the 

proposed rules’ effect on small businesses as improperly limited to proposed paperwork 

changes, ignoring the impact on small QFs’ abilities to construct facilities.856 Allco states 

that the Commission did not attempt to minimize the impacts on small renewable energy 

producers, consider alternative structures, or describe these steps or considerations in a 

mandatory final RFA analysis.857 Allco asserts that the Commission failed to support its 

finding that the NOPR’s proposed revisions will not significantly impact a substantial 

number of small entities (specifically, solar energy QFs); Allco therefore claims that the 

Commission violated the Small Business Regulatory Enforcement Fairness Act.858

541. Solar Energy Industries state that the NOPR lacks important details such as 

whether the Commission’s determination is subject to rehearing, and whether a final 

Based Rate Purposes, Order No. 860, 168 FERC ¶ 61,039, at P 183 (2019)).

854 Id. at 54, 57.

855 Id. at 54.

856 Allco Comments at 33.

857 Id.

858 Id.
Docket Nos. RM19-15-000 and AD16-16-000 - 305 -

decision can be appealed under the FPA to an appellate court.859 Solar Energy Industries 

state that an adverse determination by the Commission could impose upwards of $100 

million in harm on a QF, and it is unclear whether the QF would have a path to relief if the 

Commission erred in its determination. Solar Energy Industries state that the current 

practice, where the challenger bears the responsibility of seeking declaratory relief, strikes 

an appropriate balance.860

542. Several commenters, on the other hand, support the NOPR proposal to allow a 

party to protest a self-certification or self-recertification of a facility without being 

required to file a separate petition for declaratory order and to pay the associated filing 

fee.861 Several commenters argue that the proposed amendment would strike the right 

balance and distribute the burdens of proof appropriately.862 Several commenters also 

state that this proposal would increase the efficiency of the process, reduce administrative 

costs, and could solve potential certification problems before they even begin.863

859 Id. at 58.

860 Id. at 59.

861 Alaska Power Comments at 2; Alliant Energy Comments at 22-23; APPA 

Comments at 31-35; Duke Energy Comments at 23-24; Indiana Municipal Comments at 

10; NRECA Comments at 21-22; Portland General Comments at 21-22; Ohio 

Commission Energy Advocate Comments at 10; Chamber of Commerce Comments at 8; 

We Stand Comments at 3.

862 APPA Comments at 31-35; NRECA Comments at 21-22; Ohio Commission 

Energy Advocate Comments at 10.

863 Indiana Municipal Comments at 10; NRECA Comments at 21-22; Portland 

General Comments at 21-22.
Docket Nos. RM19-15-000 and AD16-16-000 - 306 -

543. Other commenters support the NOPR proposal, but with caveats or extra 

requests.864 Golden Valley recommends that the 30-day clock to challenge QF selfcertification or self-recertification begins when the QF serves notice to the interested 

electric utility, not when the QF makes its filing with the Commission.865 NIPPC, CREA, 

REC, and OSEIA state that the Commission should provide a 60-day deadline after the 

filings are complete by which time a failure of the Commission to rule results in the 

objection being denied by operation of law.866

544. NorthWestern requests the QFs be subject to various discovery requests when they 

self-certify or self-recertify.867 Two commenters argue that any challenging party should 

be required to include an affidavit from a company official.868

545. NorthWestern and Northern Laramie Range Alliance request that QF developers 

seeking certification with the Commission should be required to publish notice in local 

newspapers in the states in which the development would be located, in order to alert 

affected parties so they could intervene in the certification process.869 El Paso Electric is 

864 DTE Electric Comments at 9-10; Golden Valley Electric Comments at 1-2, 3-7; 

Industrial Energy Consumers Comments at 14; Northern Laramie Range Alliance 

Comments at 3; NorthWestern Comments at 17-18; ELCON Comments at 19-20, 37-38.

865 Golden Valley Electric Comments at 2.

866 NIPPC, CREA, REC, and OSEIA Comments at 74.

867 NorthWestern Comments at 17-18.

868 Industrial Energy Consumers Comments at 14; ELCON Comments at 20, 38.

869 NorthWestern Comments at 3; Northern Laramie Range Alliance Comments at 

3.
Docket Nos. RM19-15-000 and AD16-16-000 - 307 -

concerned by the proposal to limit the ability to challenge QF status once it has been 

certified in a Commission certification proceeding or in response to a challenge unless the 

new challenger can demonstrate a change in the facility circumstances that threaten the 

validity of the previous finding. El Paso Electric states that sometimes QFs fail to provide 

utilities with their QF application and so the utility does not know to protest.870 

546. Ares notes that small power production QFs could be aggregated under the morethan-one-but-less-than-10-miles rebuttable presumption and not even be aware of the 

other small power production QFs because of a lack of information.871

3. Commission Determination

547. We adopt the NOPR proposal to revise 18 CFR 292.207(a) to allow an interested 

person or entity to seek to intervene and to file a protest of a self-certification or selfrecertification of a QF, and not have to file a petition for declaratory order and pay the 

filing fee for petitions.872 We also adopt the other changes to the QF certification process 

proposed in the NOPR, with the additions detailed below. We find that any increased 

administrative burden or litigation risk imposed by the new rule is justified by the need to 

ensure that QFs meet the statutory criteria for QF status. 

548. The ability to intervene and to file a protest of a self-certification or selfrecertification of a QF without having to file a petition for declaratory order and pay the 

870 El Paso Electric Comments at 5.

871 Ares Comments at 6.

872 We amend the proposed regulation in the NOPR to move the sections referring 

to protests and interventions from 18 CFR 292.204 to 18 CFR 292.207. 
Docket Nos. RM19-15-000 and AD16-16-000 - 308 -

filing fee for petitions is effective as of the effective date of the final rule. However, we 

will grant legacy treatment to existing QFs under certain circumstances, as we explain 

below. With the exceptions noted below, protests pursuant to this final rule will not be 

allowed to QF certifications and recertifications (including self-certifications and selfrecertifications) that are submitted before the effective date of the final rule, although 

entities may still challenge by filing a petition for declaratory order and submitting the 

required fee. Conversely, protests can be made to QF certifications (both self-certification 

and application for Commission certification) or recertifications (both self-recertification 

and application for Commission recertification) that are submitted on or after the effective 

date of this final rule. We note here that it is the date of filing for certification or 

recertification, and not the date of construction, that determines whether our new protest 

rule applies to the certification or recertification. 

549. Many commenters have argued for expansive legacy treatment for recertification of 

existing projects. They have noted that QFs need to recertify when property is transferred, 

PPAs expire, or even for non-substantive changes, such as changes in contact information 

or street address.873 Commenters argue that, if the new protest rules apply to 

recertifications, existing QFs could lose their QF status, even if their configuration or 

other relevant factors do not materially change, when they file their recertifications, 

upsetting the settled expectations under which the QFs built their facilities. 

873 NIPPC, CREA, REC, and OSEIA Comments at 75; Terna Energy Comments at 

1-2, 7.
Docket Nos. RM19-15-000 and AD16-16-000 - 309 -

550. We agree that QF recertifications to implement or address non-substantive changes 

should not be subject to our new protest rule; the settled expectations of the QFs should be 

respected in such instances. Accordingly, we find that protests may be filed to an initial 

certification (both self-certification and application for Commission certification) filed on 

or after the effective date of this final rule, but only to a recertification (both selfrecertification and application for Commission recertification) that makes substantive 

changes to the existing certification and that are filed on or after the effective date of this 

final rule. Substantive changes that may be subject to a protest may include, for example,

a change in electrical generating equipment that increases power production capacity by

the greater of 1 MW or 5 percent of the previously certified capacity of the QF, or a

change in ownership in which an owner increases its equity interest by at least 10% from

the equity interest previously reported. We find that recertifications (both selfrecertifications and applications for Commission recertifications) making “administrative 

only” changes should not be subject to a protest pursuant to this final rule.

874 We believe 

that excepting from protests QF recertifications making non-substantive changes will 

allow QFs to make such changes and recertify without potentially losing their QF status. 

551. Solar Energy Industries asserts that the certification process will no longer be 

quick, and estimates that it would require an additional approximately 90 to 120 hours per 

year to comply with these new requirements. Solar Energy Industries is concerned that 

874 As noted elsewhere in this final rule, our allowing protests does not eliminate 

the ability to file a petition for declaratory order seeking revocation of qualifying status. 
Docket Nos. RM19-15-000 and AD16-16-000 - 310 -

QFs may need to defend numerous self-certifications over a facility’s lifetime, and asserts 

that QFs could be forced to recertify any time the information represented in the Form No. 

556 changes.875 

552. We do not agree with Solar Energy Industries’ estimates. First, we note that 18 

CFR 292.207(d) (which we are not altering in this rule except to renumber as 18 CFR 

292.207(f)) already states that if a QF fails to conform with any material facts or 

representations presented in the certification, the QF status of the facility may no longer 

be relied upon,876 and hence it is long-standing practice that a QF must recertify when 

material facts or representations in the Form No. 556 change. 

553. Second, certifications and recertifications are already subject to protests, albeit in 

the form of petitions for declaratory order, and therefore dealing with objections to a 

certification or recertification is not new. Although the new procedures may result in 

more protests being filed than the number of petitions that have been filed, we believe that 

the conditions we impose in this final rule will limit the number of protests filed. The 

Commission anticipates that most, though not all, of the protests filed pursuant to the new 

18 CFR 292.207(a) will relate to the new more-than-one-but-less-than-10-miles rebuttable 

presumption.877 Such protests will necessarily be limited because not all certifications and

875 Solar Energy Industries at 57.

876 18 CFR 292.207(d), which this final rule will renumber to 18 CFR 292.207(f).

877 While we anticipate that most protests will involve interested persons or entities 

attempting to rebut the presumption of separate sites for affiliated small power production 

qualifying facilities that are more than one and less than 10 miles apart, we note that 

protesters may also protest any fact or representation in the Form No. 556, or other aspect 
Docket Nos. RM19-15-000 and AD16-16-000 - 311 -

recertifications will be subject to the new more-than-one-but-less-than-10-miles rebuttable

presumption. Only small power production facilities seeking QF status that have an 

affiliated small power production QF more than one but less than 10 miles away and that 

uses the same energy resource are subject to the rebuttable presumption. Small power 

production facilities that do not have multiple small power production facilities or 

affiliates will not be affected by the new rebuttable presumption. Nor will cogeneration 

QFs be affected by the new rebuttable presumption.878 Additionally, in general as

described above, protests may only be made to an initial certification (both selfcertification and application for Commission certification) filed on or after the effective 

date of this final rule, and only to a recertification (self-recertification or application for 

Commission recertification) that makes substantive changes to the existing certification

that are filed after the effective date of this final rule.

554. Third, we are also instituting time limits on protests that may be filed under this 

final rule. We adopt the NOPR proposal that interested parties will have 30 days from the 

date of the filing of the Form No. 556 at the Commission to file a protest (without paying 

a fee).879 Additionally, a protestor must concurrently serve its protest on the Form No. 

556 applicant pursuant to 18 CFR 385.2010. 

of a QF’s filing they believe is inconsistent with PURPA or our PURPA Regulations.

878 The 80 MW limit and same site determination only apply to small power 

production facilities, not cogeneration facilities. See 16 USC 796(17)(A).

879 We note that section 292.207(c) of the PURPA Regulations requires the 

applicant to concurrently with its filing serve a copy of the filing on each applicable 

electric utility as well as the applicable State regulatory authority. We expect an applicant 
Docket Nos. RM19-15-000 and AD16-16-000 - 312 -

555. Fourth, regarding Solar Energy Industries’ concern that a QF may have to engage 

in multiple defenses of its status, in addition to the above limits on protests, once the 

Commission has affirmatively certified an applicant’s QF status in response to a protest 

opposing a self-certification or self-recertification, or in response to an application for 

Commission certification or Commission recertification, any later protest to a 

recertification (self-recertification or application for Commission recertification) making 

substantive changes to a QF’s existing certification, e.g., asserting that the entity seeking 

QF status is at the same site as affiliated small power production QFs more than one but 

less than 10 miles from it, must demonstrate changed circumstances from the facts on 

which the Commission acted on the certification filing that call into question the 

continued validity of the earlier certification. 

556. Finally, even if it indeed takes some small power production facilities an additional 

90 to 120 hours (and we think that unlikely), that is not an unreasonable burden to impose 

to ensure that a generating facility that seeks to be a QF is, in fact, entitled to QF status

and complying with PURPA. 880

seeking QF status (or recertifying its status) to timely comply with that regulation. 

Therefore, a utility should also receive the filing at the same time that the filing is made at 

the Commission.

880 The regulations adopted in this final rule explicitly make self-certifications and 

self-recertifications effective upon filing and allow them to remain effective even if 

challenged until such time as the Commission finds that a facility does not qualify to be a 

QF. Additionally, entities seeking QF status can file self-certifications years in advance of 

facility operation, such that the few months contemplated by the new process should not 

cause delay. Finally, with regard to the time it may take to fill in the Form No. 556, we 

note that while an entity seeking QF status may choose to preemptively defend against 

claims that it should be considered to be at the same site as affiliated small power 
Docket Nos. RM19-15-000 and AD16-16-000 - 313 -

557. Turning to the requirements for a protest, as proposed in the NOPR, we will require 

any person or entity filing a protest to specify facts that make a prima facie demonstration 

that the facility described in the certification (both self-certification and application for 

Commission certification) or recertification (both self-recertification or application for 

Commission recertification) does not satisfy the requirements for QF status. We will also 

require any protest to be adequately supported with any supporting documents, contracts, 

or affidavits, as appropriate. Just as public utilities are typically not subject to discovery 

with regard to their rate filings under section 205 of the FPA prior to the Commission’s 

instituting trial-type evidentiary hearings,881 we similarly decline to make QFs subject to 

discovery requests when they self-certify or self-recertify. 

558. The Commission also orders here that an applicant’s response to a protest will be 

allowed under 18 CFR 385.213(a)(2). By this final rule, we are consistent with that 

regulation, “otherwise order[ing]” that such answers may be filed. They will be due no 

later than 30 days after the filing of the protest. 

559. Rooftop solar developers frequently finance the initial development of rooftop solar 

photovoltaic (PV) systems of individual homeowners, and then retain ownership of such 

PV systems for extended periods of time until the ownership is eventually transferred to 

the relevant homeowners. While these rooftop solar PV systems are owned by the 

production qualifying facilities located more than one but less than 10 miles from it, this is 

optional, not required.

881 18 CFR 385.401(a).
Docket Nos. RM19-15-000 and AD16-16-000 - 314 -

developer, each individual rooftop solar PV system would be considered affiliated 

electrical generating equipment of every other rooftop solar PV system owned by that 

developer. When there are multiple co-owned rooftop solar PV systems within a mile, 

and thus at the same site, they may exceed 1 MW and therefore be required to file for 

certification or recertification unless they receive a waiver.882 Moreover, whenever they 

add an additional rooftop solar PV system to their portfolio, or alternatively transfer the 

ownership of such a rooftop solar PV system to the relevant homeowner, their facility 

could be viewed as no longer conforming with the material facts in their prior certification 

or recertification; thus they would need to recertify. 

560. Due to the unique nature of rooftop solar PV developers, the Commission finds the 

recertification requirement for PV developers could be unduly burdensome. Therefore, to 

lessen the burden on such developers when recertifying, we will permit rooftop solar PV 

developers an alternative option to file their recertification applications. That is, rather 

than be required to file for recertification each time the rooftop solar developer adds or 

removes a rooftop facility, a rooftop solar PV developer may recertify on a quarterly basis. 

The filing would be due within 45 days after the end of the calendar quarter. However, if

in any quarter a rooftop solar PV developer either has no changes or only has changes of 

power production capacity of 1 MW or less, then it would not be required to recertify until 

it has accumulated changes greater than 1 MW total over the quarters since its last 

882 See Sunrun, Inc., 167 FERC ¶ 61,059 (2019).
Docket Nos. RM19-15-000 and AD16-16-000 - 315 -

filing.883 Additionally, we note that rooftop solar PV developers, like all small power 

production facilities, will not be subject to protests when they file recertifications that are 

“administrative only” in nature, but would be subject to such protests when they make 

substantive changes to the existing certification as detailed above in this section.

561. We take this opportunity to clarify that, when the Commission issues an order 

revoking QF certification, such order is subject to rehearing and appeal pursuant to the 

FPA.

884 The Commission’s authority to determine whether or not a facility is a qualifying 

small power production facility stems from PURPA section 201, which amended FPA 

section 3 to add paragraph (17).

885 Similarly, FPA section 3(18) grants the Commission 

authority to determine whether a cogeneration facility meets the Commission’s 

requirements.886 Because the Commission’s authority is grounded in the FPA, the 

883 For example, if a rooftop solar QF increases its power production capacity by 

0.9 MW in a quarter, it would not need to file to recertify for that quarter. However, if in 

the next quarter the rooftop solar QF increased its power production capacity by 0.9 MW, 

it would need to recertify for that quarter because cumulatively over the quarters since its 

last filing it has changed its power production capacity by more than 1 MW (i.e., under 

this example the rooftop solar QF changed its power production capacity since its last 

recertification filing by 1.8 MW).

884 Similarly, when the Commission issues an order affirmatively certifying an

applicant’s QF status (in response to a protest opposing a self-certification or selfrecertification, or in response to an application for Commission certification or 

recertification), any party to that proceeding aggrieved by the order, including the 

protestant, may seek rehearing and appeal pursuant to the FPA.

885 16 U.S.C. 796(17). Section 3(17) of the FPA mandates a size requirement for a 

small power production facility: it must have “a power production capacity which, 

together with any other facilities located at the same site (as determined by the 

Commission), is not greater than 80 megawatts.”

886 16 U.S.C. 796(18). 
Docket Nos. RM19-15-000 and AD16-16-000 - 316 -

Commission’s order revoking QF certification is subject to rehearing and appeal pursuant 

to FPA section 313.887

562. El Paso Electric states that sometimes the utility does not know to protest, because 

sometimes QFs fail to provide utilities with their QF application, and El Paso Electric is 

therefore concerned by the Commission’s proposal to limit protests by requiring that once 

the Commission has affirmatively certified an applicant’s QF status, any later protest must 

demonstrate changed circumstances. We note that a QF that is filing a FERC Form No. 

556 is currently required by 18 CFR 292.207(c) (which we are not altering in this rule 

except to renumber as 18 CFR 292.207(e)) to serve a copy on each electric utility with 

which it expects to interconnect, transmit or sell electric energy to, or purchase 

supplementary, standby, back-up or maintenance power from, and the state regulatory 

authority of each state where the facility and each affected utility is located. This final 

rule does not change that requirement and we expect applicants to timely comply with that 

regulation. Should an issue arise, though, the Commission can address it on a case-bycase basis as the circumstances warrant. Additionally, we note that, if a self-certification

887 16 U.S.C. 825l. The Commission has previously entertained rehearing of an

order revoking QF status, Golden Valley Elec. Ass'n, Inc., 167 FERC ¶ 61,208 (2019),

reh’g denied, 170 FERC ¶ 61,025 (2020), and of an order denying petitions to revoke

QF status, N. Laramie Range All., 138 FERC ¶ 61,171, reh’g denied, 139 FERC ¶

61,190 (2012), appeal dismissed, 733 F.3d 1030. There have also been appeals of

orders denying petitions to revoke QF status. N. Laramie Range All. v. FERC, 733 F.3d 

1030 (10th Cir. 2013) (dismissing appeal on other grounds); Brazos Elec. Power Coop. 

Inc., v. FERC, 205 F.3d 235 (5th Cir. 2000) (denying petition for review). Unlike 

PURPA section 210, PURPA section 201 amends the FPA and is therefore subject to 

FPA section 313. See Portland Gen. Elec. Co. v. FERC, 854 F.3d 692, 700 (2017); 

Midland Power Coop. v. FERC, 774 F.3d 1, 3 (2014).
Docket Nos. RM19-15-000 and AD16-16-000 - 317 -

or self-recertification is not protested within the 30 day-period permitted for protests, then, 

just as it could prior to this final rule, a challenger still has the ability to file a petition for 

declaratory order, with the filing fee, without being required to show changed 

circumstances to do so. 

563. Regarding Basin’s request to allow petitions seeking de-certification of QFs that 

have previously filed self-certifications and ultimately never proceed to development,888

as we note above we limit the ability to file a protest (rather than a petition for declaratory 

order, with the accompanying filing fee) to within 30 days of the date of the filing of the 

self-certification or self-recertification. If an interested party would like to contest a selfcertification or self-recertification later than 30 days after the date of its filing, then the 

interested party may file a petition for declaratory order with the accompanying filing fee, 

just as they could prior to the effective date of this final rule. 

564. We decline to adopt the requests that QF developers seeking certification with the 

Commission be required to publish notice in local newspapers in the states in which the 

development would be located. We find that the service requirement already in our 

regulations cited above should serve to provide adequate notice to affected entities. 

565. We decline to impose a 60-day deadline after which a failure of the Commission to 

rule on the protest results in the protest being denied by operation of law. Selfcertification will be effective upon filing and we adopt the NOPR proposal that the selfcertifications will remain effective after a protest has been filed, until such time as the 

888 Basin Comments at 11.
Docket Nos. RM19-15-000 and AD16-16-000 - 318 -

Commission issues an order revoking certification. We also clarify that selfrecertifications will likewise remain effective after a protest has been filed, until such time 

as the Commission issues an order revoking certification. 

566. We also will adopt the NOPR’s proposed timeline for issuance of an order 

following protests to a QF self-certification and self-recertification. The Commission will 

issue an order within 90 days of the filing of a protest. However, if the Commission 

requests more information, the time period for the Commission order would be extended 

to 60 days from the filing of a complete answer to the information request. In addition to 

any extension resulting from a request for information, the Commission also may toll the 

90-day period during which the Commission commits to act for one additional 60-day 

period. We clarify, however, that, absent Commission action by the date of the expiration 

of the tolling period, a protest will be deemed denied, and the self-certification or selfrecertification will remain effective. We find that this timeline provides both QFs and 

other interested persons with certainty about the QFs’ status within a reasonable amount 

of time.

567. Regarding Ares’ concern that small power production QFs could be aggregated 

under the new rule without being aware of the other small power production QFs with 

which they are aggregated, the Commission notes that this concern would only apply to 

small power production facilities owned by the same person or its affiliates; it is unlikely 

that the owner(s) of one facility would not be aware of other, affiliated QFs. Furthermore, 

the presumption continues to be that a small power production facility seeking QF status 

that is located more than one but less than 10 miles from any affiliated small power 
Docket Nos. RM19-15-000 and AD16-16-000 - 319 -

production QFs is at a separate site from those affiliated small power production QFs, and 

the Commission here is simply making this presumption rebuttable. If an entity 

challenges that presumption, the applicant seeking QF status would necessarily be served 

with the protest889 and thus informed of the challenge, and given the opportunity to defend 

against the challenge. 

568. Regarding Solar Energy Industries contention regarding the currently pending 

Connected Entity proceeding, that is a separate proceeding and beyond the scope of this 

proceeding. Moreover, the data collection at issue in that proceeding does not eliminate 

the need for the Commission to collect the data required by the FERC Form No. 556 so 

that the Commission has the information it needs to determine whether a facility qualifies 

to be a QF consistent with the standards laid out in the statute. In any event, we note that 

the Connected Entity rulemaking was about market-based rate sellers, not QFs, and it is 

likely that the Connected Entity rulemaking would not apply to many QFs in the first 

place since they often nether seek nor have the authority to sell at market-based rates. 

569. Regarding Allco’s concerns about the RFA, we discuss the RFA issue in section 

VII.

F. Corresponding Changes to the FERC Form No. 556

1. NOPR Proposal

570. The Commission proposed changes to the FERC Form No. 556, corresponding to 

the new rules discussed above regarding whether QFs are at separate sites. Currently, 

889 18 CFR 385.211(b).
Docket Nos. RM19-15-000 and AD16-16-000 - 320 -

item 8a of FERC Form No. 556 requires that the applicant identify any facilities with 

electrical generating equipment within one mile of the instant facility’s electrical 

generating equipment, as shown below:

571. The Commission proposed adding a new item 8b,890 which would be similar to the 

current item 8a, except that it would cover affiliated facilities whose nearest electrical 

generating equipment is greater than 1 mile and less than 10 miles from the electrical 

generating equipment of the instant facility. 

572. The Commission proposed that the instructions for the new item 8b would also 

allow applicants with facilities identified under item 8b (i.e., facilities more than one mile 

apart and less than 10 miles apart) to, if they choose, explain (in the Miscellaneous section 

starting on page 19 of the form) why the facilities identified under item 8b should be 

considered separate facilities,891 considering the relevant physical and ownership factors. 

890 Subsequent items in that section of the FERC Form No. 556 would be retained 

but re-numbered and moved down accordingly.

891 As discussed in detail in section IV.D.1.d, this final rule will change the 

references to “separate facilities” or “the same facility” to “at separate sites” or “at the 

same site.”
Docket Nos. RM19-15-000 and AD16-16-000 - 321 -

The Commission further proposed to provide reference, in the instructions to the new item 

8b, to the paragraphs of this final rule which discuss the relevant physical and ownership 

factors that may be asserted to defend against rebuttal.

573. The Commission sought comment on whether item 8a (existing) should be revised 

and item 8b (as proposed) written to require that the applicant specify the distance from 

the instant facility to each affiliated facility listed. We also sought comment on whether 

items 8a and (new) 8b should require the applicant to document (in the Miscellaneous 

section on page 19 of the FERC Form No. 556) how the distances reported were 

calculated. Specifically, we sought comment on whether the applicant should be required 

to identify the particular electrical generating equipment and associated geographic 

coordinates used in calculating the distance(s) between the facilities.

574. The Commission noted that item 8a currently requires applicants to list all affiliated 

“facilities.” Under this requirement, an applicant would have to list all affiliated QFs as 

well as affiliated non-QFs. We requested comment on whether such a requirement is

more burdensome than necessary. It was not clear that requiring the listing of affiliated 

non-QFs is necessary in monitoring for compliance with the relevant QF regulations, 

which are concerned only with the distance between affiliated QFs. 

575. The Commission also sought comment on whether item 3c (geographic 

coordinates) and the Geographic Coordinates instructions on page 4 of the current FERC 

Form No. 556 should be modified such that reporting of geographic coordinates should be 

required for all applications, rather than only for applications where there is no facility 

street address (as has been the case). We believed such information may provide more 
Docket Nos. RM19-15-000 and AD16-16-000 - 322 -

transparency in measuring distances between facilities, and that such transparency may be 

useful for both the public and Commission staff in monitoring compliance with the 

Commission’s QF regulations. 

576. The Commission noted, as it did in Order No. 732,892 and as in the general form 

instructions on page 4 of the FERC Form No. 556, that such coordinates can be obtained 

through certain free online map services (with links and instructions available through the 

Commission’s QF website); GPS devices (including smartphones, which are now nearly 

ubiquitous); Google Earth; property surveys; various engineering or construction 

drawings; property deeds; or municipal or county maps showing property lines. The 

Commission also noted that the Commission has a link on its QF webpage 

(https://www.ferc.gov/industries-data/electric/power-sales-and-markets/purpa-qualifyingfacilities) which provides assistance with determining geographic coordinates of facilities. 

As such, the Commission believed that the burden that would be created by requiring 

every QF to provide geographic coordinates would be limited. Even so, the Commission

sought comment on whether the value of the information to the public and the 

Commission would outweigh the limited burden.

892 Revisions to Form, Procedures, and Criteria for Certification of Qualifying 

Facility Status for a Small Power Production or Cogeneration Facility, Order No. 732, 

130 FERC ¶ 61,214, at P 100 (2010).
Docket Nos. RM19-15-000 and AD16-16-000 - 323 -

2. Comments

577. A few commenters oppose the changes to FERC Form No. 556 as proposed in the 

NOPR.893 Solar Energy Industries and the Southeast Public Interest Organizations 

contend that the proposed new item 8b that requests a list of all affiliated facilities within 

one to 10 miles from the certifying QF would be a significant increase in information 

collection, time, effort, and cost of QF certification.894 

578. The Southeast Public Interest Organizations further object that the obligation to 

show how distances are calculated and to identify electrical generating equipment and 

their associated geographic coordinates are overly burdensome for facilities that are 

presumed to be separate and contradicts the rebuttable presumption of separate facilities, 

which usually places the burden on the challenger.895 

579. The Southeast Public Interest Organizations also assert it would be reasonable to ask 

for only affiliated QFs and to exclude non-QF affiliates from the questions in item 8.896

580. Several commenters support changes to FERC Form No. 556 as proposed in the 

NOPR.897 A few commenters support the proposed changes to item 8a and proposed new 

893 Solar Energy Industries Comments at 8; Southeast Public Interest Organizations

Comments at 36-37.

894 Solar Energy Industries Comments at 56; Southeast Public Interest 

Organizations Comments at 36-37.

895 Southeast Public Interest Organizations Comments at 37-38.

896 Id.

897 APPA Comments at 23; EEI Comments at 50; Portland General Comments at 

17-18; Subsurface Engineering Association Comments at 1.
Docket Nos. RM19-15-000 and AD16-16-000 - 324 -

item 8b and argue that the additional information might be otherwise difficult to find and 

will be useful to clarify if the assumption of separate facilities is appropriate.898 Some 

commenters support requiring all applicants to supply geographic coordinates in item 3c, 

regardless of whether they have a street address.899 

581. Two commenters support the collection of information for all affiliated facilities, 

not just QF affiliates, within the one or ten-mile radius requested in item 8a and proposed 

item 8b, respectively, because they believe it will be needed to identify QFs not 

complying with the proposed rule.900

582. Solar Energy Industries assert that the proposed item 8b to the Form No. 556, 

requiring a listing of all affiliated facilities whose nearest electrical generating equipment 

is greater than one mile and less than 10 miles from the electrical generating equipment of 

the certifying QF, is a substantial expansion of the information collection requirements 

and goes against the Commission’s previously-granted blanket exemptions for QFs to 

relieve the burden of public utility regulation. Solar Energy Industries argue that this is 

not a mere information collection requirement, but a request for information that is not 

otherwise publicly available and is inconsistent with the Commission’s finding on the 

burden of collecting Connected Entity information. Solar Energy Industries argue that 

898 APPA Comments at 23-24; EEI Comments at 50.

899 EEI Comments at 50; Idaho Commission Comments at 7; Subsurface 

Engineering Association Comments at 1.

900 EEI Comments at 50-51; Portland General Comments at 18.
Docket Nos. RM19-15-000 and AD16-16-000 - 325 -

collecting such information from QFs is unwarranted discriminatory treatment and is 

arbitrary and capricious.901

583. A few commenters requested additional changes to FERC Form No. 556.902 North 

American-Central would like the Commission to create separate Form No. 556 forms for 

small power producers and cogeneration QFs for a more distinct and simplified

application process.903 EEI would like Form No. 556 to explicitly include battery 

storage.904 EEI requests that the Form No. 556 collect information on the rated capacity 

and notes that net capacity may not be the appropriate measure of power production. 

Solar Energy Industries also noted that the Commission stated in Order No. 732 that 

future changes to Form No. 556 would not go through a rulemaking and would instead be 

reviewed by the Office of Management and Budget with a period for public comments.905 

3. Commission Determination 

584. We adopt the NOPR proposals regarding changes to the FERC Form No. 556, with 

the further clarifications and additions described below. The revised Form No. 556 will 

be attached to this rule in eLibrary, but will not be published in the Federal Register or 

Code of Federal Regulations. The Commission finds that the added information collected 

901 Solar Energy Industries Comments at 56-57.

902 EEI Comments at 51; El Paso Electric Comments at 5-6; North AmericanCentral Comments at 7.

903 North American-Central Comments at 7.

904 EEI Comments at 51-52.

905 Solar Energy Industries Comments at 56.
Docket Nos. RM19-15-000 and AD16-16-000 - 326 -

by these changes is necessary to implement the changes made to the regulations in this 

final rule, and thus justifies the increase in reporting burden. 

585. The currently effective Form No. 556 contains a “Who Must File” section which 

specifies when an applicant seeking QF status or recertification of QF status must file a 

self-certification, and when such applicant is exempt from the filing requirement. We will 

revise the “Who Must File” section to clarify that the exemption from the requirement to 

complete or file a Form No. 556 applies to an applicant seeking QF status for a small 

power production facility that, together with any affiliated small power production QFs 

within one mile of the entity seeking small power production QF status, has a net power 

production capacity of 1 MW or less. While we did not seek comment on this corrective 

change in the NOPR, this change is consistent with the Commission’s determination in 

SunE B9 Holdings LLC, 906 and serves to make the Form No. 556 more transparent in its 

application.

586. We also revise the “Who Must File” section to include a “Recertification” section 

which provides the text of revised 18 CFR 292.207(f), (previously 18 CFR 292.207(d))

which states that a QF must file for recertification whenever the QF “fails to conform with 

any material facts or representation presented . . . in its submittals to the Commission.”907 

906 157 FERC ¶ 61,044 at P 16 (“the one-mile rule of section 292.204(a)(2) is a size 

determination which the Commission has consistently applied generally to the regulations 

pursuant to PURPA, and which applies here to determining the applicability of the lessthan-1-MW exemption of section 292.203(d)”) (internal citations omitted).

907 18 CFR 292.207(d).
Docket Nos. RM19-15-000 and AD16-16-000 - 327 -

This addition does not alter our recertification requirements, and we include it here simply 

to make the Form No. 556 clearer in its application. 

587. The total burden estimates in the “Paperwork Reduction Act Notice” section of 

FERC Form No. 556 will be updated based on the changes in this final rule, to provide the 

following estimates: 1.5 hours for self-certifications of facilities of 1 MW or less; 1.5 

hours for self-certifications of a cogeneration facility over 1 MW; 50 hours for 

applications for Commission certification of a cogeneration facility; 3.5 hours for selfcertifications of small power producers over 1 MW and less than a mile or more than 10 

miles from affiliated small power production QFs that use the same energy resource; 56 

hours for an application for Commission certification of a small power production facility 

over 1 MW and less than a mile or more than 10 miles from affiliated small power 

production QFs that use the same energy resource; 9.5 hours for self-certifications of 

small power producers over 1 MW with affiliated small power production QFs more than 

one but less than 10 miles that use the same energy resource; 62 hours for an application 

for Commission certification of a small power production facility over 1 MW with 

affiliated small power production QFs more than one but less than 10 miles that use the 

same energy resource.

588. We find that an explanatory “Protest to the Filing” section should be added to the 

FERC Form No. 556 to note that, pursuant to 18 CFR 292.207, an interested person or 

entity has 30 days from the date of the filing of the FERC Form No. 556 to intervene or 

file a protest. The “Protest to the Filing” section will state that the protestor must 

concurrently serve a copy of such filing, pursuant to 18 CFR 385.211(b), on the Form No. 
Docket Nos. RM19-15-000 and AD16-16-000 - 328 -

556 applicant. The “Protest to the Filing” section will also state that the Form No. 556 

applicant will have 30 days to file any answer to a protest. The “Protest to the Filing” 

section will also state that protests may be made to any initial certification, and any 

recertifications on or after the effective date of this final rule making substantive changes

to the existing certification, which may include, for example, a change in electrical

generating equipment that increases power production capacity by the greater of 1 MW or

10 percent of the previously certified capacity of the QF, or a change in ownership in

which an owner increases their equity interest by at least 10% from the equity interest

previously reported. The “Protest to the Filing” section will note that “administrative 

only” changes will not be subject to protests.

589. The Commission finds that item 3c (geographic coordinates) and the Geographic 

Coordinates instructions on page 4 of the current FERC Form No. 556 will be revised to 

require all applicants to report the applicant facility’s geographic coordinates, rather than 

only for applications where there is no street address (as was the case previously). We 

find that such information will provide more transparency regarding the location of each

site, and that such transparency may be useful for both the public and Commission staff in 

monitoring compliance with the Commission’s QF regulations. 

590. The Commission will change item 8a, which currently requires applicants to list all 

affiliated facilities within one mile, to instead require that the applicant only list affiliated 

small power production QFs using the same energy resource within one mile.

591. We modify the NOPR’s proposal to add the collection of information for affiliated 

facilities whose nearest electrical generating equipment is more than one but less than 10 
Docket Nos. RM19-15-000 and AD16-16-000 - 329 -

miles from the electrical generating equipment of the applicant’s facility to instead add the 

collection of information for affiliated small power production QFs using the same energy 

resource located more than one mile but less than 10 miles from the electrical generating 

equipment of the applicant’s facility. However, rather than adding a separate item 8b to 

the Form No. 556 specifically for such QFs, as proposed in the NOPR, we are expanding 

the existing item 8a to require the applicant to list all affiliated small power production

QFs using the same energy resource whose nearest electrical generating equipment is less 

than 10 miles from the electrical generating equipment of the entity seeking small power 

production QF status. 

592. We determine that the revised item 8a will require the applicant to list the

geographic coordinates of the nearest “electrical generating equipment” of both its own 

facility and the affiliated small power production QF in question based on the definitions 

adopted in this final rule. The distance between the entity seeking small power production 

QF status and each affiliated small power production QF will be automatically calculated 

based on these coordinates. For any affiliated small power production QFs that cannot be 

described in item 8a due to space limitations, the instructions will direct applicants to 

provide the required information for such small power production QFs in the 

Miscellaneous section of the form. To facilitate the uniform calculation of distances for 

facility data that are entered into the Miscellaneous section of the form, a distance 

calculator will be added to the form, and the form instructions will direct applicants to use 

the calculator to convert their facilities’ geographic coordinates into distance. 
Docket Nos. RM19-15-000 and AD16-16-000 - 330 -

593. The Commission also adopts the NOPR proposal to allow applicants with affiliated 

small power production QFs greater than one mile and less than 10 miles from the 

electrical generating equipment of the entity seeking small power production QF status

identified under item 8a to, if they choose, explain why the affiliated small power 

production QFs greater than one mile and less than 10 miles from the nearest electrical 

generating equipment of the entity seeking QF status identified under item 8a should be 

considered to be at separate sites from the entity seeking QF status, considering the 

relevant physical and ownership factors. The instructions will provide references to the 

relevant physical and ownership factors, as defined in this final rule, that may be asserted 

to defend against rebuttal. 

594. Regarding Solar Energy Industries’ concern regarding the expansion of the 

information collection requirements, we find that the added information collected by item 

8a of the Form No. 556 is necessary to implement the changes made to the regulations in 

this final rule, and thus justifies the increase in reporting burden. As noted in section 

IV.E, the currently pending Connected Entity proceeding is a separate proceeding and 

beyond the scope of this proceeding. Moreover, the data collection at issue in that 

proceeding does not eliminate the need for the Commission to collect the data required by 

the FERC Form No. 556 so that the Commission has the information it needs to determine 

whether a facility qualifies to be a QF consistent with the standards laid out in the statute. 
Docket Nos. RM19-15-000 and AD16-16-000 - 331 -

595. We note that these changes and any future changes to Form No. 556 will continue 

to be reviewed by the Office of Management and Budget following solicitation of 

comments from the public, as described in Order No. 732.908 

596. We find the requests for additional changes to FERC Form No. 556 beyond the 

scope of this proceeding. 

G. PURPA Section 210(m) Rebuttable Presumption of Nondiscriminatory 

Access to Markets

1. PURPA Section 210(m) Implementation

a. NOPR Proposal 

597. In 2006, when Order No. 688 was issued, the organized electric markets had been 

in existence for only a few years and were not well understood by all market participants. 

Now, fourteen years later, the markets are more mature, and the mechanics of 

participation in such markets are improved and better understood. Consequently, in the 

NOPR, the Commission determined that small power production facilities below 20 MW 

should now be able to participate in such markets under most circumstances. The 

Commission therefore proposed to revise 18 CFR 292.309(d) to reduce the net power 

production capacity level at which the presumption of nondiscriminatory access to a 

market attaches for small power production facilities, but not cogeneration facilities, from 

20 MW to 1 MW. 

908 Order No. 732, 130 FERC ¶ 61,214.
Docket Nos. RM19-15-000 and AD16-16-000 - 332 -

598. The Commission determined that, in light of the maturation of organized electric 

markets, such a reduction was consistent with Congress’s intent to relieve electric utilities 

of their obligation to purchase when a QF has nondiscriminatory access to competitive 

markets. 

599. The Commission noted that, in establishing the original presumption that QFs 

whose net power production capacity was 20 MW or below lacked nondiscriminatory 

access to markets defined in sections 210(m)(1)(A)-(C) of PURPA, it had acknowledged 

that “there is no unique and distinct megawatt size that uniquely determines if a generator 

is small.”909 The Commission noted that, in using 20 MW to separate the presumption 

that large QFs had nondiscriminatory access and small QFs lacked such access, the 

Commission had recognized: (1) Order No. 671’s exemption for QFs that are 20 MW or 

smaller from sections 205 and 206 of the FPA; and (2) Order Nos. 2006 and 2006-A’s 

setting 20 MW as the demarcation for different interconnection standards between small 

and large generators.910 The NOPR stated that, while the Commission had not (and 

909 Order No. 688-A, 119 FERC ¶ 61,305 at P 97.

910 See Order No. 688, 117 FERC ¶ 61,078 at P 76, order on reh’g, Order No. 688-A, 

119 FERC ¶ 61,305 at P 97; see also 18 CFR 292.601(c)(1) (“[S]ales of energy or capacity 

made by qualifying facilities 20 MW or smaller, or made pursuant to a contract executed on 

or before March 17, 2006 or made pursuant to a state regulatory authority’s implementation 

of section 210 the Public Utility Regulatory Policies Act of 1978, 16 U.S.C. 824a-1, shall be 

exempt from scrutiny under sections 205 and 206.”); Revised Regulations Governing Small 

Power Production and Cogeneration Facilities, Order No. 671, 114 FERC ¶ 61,102, at P 

98, order on reh’g, Order No. 671-A, 115 FERC ¶ 61,225 (2006) (establishing exemption 

for QFs 20 MW or below from 205 and 206 of FPA); Standardization of Small Generator 

Interconnection Agreements and Procedures, Order No. 2006, 111 FERC ¶ 61,220, at P 75, 

order on reh’g, Order No. 2006-A, 113 FERC ¶ 61,195 (2005), order granting clarification, 
Docket Nos. RM19-15-000 and AD16-16-000 - 333 -

likewise did not in the NOPR) propose to revise the exemptions for QFs from sections 205 

and 206 of the FPA, the Commission had elsewhere taken steps to ease both 

interconnection and market access for generation resources with small capacities since it 

first implemented section 210(m) of PURPA. 

600. For example, the Commission noted that it had required public utilities to provide a 

Fast-Track interconnection process for some interconnection customers whose capacity is 

up to and including 5 MW (up from the previous 2 MW threshold),911 and had required 

each RTO/ISO to revise its tariff to include a participation model for electric storage 

resources that establishes a minimum size requirement for participation in the RTO/ISO 

markets that does not exceed 100 kW.912 While both of these changes do not apply only 

to generation types that could become QFs or only to RTOs/ISOs, the Commission stated 

that it believed they generally show that small power production facilities below 20 MW, 

specifically those whose capacity exceeds 1 MW, now have greater access to the markets 

defined in section 210(m)(1) of PURPA than they did when the Commission first 

established the presumptions of market access. The Commission also stated that, under

the NOPR proposal and like QFs over 20 MW today, small power production facilities 

Order No. 2006-B, 116 FERC ¶ 61,046 (2006).

911 Small Generator Interconnection Agreements and Procedures, Order No. 792, 

145 FERC ¶ 61,159, at P 103 (2013), clarifying, Order No. 792-A, 146 FERC ¶ 61,214 

(2014).

912 Order No. 841, 162 FERC ¶ 61,127 at P 265.
Docket Nos. RM19-15-000 and AD16-16-000 - 334 -

over 1 MW would still be able to rebut the presumption of access due to operational 

characteristics or transmission constraints.913

601. The Commission did not propose to make the same reduction applicable to 

cogeneration facilities. The Commission stated that, unlike small power production 

facilities, which are constructed solely to produce and sell electricity, cogeneration 

facilities seeking QF certification after February 2, 2006 are statutorily required to show 

that they are intended primarily to provide heat for an industrial, commercial, residential 

or institutional process rather than fundamentally for sale to an electric utility.914 

Consequently, the production and sale of electricity is a byproduct of these thermal 

processes, and owners of cogeneration facilities might not be as familiar with energy 

markets and the technical requirements for such sales. The Commission stated that 

retention of the existing 20 MW level for the presumption of access to markets therefore 

would be appropriate for cogeneration facilities.

b. Comments in Opposition

602. Numerous commenters oppose the NOPR proposal to revise 18 CFR 292.309(d) to 

reduce the net power production capacity level at which the presumption of 

913 See 18 CFR 292.309(c), (e), (f).

914 See 16 U.S.C. 824a-3(n); 18 CFR 292.205(d)(3). We recognize that 

cogeneration facilities seeking certification 5 MW or smaller after February 2, 2006 are 

presumed to satisfy this requirement. 18 CFR 292.205(d)(4).
Docket Nos. RM19-15-000 and AD16-16-000 - 335 -

nondiscriminatory access to a market attaches for small power production facilities, but 

not cogeneration facilities, from 20 MW to 1 MW.915

i. Insufficient Evidentiary Support

603. Several commenters argue that the record does not support the proposal.916

604. Advanced Energy Economy asserts that, when an agency reverses course on a 

policy issue, and the “new policy rests upon factual findings that contradict those which 

underlay” the previous policy, then the agency must “provide a more detailed justification 

than what would suffice for new policy created on a blank slate.”917 Advanced Energy 

Economy argues that the NOPR falls short of that standard.918

915 Allco Comments at 2, 17-19; Advanced Energy Economy Comments at 1-12; 

AllEarth Comments at 2; Biogas Comments at 2-3; Biological Diversity Comments at 8-9; 

California Commission Comments at 31-33; CARE Comments at 5-6; Con Edison 

Comments at 5; Covanta Comments at 10-12; DC Commission Comments at 4-5; 

Distributed Sun Comments at 2-3; ELCON Comments at 18, 31-35; Energy Recovery 

Comments at 4-5; ENGIE Comments at 3-4; Commissioner Slaughter Comments at 2, 4; 

Green Power Comments at 3; Industrial Energy Consumers Comments at 6-10; 

Massachusetts AG Comments at 6-8; Michigan Commission Comments at 6-7; North 

American-Central at 2-4; One Energy Comments at 2; South Dakota Commission 

Comments at 5; Solar Energy Industries Comments at 44-51; State Entities Comments at 

5-6; Western Resource Councils Comments at 1-144.

916 AllEarth Comments at 2; Advanced Energy Economy Comments at 5-9; 

Biological Diversity Comments at 9; ELCON Comments at 31-32; Industrial Energy 

Consumers Comments at 8; New England Hydropower Comments at 11-12; NIPPC, 

CREA, REC, and OSEIA Comments at 77; Public Interest Organizations Comments at 

76-78; SC Solar Alliance Comments at 12; Solar Energy Industries Comments at 45-48;

Southeast Public Interest Organization Comments at 39-40.

917 Advanced Energy Economy Comments at 6 (citing FCC v. Fox Television 

Stations, Inc., 556 U.S. at 515).

918 Id. at 7. 
Docket Nos. RM19-15-000 and AD16-16-000 - 336 -

605. Public Interest Organizations and NIPPC, CREA, REC and OSEI argue that the 

Commission fails to cite any evidence supporting the premise that the markets are more 

mature, and that the mechanics of participation in such markets are improved and better 

understood. Public Interest Organizations and NIPPC, CREA, REC, and OSEIA state that 

the Commission asserts that QFs smaller than 20 MW can now participate in markets on a 

nondiscriminatory basis “under most circumstances,” but that the Commission does not 

explain what those “circumstances” are, or whether they apply as a general matter to most 

small QFs.919

606. Several commenters state that, in Order No. 688-A, the Commission, rejected

utility proposals to set the threshold at 1 MW, and confirmed that 20 MW was an 

appropriate threshold.920 Advanced Energy Economy states that the Commission’s 

explanation in Order No. 688-A, which stated that the rebuttable presumptions were based 

on the Commission’s experience of implementing non-discriminatory open access 

transmission over the past 11 years, dealing with QF issues over the past 29 years and its 

experience with RTO/ISO markets for almost 10 years, contradicts the Commission’s 

justification in the NOPR of limited experience with organized electric markets.921 

Advanced Energy Economy and Southeast Public Interest Organizations assert that, since 

919 Public Interest Organizations Comments at 78; NIPPC, CREA, REC, and 

OSEIA Comments at 77 (citing NOPR, 168 FERC ¶ 61,184 at P 126).

920 Advanced Energy Economy Comments at 5-6; ELCON Comments at 31-32.

921 Advanced Energy Economy Comments at 8-9.
Docket Nos. RM19-15-000 and AD16-16-000 - 337 -

Order No. 688, the Commission has repeatedly found that utilities in organized markets 

have failed to rebut the presumption of nondiscriminatory access to QFs, instead finding 

that QFs 20 MW and under do not have sufficient access.922

607. Public Interest Organizations and NIPPC, CREA, REC, and OSEIA argue that the 

Commission fails to explain the relevance of its Fast-Track interconnection process or 

energy storage order or which barriers these developments alleviate for small QFs’ access 

to markets.923 Advanced Energy Economy asserts that the expansion of the Fast-Track 

procedures only applied to a narrow slice of inverter-based resources under 20 MW and is 

insufficient to support a rebuttable presumption that all QFs under 20 MW have 

nondiscriminatory access.924

608. Solar Energy Industries and New England Hydro argue that, just because some 

small QFs participate in energy markets, that is not sufficient justification to find that all 

small QFs meet the statutory standard required for granting waiver for all QFs 20 MW or 

922 Id. (citing, e.g., PPL Elec. Utils Corp., 145 FERC ¶ 61,053, at P 24 (2013); City 

of Burlington, 145 FERC ¶ 61,121, at P 36 (2013); Fitchburg Gas and Elec. Light Co., 

146 FERC ¶ 61,186, at PP 32-33 (2014); Va. Elec. & Power Co., 151 FERC ¶ 61,038, at 

P 21 (2015); N. States Power Co., 151 FERC ¶ 61,110 (2015)); Southeast Public Interest 

Organizations Comments at 39-40.

923 NIPPC, CREA, REC, and OSEIA at 77; Public Interest Organizations 

Comments at 78 (citing Motor Vehicle Mfrs. Ass’n of U.S., Inc. v. State Farm Mut. Auto. 

Ins. Co., 463 U.S. 29, 43 (1983) (explaining that an agency’s failure to consider the 

relevant factors and supply a “rational connection between the facts found and the choice 

made” renders its decision arbitrary and capricious)). 

924 Advanced Energy Comments at 7-8.
Docket Nos. RM19-15-000 and AD16-16-000 - 338 -

less.925 Public Interest Organizations assert that proper implementation of section 210(m) 

requires that exemption from the mandatory purchase obligation only applies where QF 

development will be stimulated by market forces; otherwise Congress intended QF 

development to continue to be encouraged by the mandatory purchase obligation.926

Protesters assert that the record does not provide evidence that could reasonably allow the 

Commission to conclude that small QF development will be stimulated by market forces. 

On the contrary, the Public Interest Organizations assert that the Commission’s proposal 

placing the burden on small QFs to rebut the presumption of access is itself a barrier to QF 

development.927

609. Solar Energy Industries argue that, along with the energy markets, the capacity 

markets in the RTO/ISO regions have not evolved to provide a meaningful opportunity for 

any QF to sell long-term capacity.928 Solar Energy Industries argue that PURPA section 

210(m) requires the Commission to find that a QF has nondiscriminatory access to a 

market for long-term sales of capacity prior to relieving the purchase obligation. Solar 

Energy Industries provide several examples such as MISO’s Planning Resources Auction 

925 Solar Energy Industries Comments at 46; New England Hydro Comments at 11-

12.

926 Public Interest Organizations Comments at 76 (citing New PURPA Section 

210(m) Regulations Applicable to Small Power Production and Cogeneration 

Facilities, Order No. 688, 117 FERC ¶ 61,078, at P 6 (2006), order on 

reh'g, Order No. 688-A, 119 FERC ¶ 61,305 (2007), aff'd sub nom. Am. Forest and Paper 

Ass'n v. FERC, 550 F.3d 1179).

927 Id. 

928 Solar Energy Industries Comments at 45.
Docket Nos. RM19-15-000 and AD16-16-000 - 339 -

that only provides a one-year purchase agreement, PJM not purchasing capacity since the 

Commission’s July 2019 Order, and that SPP does not have a centralized capacity market. 

Solar Energy Industries argue that without a specific finding that RTO/ISO markets 

provide QFs with an opportunity to sell long-term capacity, the Commission is statutorily 

required to maintain utilities’ obligation to purchase output from QFs 20 MWs or less.929

610. Mr. Mattson asserts, without elaboration, that FPA sections 205 and 206 disallow 

the Commission from lowering the nondiscriminatory access threshold from 20 MW to 1 

MW, and, therefore, claims it would amount to a violation of state-jurisdictional rights and 

a taking of property.930

ii. Administrative Burden and Complex Market Rules

611. The DC Commission state that QFs 20 MW or less lack the capability to participate 

in a complicated wholesale market such as PJM where there is a need to understand 

membership obligations and rules in order to appropriately execute transactions.931

612. Allco argues that, in retail choice states, PURPA is the only way small QFs can sell 

to utilities. Allco asserts that in retail choice states there is a shifting retail customer base, 

therefore utilities want obligations reduced and contracts limited to a year. Allco asserts 

that utilities and state commissions cannot limit contracts due to a potentially disappearing 

customer base and then argue that a sufficient wholesale market exists for long-term sales 

929 Id. at 49.

930 Mr. Mattson Comments at 10.

931 DC Commission Comments at 4-5.
Docket Nos. RM19-15-000 and AD16-16-000 - 340 -

of electric energy and capacity to support nondiscriminatory access for small QFs under 

20 MW.

932

613. Public Interest Organizations argue that giving special exemptions to cogeneration 

facilities is discriminatory against small power producer QFs.933 Two commenters also 

assert that small QFs are at an inherent disadvantage compared to larger QFs because 

smaller QFs are often engaged in other business enterprises, such as governmental units 

distributing irrigation water or local companies unfamiliar with energy markets.934

c. Comments in Support

614. Numerous commenters support the proposal to revise 18 CFR 292.309(d) for small 

power production facilities but not cogeneration facilities, to reduce the net power 

production capacity level at which the presumption of nondiscriminatory access to a 

market applies from 20 MW to 1 MW.935 DTE Electric argues that RTO/ISOs can now 

932 Allco Comments at 18. 

933 Public Interest Organizations Comments at 74.

934 NIPPC, CREA, REC, and OSEIA Comments at 18-19, 24-25; Mr. Mattson 

Comments at 15.

935 Alliant Energy Comments at 13-16; Tax Reform Comments at 2; APPA 

Comments at 24-26; Arizona Public Service Comments at 8-10; Basin Comments at 12-

13; Freedom Center Comments at 2; Colorado Independent Energy Comments at 14; 

Connecticut Commission Comments at 21-22; Conservative Action Comments at 2; 

Consumers Alliance Comments at 1-2; Consumers Energy Comments at 4-5; DTE 

Electric Comments at 4-5; East Kentucky Comments at 3; East River Comments at 2; EEI 

Comments 54-59; FirstEnergy Comments at 2-3; Idaho Power comments at 14; Indiana 

Municipal Comments at 6-9; Institute for Energy Research Comments at 2; Kentucky 

Commission Comments at 8; Missouri River Energy Comments at 3-4; NorthWestern at 

14; TAPS Comments at 4; Ohio Commission Energy Advocate Comments at 8; Taxpayers 

Protection Alliance Comments at 2; Chamber of Commerce Comments at 7; We Stand 
Docket Nos. RM19-15-000 and AD16-16-000 - 341 -

provide smaller resources non-discriminatory access, and therefore electric utilities should 

no longer be required to purchase electric energy from them.936 EEI supports the proposal 

because resource diversity has improved and markets have evolved as smaller resources, 

including QFs, are increasingly participating in the RTO/ISO markets. RTOs/ISOs have 

also increasingly adjusted their bidding rules, forecasts, and operations to better 

accommodate variable resources.937 Alliant and the Ohio Commission Energy Advocate 

state that small resources have increased access to wholesale markets and that RTO/ISO 

rule flexibility allows for the non-discriminatory participation of very small resources and 

the aggregation of even smaller resources in the markets, therefore the 20 MW threshold 

is no longer appropriate.938

615. Consumer Alliance and EEI argue that reducing the threshold will reduce costs to 

customers because currently some QFs with access to markets are foregoing the 

opportunity to participate in those markets and electing to contract with electric utilities 

under state-implemented PURPA programs, which EEI argues compensate QFs at an 

above-market rate.939

Comments at 1-144; Taxpayer Protection Alliance Comments at 2; TAPS Comments at 4.

936 DTE Electric Comments at 5-6.

937 EEI Comments at 56-58.

938 Alliant Energy Comments at 13-14; Ohio Commission Energy Advocate 

Comments at 7-8.

939 EEI Comments at 58-59; Consumers Alliance Comments at 1-2.
Docket Nos. RM19-15-000 and AD16-16-000 - 342 -

616. The Ohio Commission Energy Advocate argues that the rebuttable presumption 

process for QFs provides an appropriate safety valve for the lower threshold.940

d. Comments Requesting Modifications/Clarifications

617. Institute for Energy Research requests that the Commission expand the rebuttable 

presumption of non-discriminatory access to QFs 1 MW and below if the market structure 

in a given state is appropriate. Institute for Energy Research gives the example of Texas’s

open market model, where generation is open to all comers of all sizes. Institute for 

Energy Research also suggests that the Commission should include some threshold now 

such that when other states achieve similar open access market designs QFs 1 MW and 

below could be rebuttably presumed to have non-discriminatory access to those markets, 

without the need to undertake, at that time, a separate rulemaking on QFs 1 MW and 

below.941

618. The Connecticut Commission suggests reducing the threshold at which the 

presumption of nondiscriminatory access attaches to 0 MW because the markets are more 

mature, the mechanics of participating in the markets are improved and the law requires 

nondiscriminatory access to the markets for all resources.

942 Missouri River Energy 

recommends lowering the threshold to 500 kW.943 FirstEnergy recommends the 

940 Ohio Commission Energy Advocate Comments at 8.

941 Institute of Energy Research Comments at 2.

942 Connecticut Commission Comments at 21-23. 

943 Missouri River Energy Comments at 3.
Docket Nos. RM19-15-000 and AD16-16-000 - 343 -

Commission treat both small power production resources and cogeneration resources 

consistently by lowering the rebuttable presumption threshold from 20 MW to 1 MW for 

all QFs.944 Indiana Municipal requests that the Commission automatically apply the 

1 MW threshold to utilities that have already been granted waiver for QFs over 20 MW to 

promote the efficient use of the Commission’s resources and savings to utilities.945

619. The Michigan Commission requests clarification on the NOPR proposal 

specifically regarding: (1) how existing contracts with QFs greater than 1 MW but below 

20 MWs are to be treated under the NOPR, and if they would be subject to early 

termination or would be granted legacy treatment indefinitely or until the end of the 

existing contract term; (2) whether utilities that have already received relief from the 

mandatory purchase obligation from the Commission for operating within the footprint of 

an organized wholesale electricity market automatically qualify for relief under the 1 MW 

threshold; and (3) how interconnection requirements would be considered for QFs 

between 1 MW and 20 MWs – specifically whether these projects would need to 

interconnect at transmission level voltages to be considered as having access to the 

wholesale electricity market.946 The Michigan Commission notes that there is some 

tension between the proposal and the market rules for MISO and PJM.947

944 FirstEnergy Comments at 2-3. 

945 Indiana Municipal Comments at 8-9.

946 Michigan Commission Comments at 6-7

947 Id. at 7 (commenting that MISO, for example, utilizes a 5 MW threshold as the 

cut off point for Network Modeling purposes and that resources less than 5 MW are 
Docket Nos. RM19-15-000 and AD16-16-000 - 344 -

620. Several commenters request that the Commission expand the exemption for 

cogeneration to small power QFs whose primary purpose is to self-supply but still rely on 

PURPA when making occasional sales to the interconnected utility when QF output 

exceeds on-site consumption.948 Industrial Energy Consumers suggest that small power 

producers seeking a 20 MW self-supply exemption meet the “fundamental use test” which 

currently applies to cogeneration facilities.949 Other commenters assert that behind-themeter distributed energy resources,950 Waste to Energy resources,951 and baseload 

renewables952 are similar to cogeneration facilities and should be included in the 

exemption.

621. Public Interest Organizations request that the Commission clarify that utilities are 

required to petition to eliminate the must-purchase obligation for small QFs, even for 

those utilities that have previously made such a showing for QFs larger than 20 MW.953 

NRECA, concerned over a potential change in aggregation for distributed energy 

resources in RTOs/ISOs, requests that the Commission clarify that the presumption will 

modeled on a case-by-case basis only).

948 ELCON Comments at 32-33; Industrial Energy Consumers Comments at 6-8; 

Chamber of Commerce Comments at 7.

949 Industrial Energy Consumers Comments at 9-10. 

950 One Energy Comments at 2.

951 Industrial Energy Consumers Comments at 9-10. 

952 Renewable Baseload Coalition Comments at 2.

953 Public Interest Organizations Comments at 76.
Docket Nos. RM19-15-000 and AD16-16-000 - 345 -

only apply to those facilities having sufficient transmission access to the RTO/ISO 

markets.954

622. Hydropower Association asserts that, despite their potential, hydropower resources 

do not receive the same tax treatment and eligibility for state RPSs and therefore have not 

enjoyed the same growth rate as other renewable energy small power producers. 

Hydropower Association urges the Commission to retain the 20 MW rebuttable 

presumption for hydropower resources, as would be the case for cogenerators, because 

hydropower resources are required by the FPA section 10(a) to be best adapted for 

comprehensive uses, including non-power generation purposes such as irrigation, flood 

control, navigation, recreation, environmental restoration, and wildlife preservation. 

Hydropower Association states that non-powered dams by definition were not constructed 

to generate power. Because power generation is therefore a secondary use of these 

facilities, Hydropower Association asserts that subjecting these facilities to new avoided

cost calculations will necessarily burden hydropower resources more than other small 

power production facilities. Hydropower Association also asserts that there is almost 5 

GW of potential non-power dams that could be developed and that the 20 MW exemption 

should be retained for these resources.

955

623. Ohio Consumers Counsel states that lowering the rebuttable presumption could 

permit electric utilities and state policies to deny QFs and distributed energy resources 

954 NRECA Comments at 18-19.

955 Hydropower Association Comments at 2-7 (citing 16 U.S.C. 803).
Docket Nos. RM19-15-000 and AD16-16-000 - 346 -

under 20 MW from having unrestricted and nondiscriminatory access to wholesale 

markets. For example, Ohio Consumers Counsel states that the NOPR would permit 

electric distribution utilities to limit the availability of after-the-meter generation and 

storage from PJM’s markets, such as through restrictive net metering requirements, 

unreasonably low compensation for distributed energy resources, or other state regulatory 

and policy restrictions. Ohio Consumers Counsel urges the Commission to require that 

investor-owned electric distribution utilities demonstrate that they have not restricted 

market access to QFs and distributed energy resources rated between 1 MW and 

20 MW.956

e. Commission Determination

624. We agree with commenters that, in Order Nos. 688 and 688-A, given conditions at 

the time, the Commission established the rebuttable presumption at QFs 20 MW or less. 

Furthermore, as commenters noted in reviewing several individual cases in 2013-2015, the 

Commission continued to find that those individual small power production facilities 20 

MW or less still needed the additional protections and encouragement.957 However, since 

Order Nos. 688 and 688-A the Commission has recognized multiple examples of small 

power production facilities under 20 MW participating in RTO/ISO energy markets. The 

956 Ohio Consumers Counsel Comments at 2-5.

957 PPL Elec. Utilities Corp., 145 FERC ¶ 61,053 at P 24; Va. Elec. & Power Co., 

151 FERC ¶ 61,038, at P 21; N. States Power Co., 151 FERC ¶ 61,110.
Docket Nos. RM19-15-000 and AD16-16-000 - 347 -

Commission found that the electric utilities in those proceedings rebutted the presumption 

of no market access and therefore terminated the mandatory purchase obligation.

958 

625. We adopt the proposal to revise 18 CFR 292.309(d) to reduce the net power 

production capacity level at which the presumption of nondiscriminatory access to a 

market attaches for small power production facilities, but not for cogeneration facilities. 

However, recognizing some of the challenges that QFs near 1 MW have in participating in 

such markets that have been identified by commenters, in this final rule we lower the 

rebuttable presumption from 20 MW to 5 MW, rather than from 20 MW to 1 MW as 

proposed in the NOPR. Under the final rule, small power production facilities with a net 

power production capacity at or below 5 MW will be presumed not to have 

nondiscriminatory access to markets, and, conversely, small power production facilities 

with a net power production capacity over 5 MW will be presumed to have 

nondiscriminatory access to markets. 

626. A number of commenters oppose the reduction below 20 MW, arguing the lack of a 

record to support the proposal. We disagree. In Order Nos. 688 and 688-A, the 

Commission determined that small QFs may not have nondiscriminatory access to 

wholesale markets and, therefore, it was reasonable to establish a presumption for small 

QFs. At that time, the Commission found that it was “reasonable and administratively 

workable” to define “small” for purposes of this regulation to be QFs below 20 MW.959 

958 See, e.g., Fitchburg Gas and Elec. Light Co., 146 FERC ¶ 61,186, at P 33 

(2014); City of Burlington, Vt., 145 FERC ¶ 61,121, at P 33 (2013).

959 See Order No. 688, 117 FERC ¶ 61,078 at PP 74-78 (establishing rebuttable 
Docket Nos. RM19-15-000 and AD16-16-000 - 348 -

We also note that a number of commenters, including state entities which are charged with 

applying PURPA in their jurisdictions,960 supported a reduction in the 20 MW threshold.

627. The Commission acknowledged that there is no unique number to draw a line for 

determining what is a small entity.961 In establishing 20 MW presumption as the line 

between large and small QFs for purposes of section 210(m), the Commission looked at 

other non-QF rulemaking orders in which it considered what was a small entity and those 

orders showed 20 MW was a reasonable number at which to draw the line.962 But, as 

explained below, the Commission has since determined, based on changed circumstances 

since the issuance of Order Nos. 688 and 688-A, that entities with capacity lower than 

20 MW have nondiscriminatory access to the markets and, therefore, capacity level of 

20 MW may no longer be a reasonable place to establish the presumption on what 

constitutes a smaller entity under our regulations.

presumption); Order No. 688-A, 119 FERC ¶ 61,305 at P 95 (“There is no perfect bright 

line that can be drawn and we have reasonably exercised our discretion in adopting a 20 

MW or below demarcation for purposes of determining which QFs are unlikely to have

nondiscriminatory access to markets.”).

960 See Connecticut Commission Comments at 20-21; Kentucky Commission 

Comments at 8.

961 Order No. 688-A, 119 FERC ¶ 61,305 at P 97 (“Although there is no unique and 

distinct megawatt size that uniquely determines if a generator is small, in other contexts 

the Commission has used 20 MW, based on similar considerations to those presented here, 

to determine the applicability of its rules and policies.”).

962 See Order No. 688, 117 FERC ¶ 61,078 at P 76; Order No. 688-A, 119 FERC 

¶ 61,305 at PP 96-97.
Docket Nos. RM19-15-000 and AD16-16-000 - 349 -

628. Similar to our analysis in Order No. 688, we have determined that entities below 20 

MW now can participate in RTO/ISO markets.963 Here, we are updating the rebuttable 

presumption based on industry changes since Order No. 688. Moreover, it is reasonable 

to update the rebuttable presumption as markets defined in PURPA section 210(m)(1)(A), 

(B), and (C) evolve because that statute itself does not establish a presumption and we are 

updating the rules, as PURPA provides we will do from time to time, to ensure we comply 

with PURPA. However, because the revised presumption established in this final rule is a 

rebuttable presumption, QFs can seek to overcome it.

629. Over the last 15 years, the RTO/ISO markets have matured, market participants 

have gained a better understanding of the mechanics of such markets, and, as a result, we 

find that it is reasonable to presume that access to the RTO/ISO markets has improved and 

that it is appropriate to update the presumption for smaller production facilities. As we 

did in Order No. 688, we have looked to indicia in other orders to determine where the 

presumption should be set. 

630. We find that at this time, market rules are inclusive of power producers below 

20 MW participating in markets. For example, since the issuance of Order No. 688, the 

Commission has required public utilities to increase the availability of a Fast-Track 

interconnection process for projects up to 5 MW.

964 That the Commission chose a 5 MW 

963 In fact, when the Commission established the rebuttable presumption of 

20 MW, commenters in that proceeding cited instances where QFs at 1 MW or above had 

already had nondiscriminatory access to RTOs/ISOs. See Order No. 688, 117 FERC 

¶ 61,078 at PP 64-66.

964 Order No. 792, 145 FERC ¶ 61,159, at P 103, clarified, Order No. 792-A, 
Docket Nos. RM19-15-000 and AD16-16-000 - 350 -

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. 

631. While the existence of Fast-Track interconnection processes does not on its own 

demonstrate nondiscriminatory access for resources under 20 MW, it does indicate that 

entities smaller than 20 MW have access to the market. Presuming that QFs above 5 MW 

have such access is therefore a reasonable approach to identifying a capacity level at 

which to update the rebuttable presumption of nondiscriminatory market access.

632. Additionally, since the issuance of Order No. 688 the Commission has required 

each RTO/ISO to update its tariff to include a participation model for electric storage 

resources that established a minimum size requirement for participation in the RTO/ISO 

markets that does not exceed 100 kW.965 These proposals require RTO/ISOs to revise 

their tariffs to provide easier access for smaller resources. Requiring markets to 

accommodate storage resources to as low as 100 kW also supports that resources smaller 

than 20 MW have nondiscriminatory access to those RTO/ISO markets. The Commission 

believes that these developments support updating the 20 MW presumption to a lower 

number.

633. Commenters argue that individually each of these changes in circumstances,

standing alone, may not support the reduction of the threshold below 20 MW. But when 

146 FERC ¶ 61,214.

965 Order No. 841, 162 FERC ¶ 61,127 at P 265.
Docket Nos. RM19-15-000 and AD16-16-000 - 351 -

the changes are viewed together, we find that their cumulative effect demonstrates that it 

is reasonable for the Commission to maintain a small entity rule but update its 

determination of what is a small entity under this presumption under the PURPA 

regulations. Additionally, the prospect of increased participation of distributed energy 

resources in energy markets further supports the proposition that wholesale markets are 

accommodating resources with smaller capacities.

966 

634. The Commission recognizes that certain of these precedents would support 

reducing the presumption below 5 MW, and perhaps even lower than 1 MW. However, 

the Commission has carefully considered the comments detailing the problems that QFs 

have had in participating in RTO/ISO markets, problems that necessarily are more acute 

for smaller QFs at or near the 1 MW threshold proposed in the NOPR.967 The 

Commission therefore has determined that a 5 MW is a more reasonable threshold of nondiscriminatory access to RTO/ISO markets.

635. Based on the foregoing, we find it reasonable to update the presumption under 

these regulations as to what constitutes a small entity that has non-discriminatory access to 

966 See, e.g., Elec. Participation in Mkts Operated by Reg’l Transmission Orgs and 

Independent Sys. Operators, 157 FERC ¶ 61,121, P 129 (2016) (“The costs of distributed 

energy resources have decreased significantly, which when paired with alternative revenue 

streams and innovative financing solutions, is increasing these resources’ potential to 

compete in and deliver value to the organized wholesale electric markets.” (footnote 

omitted)).]

967 See, e.g., Allco Comments at 17-19; Advanced Energy Economy Comments at 

10-11; DC Commission Comments at 5; Public Interest Organizations Comments at 89-

90; SEIA Comments at 45-49. 
Docket Nos. RM19-15-000 and AD16-16-000 - 352 -

RTO/ISO markets and markets of comparable competitive quality below 20 MW, and that 

5 MW represents a reasonable new threshold that accounts for the change of 

circumstances indicating that 20 MW no longer is appropriate but also accommodates 

commenters’ concerns that a 1 MW threshold would be too low. We acknowledge that 

“there is no unique and distinct megawatt size that uniquely determines if a generator is 

small.”968 We find that a 5 MW threshold accords with PURPA’s mandate to encourage 

small power production facilities, recognizes the progress made in wholesale markets as 

discussed above, and balances the competing claims of those seeking a lower threshold 

and those seeking a higher threshold.

636. Individual small power production QFs that are over 5 MW and less than 20 MW 

can seek to make the case, however, that they do not truly have nondiscriminatory access 

to a market and should still be entitled to a mandatory purchase obligation.

637. Regarding Advanced Energy Economy’s argument that the Commission failed to 

sufficiently justify its change in policy, we disagree.969 In FCC v. Fox Television, the 

court stated that, when an agency makes a change in policy, the agency must show that

there are good reasons for the change, “[b]ut it need not demonstrate to a court’s 

satisfaction that the reasons for the new policy are better than the reasons for the old one; 

it suffices that the new policy is permissible under the statute, that there are good reasons 

968 Order No. 688-A, 119 FERC ¶ 61,305 at P 97.

969 Advanced Energy Economy Comments at 6 (citing FCC v. Fox Television, 556 

U.S. at 515).
Docket Nos. RM19-15-000 and AD16-16-000 - 353 -

for it, and that the agency believes it to be better, which the conscious change of course 

adequately indicates.”970

638. To be clear, we are maintaining our determination from Order No. 688 that small 

entities potentially may not have non-discriminatory access for purposes of PURPA 

section 210(m). However, as explained above, the Commission has determined that using 

20 MW as an indicator of what constitutes a small entity is no longer valid. Entities below 

20 MW increasingly have access to the markets, become familiar with practices and 

procedures, and that markets have since implemented several changes to provide easier 

access to smaller facilities, including small power production QFs, storage facilities, and 

distributed energy resources. These changes demonstrate a change in facts since the time 

we issued Order No. 688 which supports our updating of what constitutes a small entity 

for purposes of PURPA section 210(m). 

639. Accordingly, we decline to adopt Ohio Consumers Counsel’s suggestion that 

electric utilities continue to have the burden to demonstrate that certain small power 

production QFs under 20 MW have nondiscriminatory access to markets like PJM before 

being relieved of the mandatory purchase obligation for such QFs. 

640. While we find that it is reasonable to update the rebuttable presumption from 20 

MW to 5 MW, we recognize commenters’ concerns regarding specific barriers to 

participation in RTO markets that may affect the nondiscriminatory access to those 

markets of some individual small power production facilities between 5 MW and 20 MW. 

970 FCC v. Fox Television, 556 U.S. at 515.
Docket Nos. RM19-15-000 and AD16-16-000 - 354 -

To address these concerns, we additionally are revising 18 CFR 292.309(c)(2)(i)-(vi) to 

include factors that small power production facilities between 5 MW and 20 MW can 

point to in seeking to rebut the presumption that they have nondiscriminatory access. 

These factors are in addition to the existing ability, pursuant to 18 CFR 292.309(c), to 

rebut the presumption of access to the market by demonstrating, inter alia, operational 

characteristics or transmission constraints.

641. Specifically, the Commission adds to 18 CFR 292.309(c) the following five

factors: (1) specific barriers to connecting to the interstate transmission grid, such as 

excessively high costs and pancaked delivery rates; (2) the unique circumstances 

impacting the time/length of interconnection studies/queue to process small power QF 

interconnection requests; (3) a lack of affiliation with entities that participate in RTO/ISO 

markets; (4) a predominant purpose other than selling electricity which would warrant the 

small power QF being treated similarly to cogenerators (e.g., municipal solid waste 

facilities, biogas facilities, run-of-river hydro facilities, and non-powered dams); (5) the 

QF has certain operational characteristics that effectively prevent the qualifying facility's 

participation in a market; and (6) the QF lacks access to markets due to transmission 

constraints, including that it is located in an area where persistent transmission constraints 

in effect cause the QF not to have access to markets outside a persistently congested area 

to sell the QF output or capacity. This is not intended to be an exhaustive list of the 

factors that a QF could rely upon in seeking to rebut the presumption. These factors, 

among other indicia of lack of nondiscriminatory access, will be assessed by the 

Commission on a case-by-case basis in considering a claim that the presumption of 
Docket Nos. RM19-15-000 and AD16-16-000 - 355 -

nondiscriminatory access to the defined markets should be considered rebutted for a 

specific QF. 

642. The addition of these factors addresses commenters’ concern that not all small 

power production facilities between 5 and 20 MW may have nondiscriminatory access to 

competitive markets, and facilitates the ability of small power production facilities facing 

barriers to participation in RTO markets to demonstrate their lack of access. For example,

while a small power production facility between 5 MW and 20 MW does not need to be 

physically interconnected to transmission facilities to be considered as having access to 

the statutorily-defined wholesale electricity markets, we recognize there are some small 

power production facilities between 5 MW and 20 MW that may face additional barriers, 

such as excessively high costs and pancaked delivery rates, to access wholesale markets. 

643. For example, several commenters express concern over the resources or 

administrative burden for some small power QFs that lack the necessary experience or 

expertise to participate in energy markets. Recognizing these concerns, we have added 

consideration of both the fact that some small power production facilities will face

additional difficulties due to costs, administrative burdens, length of the interconnection 

study process and the size of the queues, and the fact that some small power production 

QFs do not have access to the expertise of affiliated entities. 

644. We agree with commenters that some small power production facilities are similar 

to cogeneration facilities because their predominant purpose is not power production. 

Like cogeneration facilities, the sale of electricity from these small power production 

facilities is a byproduct of another purpose and these facilities might not be as familiar 
Docket Nos. RM19-15-000 and AD16-16-000 - 356 -

with energy markets and the technical requirements for such sales. Therefore, we will 

allow the small subset of small power production facilities that are between 20 MW and 5

MW to rebut the presumption of access to markets where the predominant purpose of the 

facility is other than selling electricity, and the sale of electricity is simply a byproduct of 

that purpose. Finally, like all QFs over 20 MW, we recognize that there may be particular 

small power production facilities with certain operational characteristics or that are 

located in an area where persistent transmission constraints in effect cause the QF not to 

have access to markets outside a persistently congested area to sell the QF output or 

capacity.

645. While we appreciate Indiana Municipals’ concern over preserving Commission 

resources, we will deny its request to automatically apply the lower threshold to utilities 

that have already been granted termination for QFs over the 20 MW threshold. We find 

that it is appropriate to require utilities that were previously granted termination of the 

mandatory purchase obligation for new contracts and obligations for QFs above 20 MW, 

but are now seeking to terminate the mandatory purchase obligation for new contracts and 

obligations for small power production facilities between 5 and 20 MW to follow the 

procedures in 18 CFR 292.310, including procedures for providing notice to those 

potentially affected QFs within their footprint. That is, those utilities for which the 

Commission has already granted relief from the mandatory purchase obligation for small 

power production facilities over 20 MW must reapply with the Commission requesting 

relief from the mandatory purchase obligation for small power production facilities 

between 5 MW and 20 MW. 
Docket Nos. RM19-15-000 and AD16-16-000 - 357 -

646. Among other factors, the regulation’s notice provision mentioned above will allow 

small power production facilities between 5 MW and 20 MW an opportunity, if 

applicable, to present evidence that their facility does not have nondiscriminatory access 

to defined markets based on the factors discussed above.971 In the proceeding in which the 

utility seeks to terminate the mandatory purchase obligation between 5 MW and 20 MW, 

we will not entertain arguments that the utility should lose its previously granted 

termination of purchase obligation at 20 MW and above; our regulations provide how a 

mandatory purchase obligation can be reinstated. We do not, in this final rule, change a 

QF’s right to seek reinstatement of the mandatory purchase obligation where the 

conditions set forth in 18 CFR 292.309(a), (b), or (c) are no longer met.972

647. Regarding the Michigan Commission’s questions, this final rule preserves the 

rights or remedies of any party under existing contracts or obligations, in effect or pending 

approval before the appropriate state regulatory authority or non-regulated electric utility 

on or before [INSERT DATE 120 DAYS AFTER THE DATE OF PUBLICATION 

IN THE FEDERAL REGISTER] with QFs between 5 MW and 20 MW. Consistent 

with Commission precedent, this final rule defines the term “obligations” broadly to 

encompass any existing legally enforceable obligation.973

971 18 CFR 292.310.

972 See 18 CFR 292.311.

973 See Cedar Creek Wind LLC, 137 FERC ¶ 61,006, at PP 35-36 n.62 (2011)

(stating that courts have recognized negotiations regarding terms that parties to the 

negotiations intend to become finalized or written contract, may in some circumstances 

result in legally enforceable obligations on those parties notwithstanding the absence of a 
Docket Nos. RM19-15-000 and AD16-16-000 - 358 -

2. Reliance on RFPs and Liquid Market Hubs to Terminate 

Purchase Obligation Under PURPA Section 210(m)

a. NOPR Discussion 

648. In the NOPR, the Commission noted that NARUC had proposed that the 

Commission allow utilities to rely on RFPs (in combination with liquid market hubs) to 

establish eligibility to terminate a utility’s purchase obligation pursuant to PURPA section 

210(m)(1)(C).974 After describing generally how such a proposal might be structured, 

NARUC suggested that “[t]he Commission should create a yardstick of characteristics that 

describe in detail how a utility could qualify for an exemption under subparagraph (C).”975

649. The Commission stated that, under the PURPA Regulations, electric utilities 

already may seek to terminate their mandatory purchase obligation pursuant to PURPA 

section 210(m)(1)(C) by demonstrating that a particular market is of comparable 

competitive quality to markets described in PURPA section 210(m)(1)(A) and (B).976 The 

writing). See generally Burbach Broadcasting Co. of Delaware v. Elkins Radio Corp., 

278 F.3d 401, 407-09 (4th Cir. 2002); Adjustrite Systems, Inc. v. GAB Business Serv., Inc., 

145 F.3d 543, 550 (2dCir. 1998); Miller Constr. Co. v. Stresstek, 697 P.2d 1201, 1202-04 

(Idaho 1985).); see also JD Wind 1, LLC, 129 FERC ¶ 61,148 at P 25; Grouse Creek Wind 

Park, LLC, 142 FERC ¶ 61,187 at PP 40-41.

974 NOPR, 168 FERC ¶ 61,184 at P 131 (citing NARUC Supplemental Comments, 

Docket No. AD16-16-000 (filed Oct. 17, 2018)).

975 Id., attach. A at 9.

976 Id. P 132 (citing Order No. 688-A, 119 FERC ¶ 61,305 at P 43 (“Congress 

believed the two types of markets identified in subparagraphs (A) and (B), while distinct 

between themselves, contain certain competitive qualities that justify termination of the 

purchase requirement for any QF with nondiscriminatory access to those markets. 

Subparagraph (C) directs the Commission to consider these competitive qualities when 

analyzing whether there are other markets that, while not meeting the specific 

requirements of subparagraphs (A) and (B), are sufficiently competitive to justify 
Docket Nos. RM19-15-000 and AD16-16-000 - 359 -

Commission further noted that the current PURPA Regulations are not prescriptive about 

how an electric utility must make such a demonstration and nothing in the PURPA 

Regulations or precedent would bar an electric utility from arguing that RFPs in 

combination with liquid market hubs are sufficient to satisfy PURPA section

210(m)(1)(C). 

650. The Commission then stated that it believed that a properly structured proposal 

along the lines proposed by NARUC potentially could satisfy the statutory requirements 

under PURPA section 210(m)(1)(C) and that it would consider such proposals on a caseby-case basis. Although the Commission did not propose additional criteria a utility or 

utilities may rely on to satisfy PURPA section 210(m)(1)(C), the Commission sought 

comments on any specific factors that would be useful to consider in determining how a 

utility or utilities may satisfy PURPA section 210(m)(1)(C).977

b. Comments

i. Comments in Opposition

651. A few commenters do not support allowing competition to be an alternative to the 

mandatory purchase obligation.978 ELCON is concerned that no state competitive 

termination of the purchase requirement.”)); cf. Pub. Serv. Co. of N.M., 140 FERC ¶ 

61,191, at PP 29-38 (2012) (denying application to terminate mandatory purchase 

obligation on the grounds that the Four Corners Hub is not of comparable competitive 

quality to markets in sections 210(m)(1)(A) and (B) of PURPA)).

977 Id. P 133.

978 Allco Comments at 17-19; Public Interest Organizations Comments at 90.
Docket Nos. RM19-15-000 and AD16-16-000 - 360 -

procurement is robust enough to replace avoided capacity costs.979 Solar Energy 

Industries supports using RFPs to set avoided cost rates, but does not support using RFPs 

to vitiate utilities’ mandatory purchase obligations.

980

652. Public Interest Organizations contend that RFPs are not comparable in quality to 

PURPA section 210(m)(1)(A) or (B) markets because there is only a single buyer and 

there are no safeguards against the anti-competitive behavior of that buyer, such as 

favoring its own or an affiliate’s generation.981 NIPPC, CREA, REC, and OSEIA state 

that, while they agree in principle that competition should be the motivating force in 

energy markets, their experience shows that utility-sponsored RFP programs often fall far 

short of genuine competition.982

653. Public Interest Organizations state that Order No. 688-A specifies that 

demonstrating that a market offers “a meaningful opportunity to sell” usually requires 

evidence of QF transactions, which is not possible with a market hub.983 Public Interest 

Organizations argue that market hubs are not equivalent to PURPA section 210(m)(1)(A) 

979 ELCON Comments at 19.

980 Solar Energy Industries Comments at 24 (citing Solar Energy Industries, 

Supplemental Comments, Docket No. AD16-16-000, at 10-37, 40-58 (filed Aug. 28, 

2019)).

981 Public Interest Organizations Comments at 93.

982 NIPPC, CREA, REC, and OSEIA Comments at 66.

983 Public Interest Organizations Comments at 92 (citing Order No. 688-A, 119 

FERC ¶ 61,305 at P 38).
Docket Nos. RM19-15-000 and AD16-16-000 - 361 -

or (B) markets because, unlike an independently administered auction, there is no 

guarantee that a QF will be able to sell their energy even if it is the lowest cost resource.984

654. Public Interest Organizations further contend that the Commission does not have 

the authority to approve RFPs or liquid market hubs as PURPA section 210(m)(1)(C) 

wholesale markets because they are not of comparable qualify to Day 1 or Day 2 markets, 

i.e., to PURPA section 210(a)(1)(A) or (B) markets.

985 

ii. Comments in Support

655. Several commenters support allowing competition to be an alternative to the 

mandatory purchase obligation.986 ELCON supports competitive procurements that 

exempt industrial self-supply.987

656. APPA supports the Commission reviewing factors that would determine if a market 

is competitive and comparable to PURPA sections 210(m)(1)(A) and (B).988 Xcel 

proposes that the PURPA section 210(m)(1)(C) test should evaluate whether market 

players have a reasonable opportunity to participate in the market, rather than whether the 

type of market is similar to PURPA section 210(m)(1)(A) and (B) markets.989 A few 

984 Id.

985 Id. at 90-91.

986 Advanced Energy Economy Comments at 12; APPA Comments at 29; Colorado 

Independent Energy Comments at 7; Xcel Comments at 11. 

987 ELCON Comments at 19.

988 APPA Comments at 26-29. 

989 Xcel Comments at 11.
Docket Nos. RM19-15-000 and AD16-16-000 - 362 -

commenters requested a technical conference to identify the criteria for determining what 

processes are competitive.990 Colorado Independent Energy would like the RFP standard 

for PURPA section 210(m)(1)(C) status to be higher than for QF pricing and include 

evaluation of bid data and the modeling process to show the absence of bias against 

renewable and cogeneration projects and likewise the absence of bias for utility self-build 

projects.991 

657. Arizona Public Service agrees with NARUC that the Commission should allow 

utilities to rely on RFPs to establish eligibility to terminate the utility’s purchase 

obligation pursuant to PURPA section 210(m)(1)(C). Arizona Public Service believes this 

proposal is one way a utility could demonstrate that a market is of comparable competitive 

quality to the markets described in PURPA sections 210(m)(1)(A) and (B).992 

658. APPA argues that market hubs should be considered as possibly comparable, 

particularly to PURPA section 210(m)(1)(B), which requires that QFs have access to 

Commission-approved transmission service and competitive wholesale markets for long 

and short-term capacity and energy sales.993 APPA highlights the Commission finding 

990 Advanced Energy Economy Comments at 13; ELCON Comments at 19.

991 Colorado Independent Energy Comments at 6, 11-12. 

992 Arizona Public Service Comments at 8-10.

993 APPA Comments at 27.
Docket Nos. RM19-15-000 and AD16-16-000 - 363 -

that the Mid-Columbia and Palo Verde hubs have sufficient liquidity to find just and 

reasonable rates and adds that an empirical test of market liquidity could be created.994 

c. Commission Determination

659. In this final rule, we affirm that we will consider utility proposals to terminate the 

purchase obligation pursuant to PURPA section 210(m)(1)(C) on a case-by-case basis, 

including utility proposals based on competitive solicitations or liquid market hubs.

660. In response to Public Interest Organizations, as explained above in Section IV.A.1, 

PURPA section 210(m) obligates the Commission to grant any request to terminate a 

utility’s obligation to purchase from a QF with nondiscriminatory access to the specified 

markets that satisfy that provision. Whether any particular market is of comparable 

quality to a Day 1 or Day 2 market necessarily must be determined in the context of an 

individual case.

661. We refrain from outlining here an exhaustive list of factors that will be used in any 

such case-by-case evaluation, but at a minimum we will be guided by the important 

criteria discussed previously in this rule in section IV.B.8 on the use of competitive 

solicitations to determine avoided costs. 

662. Consistent with our findings and discussion in section IV.B.4 on the use of market 

hubs to determine avoided cost, the Commission finds that competitive market prices in 

general should reflect the avoided cost energy rates of utilities with access to such markets 

in a given region. We will therefore consider, on a case-by-case basis, whether a properly 

994 Id. at 28.
Docket Nos. RM19-15-000 and AD16-16-000 - 364 -

run RFP or competitive acquisition process may also justify termination of the PURPA 

purchase obligation pursuant to PURPA section 210(m)(1)(C). 

H. Legally Enforceable Obligation

1. NOPR Proposal 

663. The Commission proposed to add regulatory text in 18 CFR 292.304(d)(3) to 

require QFs to demonstrate that a proposed project is commercially viable and that the QF 

has a financial commitment to construct the proposed project pursuant to objective, 

reasonable, state-determined criteria in order to be eligible for a LEO. The Commission 

further proposed to provide that states have flexibility as to what constitutes an acceptable 

showing of commercial viability and financial commitment. 

664. The Commission stated that its objective in requiring a showing of commercial 

viability and the QF’s financial commitment to construct the project was to ensure that no

electric utility obligation is triggered for those QF projects that are not sufficiently 

advanced in their development and, therefore, for which it would be unreasonable for a 

utility to include in its resource planning, while at the same time ensuring that the 

purchasing utility does not unilaterally and unreasonably decide when its obligation arises. 

The NOPR proposed that states may require a showing, for example, that a QF has 

satisfied, or is in the process of undertaking, at least some of the following prerequisites: 

(1) obtaining site control adequate to commence construction of the project at the 

proposed location; (2) filing an interconnection application with the appropriate entity; (3) 

securing local permitting and zoning; or (4) other similar, objective, reasonable criteria 

that allow a QF to demonstrate its commercial viability and financial commitment to 
Docket Nos. RM19-15-000 and AD16-16-000 - 365 -

construct the facilities. The NOPR stated that these proposed indicia were not intended to 

be exhaustive and the Commission sought comment on these indicia and others that also 

might be appropriate for consideration.

665. The Commission stated that it believed requiring QFs to demonstrate their 

commercial viability and financial commitment to construct the facilities based on such 

indicia before obtaining a LEO would allow electric utilities to reliably plan their systems 

while ensuring resource adequacy. Additionally, the development and definition of 

objective and reasonable factors to determine commercial viability and financial 

commitment to construct a facility would encourage the development of QFs by providing 

QFs with more certainty as to when they will obtain a LEO.

995

2. Comments

a. Comments in Opposition 

666. Several commenters oppose the Commission’s proposal to require QFs to 

demonstrate that a proposed project is commercially viable and the QF has a financial 

commitment to construct the proposed project pursuant to objective, reasonable, statedetermined criteria in order to be eligible for a LEO and that states have flexibility as to 

what constitutes an acceptable showing of commercial viability and financial 

commitment, arguing it undermines PURPA’s intent to promote QF development.996

995 Because QFs already in operation have necessarily demonstrated a commitment 

to construct the project, the Commission stated that it does not intend commercial viability 

and financial commitment requirements to serve as prerequisites to QFs already in 

operation with existing LEOs to obtaining new LEOs.

996 NIPPC, CREA, REC, and OSEIA Comments at 81; Public Interest 
Docket Nos. RM19-15-000 and AD16-16-000 - 366 -

667. NIPPC, CREA, REC, and OSEIA argue that developers cannot obtain financing 

without the financial commitment of a PPA or LEO from the utility and therefore 

requiring financial viability as a condition precedent to obtain a LEO is problematic.997

Western Resource Councils argues that the NOPR proposal represents an onerous 

financial and bureaucratic barrier that will lead to a substantial reduction in the number of 

QFs.998

668. Southeast Public Interest Organizations argue that the proposal does not 

sufficiently narrow the range of divergent LEO tests that have already been adopted by the 

states and opposes allowing states additional flexibility in establishing criteria up to a fully 

executed agreement.999 sPower requests that the Commission establish specific criteria 

and prohibit states from imposing any additional criteria.1000 Solar Energy Industries 

requests that the Commission develop a concrete baseline in determining when a QF is 

entitled to a purchase contract.

669. Solar Energy Industries and Public Interest Organizations argue that requiring 

developers to invest additional capital prior to obtaining a LEO will prevent smaller 

companies who are unable to invest heavily in early state development activity from 

Organizations Comments at 98; Western Resource Councils Comments at 144.

997 NIPPC, CREA, REC, and OSEIA Comments at 81.

998 Western Resource Councils Comments at 144.

999 Southeast Public Interest Organizations Comments at 43

1000 sPower Comments at 14.
Docket Nos. RM19-15-000 and AD16-16-000 - 367 -

participating.1001 Solar Energy Industries argue that it is unjust and unreasonable to 

require QFs to invest millions of dollars in site control, permit acquisition and 

interconnection costs in order to secure the opportunity to negotiate with the purchasing 

utility. For those states that do not willingly disclose their avoided cost rates or 

methodology, the NOPR’s LEO proposal requires QFs to incur substantial expense to 

establish their commercial viability without a reasonable understanding of what their rate

may be.

1002

670. In striking a balance between interconnection and development risk, Solar Energy 

Industries proposes that the first prerequisite to a LEO formation be either: (a) the 

completion of the System Impact Study (or the equivalent in the state interconnection 

process); or (b) where the utility cannot complete the System Impact Study within a 

reasonable period of time, one year after tendering an interconnection request to the host 

utility.1003 Where a QF has obtained site control, initiated state permitting processes, 

submitted an interconnection request and associated study deposit, and has been certified 

through the submission of a Form No. 556, the Commission should find that the QF is 

eligible to establish a LEO to sell to the purchasing utility, provided that: (1) the QF has 

received a System Impact Study report (or equivalent) or one year has elapsed since the 

1001 Solar Energy Industries Comments at 41; Public Interest Organization 

Comments at 80-82.

1002 Solar Energy Industries Comments at 41.

1003 Id. at 43. 
Docket Nos. RM19-15-000 and AD16-16-000 - 368 -

QF’s interconnection request was tendered to the host utility; and (2) the QF commits to 

achieving commercial operation within 180 days of the completion of all interconnection 

facilities and network upgrades by the utility.1004 Solar Energy Industries asserts that QFs 

would, upon satisfaction of these criteria, be legally entitled to negotiate with the 

purchasing utility to develop a PPA setting forth the terms and conditions of the purchase, 

including liability if the QF fails to perform. Projects that reach agreement will proceed 

according to the terms of the PPA and the purchasing utility can establish milestones with 

enough financial protection to ensure that ratepayers will not be harmed if the QF fails to

begin operations.

1005

671. American Dams argues that Interconnection Agreements are generally processed 

far too slowly, a problem that should be addressed by the Commission.1006

672. Southeast Public Interest Organizations support the requirement of demonstrating 

site control, but state that requiring permits can be time-consuming and costly such that 

pre-financing QFs may not have the resources for the lengthy permitting process, and it is 

unreasonable to expect a QF to incur these expenses until it has secured a price for its 

output so that it can in turn secure financing for the project.1007

1004 Id.

1005 Id.

1006 American Dams Comments at 5-6.

1007 Southeast Public Interest Organization Comments at 43-44.
Docket Nos. RM19-15-000 and AD16-16-000 - 369 -

b. Comments in Support

673. Numerous commenters support the NOPR’s LEO proposal, asserting that state 

agencies are better positioned to develop criteria that reflect their unique operational 

circumstances, resource planning needs and risk appetite.1008 Several commenters note 

that the proposed factors provide a reasonable balance between the planning needs of the 

connecting utility and certainty to QF developers.1009 Several commenters assert that 

requiring QFs to demonstrate commercial viability and financial commitment will reduce 

the reliability or other risks a utility faces by having to plan for its system needs or 

resource adequacy around a QF that is never developed.

1010

674. Several commenters agree that the proposed regulations will provide certainty to 

host utilities and state commissions while decreasing systems impact and associated 

costs.1011

1008 Alaska Power Comments at 1-2; APPA Comments at 30; Chamber of 

Commerce at 8; Colorado Independent Energy Comments at 13; Connecticut Authority 

Comments at 24-25; Consumer Alliance Comments at 2; Consumers Energy Comments at 

5; East Kentucky Comments at 3-4; East River at 2; El Paso Electric Comments at 6-7; 

Golden Valley Comments at 7-8; Indiana Municipal Comments at 11-12; Institute for 

Energy Research Comments at 2; Massachusetts DPU Comments at 10; NARUC 

Comments at 7-8; NIPPC, CREA, REC, and OSEIA Comments at 81; NRECA Comments 

at 21; North Carolina Commission Staff Comments at 6; Northern Laramie Range 

Alliance Comments at 3-4; Ohio Commission Energy Advocate Comments at 10; Oregon 

Commission at 6.

1009 Alliant Energy Comments at 21; Industrial Energy Consumers Comments at 

14-16.

1010 Duke Energy Comments at 19; EEI Comments at 37.

1011 Alliant Energy Comments at 21-22; NRECA at 21; Northern Laramie Range 

Alliance Comments at 3-4.
Docket Nos. RM19-15-000 and AD16-16-000 - 370 -

675. Connecticut Authority supports the proposal arguing that the factors included in the 

NOPR will provide greater certainty and less risk to QF developers and purchasing 

utilities which is consistent with PURPA’s goal of developing renewable resources.1012 

The Chamber of Commerce argues that the proposed factors indicate a developer’s goodfaith intention to ultimately develop its proposed QF.1013 The Michigan Commission 

states that it supports the proposal, currently has a rulemaking and several cases pending 

regarding LEOs, and appreciates any additional clarity the Commission could provide.1014

c. Comments Requesting Modification

676. NIPPC, CREA, REC, and OSEIA request that the Commission: (1) further define 

the terms “commercial viability” and “financial commitment” to avoid litigation; (2) 

clarify that any changes to the LEO rules will not affect the viability of any executed 

contract between a developer and utility, regardless of the facility’s development status; 

and (3) clarify that the LEO rules will not preclude nor bar any utility from executing a 

PPA before the QF may be able to demonstrate compliance with the implementation of 

LEO rules.1015

1012 Connecticut Authority Comments at 24-25.

1013 Chamber of Commerce Comments at 8.

1014 Michigan Commission Comments at 7-8.

1015 NIPPC, CREA, REC, and OSEIA Comments at 81-83.
Docket Nos. RM19-15-000 and AD16-16-000 - 371 -

i. Studies

677. NorthWestern requests that the Commission require more than just the submission 

of an interconnection application prior to obtaining a LEO in order to demonstrate that the 

proposal is more than a speculative paper project.1016 Portland General requests that the 

Commission allow states to require developers to have completed the first interconnection 

study.1017 The South Dakota Commission states that developers should be required to 

have completed a transmission feasibility study or system impact study with a 

determination of the interconnection costs the QF would be required to pay prior to 

obtaining a LEO.1018 Portland General requests that off-system QFs be required to have 

completed the first study milestone of the transmission service request.1019

678. SC Solar Alliance requests that the Commission adopt a recent South Carolina 

Commission ruling that a QF should be able to establish a LEO after receiving a System 

Impact Study or within one year if a System Impact Study is not provided in a timely 

manner and that PPA in-service dates must be extended based on interconnection 

delays.1020

1016 NorthWestern Comments at 15-16.

1017 Portland General Comments at 20. 

1018 South Dakota Commission Comments at 2.

1019 Portland General Comments at 20.

1020 SC Solar Alliance Comments at 15.
Docket Nos. RM19-15-000 and AD16-16-000 - 372 -

ii. Commercial Viability

679. Alliant Energy requests that the Commission consider requiring QF developers to 

have contracts in place with equipment suppliers and an analysis of interconnections 

needed.1021

680. North Carolina Commission Staff requests that the Commission adopt a North 

Carolina Commission standard that QFs must (1) commit to sell their power via a written 

notice of commitment by the earlier of 105 days after submission of an interconnection 

request or upon receipt of the system impact study, (2) have filed a report of proposed 

construction, and (3) submitted an interconnection request under the state’s 

interconnection protocol which requires the QF to demonstrate site control.1022 sPower 

argues that option contracts should be sufficient to demonstrate site control.1023

iii. Financial Viability

681. Portland General and sPower suggest requiring developers to pay a deposit to state 

commissions to demonstrate financial viability with the amount based on the capacity of 

the QF and released upon project completion.1024 Portland General asserts that having to 

1021 Alliant Energy Comments at 22.

1022 North Carolina Commission Staff Comments at 6.

1023 sPower Comments at 15.

1024 Portland General Comments at 15-16; sPower Comments at 14-15.
Docket Nos. RM19-15-000 and AD16-16-000 - 373 -

post a deposit encourages developers to perform sufficient due diligence prior to claiming 

a LEO.1025

682. North Carolina Commission Staff argues that, in order to protect ratepayers from 

QFs gaming the process, any project that backs out of its notice of commitment should

only receive as-available rates for two years.1026

iv. Rejecting QF Purchases and Expanded Curtailment 

Rights

683. North Carolina Commission Staff suggests that the Commission update its 

regulations to allow curtailing QFs when it would be uneconomic for the utility to make 

such purchases.1027 The Institute for Energy Research argues that the Commission should 

allow a utility to reject purchases from QFs if the utility has no need for additional 

capacity. The Institute for Energy Research states that such need could be determined 

separately, on an annual basis, a stand-alone basis, or as part of an IRP process.1028

3. Commission Determination

684. In this final rule, we adopt the NOPR proposal to require QFs to demonstrate that a 

proposed project is commercially viable and that the QF has a financial commitment to 

construct the proposed project, pursuant to objective, reasonable, state-determined criteria 

1025 Portland General Comments at 20-21.

1026 North Carolina Commission Staff Comments at 6.

1027 Id. at 8.

1028 Institute for Energy Research Comments at 2-3.
Docket Nos. RM19-15-000 and AD16-16-000 - 374 -

in order to be eligible for a LEO.1029 We also affirm that the states have flexibility as to 

what constitutes an acceptable showing of commercial viability and financial 

commitment, albeit subject to the criteria being objective and reasonable. We find that 

requiring a showing of commercial viability and financial commitment, based on objective 

and reasonable criteria, will ensure that no electric utility obligation is triggered for those 

QF projects that are not sufficiently advanced in their development, and therefore, for 

which it would be unreasonable for a utility to include in its resource planning. At the 

same time, the criteria ensure that the purchasing utility does not unilaterally and 

unreasonably decide when its obligation arises. We believe this strikes the right balance 

for QF developers and purchasing utilities and should encourage development of QFs.

685. Examples of factors a state could reasonably require are that a QF demonstrate that 

it is in the process of at least some of the following prerequisites: (1) taking meaningful 

steps to obtain site control adequate to commence construction of the project at the 

proposed location and (2) filing an interconnection application with the appropriate entity. 

The state could also require that the QF show that it has submitted all applications, 

including filing fees, to obtain all necessary local permitting and zoning approvals. We 

note that the factors that the state requires must be factors that are within the control of the 

QF. Thus, we clarify that it is appropriate for states to require a QF to demonstrate that it 

is in the process of obtaining site control or has applied for all local permitting and zoning

1029 NOPR, 168 FERC ¶ 61,184 at P 140.
Docket Nos. RM19-15-000 and AD16-16-000 - 375 -

approvals, rather than requiring a QF to show that it has obtained site control or secured 

local permitting and zoning. 

686. We agree with Southeast Public Interest Organizations’ concerns regarding 

requiring QFs to obtain permits in order to determine commercial viability. In some 

regions the permitting and zoning process can be lengthy and expensive, making obtaining 

the permits and zoning changes a condition to a LEO unreasonable. Therefore, instead of 

requiring a QF to have secured local permitting and zoning, states can require QFs to have 

applied for all of the necessary permits and zoning variances, including the payment of all 

necessary fees, as a factor in demonstrating the QF’s commercial viability. States may 

require a showing that such applications have been submitted to the relevant regulatory 

bodies (including payment of the application fees).

687. Several commenters argue that requiring QFs to demonstrate financial viability 

prior to obtaining a LEO is problematic because QFs need a LEO to obtain financing.1030 

However, demonstrating the required financial commitment does not require a 

demonstration of having obtained financing. Requiring QFs to, for example, apply for all 

relevant permits, take meaningful steps to seek site control, or meet other objective and 

reasonable milestones in the QF’s development can sufficiently demonstrate QF 

developers’ financial commitment in the QF development and allows utilities to

1030 NIPPC, CREA, REC, and OSEIA Comments at 81; Western Resource Council 

Comments at 144.
Docket Nos. RM19-15-000 and AD16-16-000 - 376 -

reasonably rely on the LEO in planning for system resource adequacy. Obtaining a PPA 

or financing cannot be required to show proof of financial commitment. 

688. The intent of these factors is to provide a reasonable balance between providing 

QFs with objective and transparent milestones up front that are needed to obtain a LEO, 

allowing states the flexibility to establish factors that address the individual circumstances 

of each state, and increasing utilities’ ability to accurately plan their systems.

1031 

Establishing objective and reasonable factors is intended to limit the number of unviable 

QFs obtaining LEOs and unnecessarily burdening utilities that currently have to plan for 

QFs that obtain a LEO very early in the process but ultimately are never developed.

1032 In 

adopting this provision, the Commission is raising the bar to prevent speculative QFs from 

obtaining LEOs, and the associated burden on purchasing utilities, but is not establishing a 

barrier for financially committed developers seeking to develop commercially viable QFs. 

689. We disagree that establishing reasonable, transparent factors is an onerous barrier 

or will cause a substantial reduction of QFs. The objective and reasonable criteria we 

have established will protect QFs against onerous requirements for a LEO that hinder 

financing, such as a requirement for a utility’s execution of an interconnection 

1031 Alliant Energy Comments at 21; Industrial Energy Consumers Comments at 

14-16.

1032 Duke Energy Comments at 19; EEI Comments at 37.
Docket Nos. RM19-15-000 and AD16-16-000 - 377 -

agreement1033 or power purchase agreement,1034 or requiring that QFs file a formal 

complaint with the state commission,1035 or limiting LEOs to only those QFs capable of 

supplying firm power,1036 or requiring the QF to be able to deliver power in 90 days.1037 

We find that, by making clear that such conditions are not permitted, and by providing 

objective criteria to clarify when a LEO commences, the LEO provisions we have adopted 

will encourage the development of QFs.

690. For those commenters that requested that the Commission establish specific factors 

for the states to apply, or to establish a baseline for eligible factors, or to otherwise limit 

states’ flexibility, we decline to do so. Since its inception, the Commission’s PURPA 

Regulations have established rules and defined boundaries allowing states flexibility 

within those boundaries in implementing PURPA as appropriate for each state. As 

commenters noted, this allows states to address their unique circumstances and best 

address each states’ needs. Furthermore, existing precedent establishes a baseline1038 and 

1033 See, e.g., FLS Energy, Inc., 157 FERC ¶ 61,211, at P 26 (2016) (FLS) (stating 

that requiring signed interconnection agreement as prerequisite to LEO is inconsistent 

with PURPA Regulations).

1034 See, e.g., Murphy Flat Power, LLC, 141 FERC ¶ 61,145, at P 24 (2012) 

(finding that requiring a signed and executed contract with an electric utility as a 

prerequisite to a LEO is inconsistent with PURPA Regulations.

1035 See, e.g., Grouse Creek Wind Park, LLC, 142 FERC ¶ 61,187, at P 40 (2013).

1036 Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380, 400 (5th Cir. 2014).

1037 Power Resource Group, Inc. v. Public Utility Com’n of Texas, 422 F.3d 231, 

(5th Cir. 2005).

1038 For example, the Commission has held that requiring a fully-executed contract 

or executed interconnection agreement as a condition precedent to obtaining a LEO is 
Docket Nos. RM19-15-000 and AD16-16-000 - 378 -

this final rule’s requirement that states adopt objective and reasonable criteria for 

determining when a QF has obtained a LEO provides additional safeguards (in addition to 

that baseline) applicable to both QFs and utilities. Similarly, regarding Solar Energy 

Industries’ proposed pre-requisites and factors, for the reasons stated above, we find that 

states are in the best position to determine what specific factors would best suit the 

specific circumstances of that state, so long as they are objective and reasonable, and we 

provide the suggested prerequisites above as examples of objective and reasonable 

factors.

1039 While Solar Energy Industries’ proposed criteria may be reasonable, we 

decline to mandate specific terms for the entire country.

691. Contrary to Solar Energy Industries’ assertions, nothing in this final rule limits a 

QF developer’s or utility’s ability to negotiate rates, terms or conditions.1040 

692. With regard to the argument that the NOPR’s LEO proposal is unreasonable in 

states that do not disclose their avoided cost rate because it would require QFs to incur 

substantial expense to establish commercial viability without a reasonable understanding 

of the purchase rate, we find that such state-specific implementation issues can be 

addressed case-by-case. To the extent that entities believe that a particular state’s avoided 

cost rates or rate setting methodologies do not provide sufficient transparency to support a 

inconsistent with PURPA. See FLS, 157 FERC ¶ 61,211 at P 26; Cedar Creek Wind LLC, 

137 FERC ¶ 61,006 at P 35.

1039 See supra P 685.

1040 See 18 CFR 292.301(b).
Docket Nos. RM19-15-000 and AD16-16-000 - 379 -

QF’s ability to make reasonable commercial viability investment decisions, such entities 

could file a petition for enforcement against the state at the Commission and, if the 

Commission declines to act, later file a petition against the state in U.S. district court 

(pursuant to PURPA section 210(h)(2)(B)). 

693. NIPPC, CREA, REC, and OSEIA request that we further define the terms 

commercial viability and financial commitment. We decline. As discussed above, we 

believe the best course is to allow states the flexibility (employing objective and 

reasonable factors) to determine what constitutes commercial viability and financial 

commitment relative to the unique conditions or circumstances in each state but also 

recognizing that existing Commission precedent establishes boundaries of what would be

considered reasonable and not discriminatory limits for requirements in establishing a 

LEO.1041

694. Additionally, we clarify that any changes to the LEO rules adopted herein do not 

affect the viability of any executed contract or LEO between a QF developer and utility in 

place as of the effective date of this final rule, regardless of the facility’s development 

status. Further we clarify that nothing in the LEO rules adopted herein precludes any 

utility from choosing to execute a PPA before a QF has demonstrated compliance with the 

LEO rules adopted here. 

1041 See FLS, 157 FERC ¶ 61,211 at P 26; Cedar Creek Wind LLC, 137 FERC ¶ 

61,006 at P 35.
Docket Nos. RM19-15-000 and AD16-16-000 - 380 -

Several commenters requested that the Commission require QFs to do more than just file

an interconnection application; instead, for example, suggesting requiring completion of 

system impact study, interconnection or transmission feasibility study.1042 We disagree. 

The approach taken here recognizes the need for a QF to demonstrate that its project is 

more than mere speculation, such that it is reasonable for a utility to consider the resource 

in its planning projections. A QF that has submitted an application for interconnection, as 

well as having taken meaningful steps to obtain site control and has applied for all 

relevant permits, while not a guarantee that the project will be completed, are all objective 

and reasonable indicators that the QF developer is seriously pursuing the project and has 

spent time and resources in developing the project to show a financial commitment.. As 

numerous commenters have explained, QFs need a LEO in order to obtain financing to 

complete the project, and we find that, as an illustrative example, requiring the submission 

of an interconnection request (as opposed to the completion of a system impact study or 

transmission feasibility study) as one criteria strikes an appropriate balance between the 

competing needs. 

695. Moreover, it bears remembering that the concept of a LEO was specifically adopted 

to prevent utilities from circumventing the mandatory purchase requirement under 

PURPA by refusing to enter into contracts.1043 The Commission thus has found that 

1042 NorthWestern Comments at 15-16, Portland General Comments at 20, South 

Dakota Commission Comments at 2.

1043 JD Wind 1, LLC, 129 FERC ¶ 61,148 at P 25, reh’g denied, 130 FERC ¶ 

61,127 (citing Order No. 69 FERC Stats. & Regs. ¶ 30,128 at 30,880; see also Midwest 
Docket Nos. RM19-15-000 and AD16-16-000 - 381 -

requiring a QF to have a utility-executed contract or interconnection agreement, or 

requiring the completion of a utility-controlled study places too much control over the 

LEO in the hands of the utility and defeats the purpose of a LEO and is inconsistent with 

PURPA.1044 When reviewing factors to demonstrate commercial viability and financial 

commitment, states thus should place emphasis on those factors that show that the QF has 

taken meaningful steps to develop the QF that are within the QF’s control to complete, 

and not on those factors that a utility controls. For example, requiring a QF to make a 

deposit as Portland General and sPower proposed or whether the QF has applied for 

system impact, interconnection or other needed studies are the types of factors that may 

show that the QF has taken meaningful steps to develop the QF that are within the QF’s 

control and the type of objective and reasonable standards that states can consider in their 

implementation.1045

696. Requests by parties to expand utilities’ rights to curtail QF sales are outside the 

scope of this proceeding. Additionally, requests to allow a utility to reject purchases from 

QFs if a utility has no need for additional capacity are outside the scope of this 

proceeding. 

Renewable Energy Projects, LLC, 116 FERC ¶ 61,017 (2006).

1044 FLS, 157 FERC ¶ 61,211 at P 23 (finding such requirements “allows a utility to 

control whether and when a legally enforceable obligation exists – e.g. by delaying the 

facilities study.”). 

1045 Portland General Comments at 15-16; sPower Comments at 14-15.
Docket Nos. RM19-15-000 and AD16-16-000 - 382 -

V. Information Collection Statement

697. The Paperwork Reduction Act1046 requires each federal agency to seek and obtain 

the Office of Management and Budget’s (OMB) approval before undertaking a collection 

of information (including reporting, record keeping, and public disclosure requirements) 

directed to 10 or more persons or contained in a rule of general applicability. OMB 

regulations require approval of certain information collection requirements contemplated 

by proposed rules (including deletion, revision, or implementation of new 

requirements).1047 Upon approval of a collection of information, OMB will assign an 

OMB control number and an expiration date. Respondents subject to the filing 

requirements of a rule will not be penalized for failing to respond to the collection of 

information unless the collection of information displays a valid OMB control number.

Public Reporting Burden: The Commission is revising its regulations implementing 

PURPA. At the Notice of Proposed Rulemaking (NOPR) stage, the Commission stated 

the principal changes that affect information collection involved the FERC Form No. 

556.1048 In response to comments arguing that the NOPR proposals would cause 

additional reporting burdens, in this final rule we have analyzed whether there are 

1046 44 U.S.C. 3501-21.

1047 See 5 CFR 1320.11.

1048 The change to the FERC-556 described by the NOPR was submitted under a 

temporary interim information collection no., FERC-556A (OMB Control No. 1902-0316)

because another item for FERC-556 was pending OMB review at the time and only one 

item per OMB Control No. can be pending OMB review at a time. The final rule is being 

submitted to OMB under FERC-556.
Docket Nos. RM19-15-000 and AD16-16-000 - 383 -

additional incremental reporting burdens that result from other aspects of this final rule. 

As described further below, we find that there is one additional potential reporting burden 

arising from this final rule. It relates to reducing the PURPA section 210(m) rebuttable 

presumption regarding small power production QFs’ nondiscriminatory access to certain 

markets from 20 MW to 5 MW. Specifically, this reporting burden would arise from 

electric utilities located in markets who choose to submit to the Commission a PURPA 

section 210(m) petition for termination of the PURPA mandatory purchase obligation 

(affecting information collection FERC-912) for small power production QFs between 20 

MW and 5 MW. 

698. With respect to the FERC Form No. 556, the Commission affirms that the relevant 

burdens derive from the change from the Commission’s current “one-mile rule” for 

determining whether generation facilities should be considered to be at the same site for 

purposes of determining qualification as a qualifying small power production facility, to 

allowing an interested person or other entity challenging a QF certification the opportunity 

to file a protest, without a fee, to rebut the presumption that affiliated small power 

production QFs using the same energy resource and located more than one mile and less 

than 10 miles from the applicant facility are considered to be at separate sites.

Specifically, as more fully explained in section IV.F above, and as demonstrated by the 

revised Form No. 556 attached to this final rule (but not published in the Federal Register
Docket Nos. RM19-15-000 and AD16-16-000 - 384 -

or Code of Federal Regulations),1049 the Commission makes the following changes to the 

FERC Form No. 556 which affect the burden of the information collection: 

• 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 selfcertification and application for Commission certification) filed on or after the 

effective date of this final rule, or to a recertification (self-recertification or 

application for Commission recertification) that makes substantive changes to the 

existing certification that is filed on or after the effective date of this final rule.

• Require all applicants to report the applicant facility’s geographic coordinates, 

rather than only for applications where there is no street address.

• Change the current requirement to identify any affiliated facilities with electrical 

generating equipment within one mile of the applicant facility’s electrical 

generating equipment to instead require applicants to list only affiliated small 

power production QFs using the same energy resource one mile or less from the 

applicant facility.

• Additionally require applicants to list affiliated small power production QFs using 

the same energy resource whose nearest electrical generating equipment is greater 

than one mile and less than 10 miles from the electrical generating equipment of 

the applicant facility.

1049 The Form 556 and instructions will be available in the Commission’s eLibrary.
Docket Nos. RM19-15-000 and AD16-16-000 - 385 -

• Require the applicant to list the geographic coordinates of the nearest “electrical 

generating equipment” of both its own facility and the affiliated small power 

production QF in question based on the definitions adopted in this final rule.

• Provide space for the applicant to explain, if it chooses to do so, why the affiliated 

small power production QFs using the same energy resource, that are more than 

one mile and less than 10 miles from the electrical generating equipment of the 

applicant facility, should be considered to be at separate sites from the applicant’s 

facility, considering the relevant physical and ownership factors identified in this 

final rule.

As explained in the body of this final rule, these changes in burden are appropriate 

because they are necessary to meet the statutory requirements contained in PURPA.

699. In this final rule, the Commission is revising its regulations implementing PURPA, 

which will affect the information collections for the FERC Form No. 556 and FERC-912. 

Below, the first table includes estimated changes to the burden and cost of the FERC Form 

No. 556 due to the final rule. As demonstrated by the table, we believe that QFs will 

spend more time to identify any affiliated small power production QFs that are less than 

one mile, between one and 10 miles, and more than 10 miles, apart. The Commission 

expects that there will be an increase due to the revisions to the Commission’s regulations, 

and that the changes to the “one-mile rule” and the ability to protest without a fee will 

affect self-certifications and applications for Commission certification. 
Docket Nos. RM19-15-000 and AD16-16-000 - 386 -

1050 The figures in this table reflect estimated changes to the current OMB-approved 

inventory for the FERC Form No. 556 (approved by the Office of Management and 

Budget (OMB) on November 18, 2019).

Where “no change” is indicated, the current figure is included parenthetically for 

information only. Those parenthetical figures are not included in the final total for 

column 5.

Commission staff believes that the industry is similarly situated in terms of wages 

and benefits. Therefore, cost estimates are based on FERC’s 2020 average hourly wage 

(and benefits) of $83.00/hour. (The submittal to and approval of OMB in 2019 for FERC 

Form No. 556 was based on FERC’s 2018 average annual wage hourly rate of 

$79.00/hour. Because the change from the $79.00 hourly rate to the current $83.00 hourly 

rate was not due to the final rule, this chart does not depict this increase.)

1051 Not required to file.

1052 In the FERC Form No. 556 approved by OMB in 2019, for the category “Small 

Power Production Facility > 1 MW, Self-certification,” we estimated the number of 

respondents at 2,698. We have now divided that category into three categories: “Small 

Power Production Facility > 1 MW, ≤ 1 Mile from Affiliated Small Power Production 

QF,” “Small Power Production Facility > 1 MW, > 1 Mile, < 10 Miles from Affiliated 

Small Power Production QF,” “Small Power Production Facility > 1 MW, ≥ 10 Miles 

from Affiliated Small Power Production QF.” In this column, the numbers 899, 900, and 

FERC-556, Changes Due to Final Rule in Docket Nos. RM19-15-000 and AD16-16-0001050

Facility Type Filing Type

Number of 

Respondents

(1)

Annual 

Number of 

Responses 

per 

Respondent

(2)

Total 

Number of 

Responses

(1)*(2)=(3)

Increased 

Average 

Burden 

Hours & 

Cost Per 

Response 

($)

(4)

Increased 

Total 

Annual 

Burden 

Hours & 

Total 

Annual 

Cost ($)

(3)*(4)=(5)

Increased 

Annual 

Cost per 

Respondent 

($)

(5)÷(1)=(6)

Cogeneration and 

Small Power 

Production Facility ≤ 1 

MW1051

Selfcertificationno 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

Selfcertificationno 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 

Selfcertificationno change 

(899)1052

no change

(1.25)

no change

(1,123.75)

2 hrs.;

$166

2,247.5 

hrs.; $207.5
Docket Nos. RM19-15-000 and AD16-16-000 - 387 -

700. The table below reflects the additional estimated public reporting burdens 

associated with reducing the PURPA section 210(m) rebuttable presumption regarding 

small power production QFs’ nondiscriminatory access to certain markets from 20 MW to 

5 MW, which affects the FERC-912.1053 The FERC-912 is optional, but if electric utilities 

899 are a distribution of those same estimated 2,698 respondents across the three 

categories.

1053 This information was not included in the burden estimates in the NOPR.

MW, ≤ 1 Mile from 

Affiliated Small Power 

Production QF

$186,542.5

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

Selfcertificationno 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

Selfcertificationno 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
Docket Nos. RM19-15-000 and AD16-16-000 - 388 -

located in relevant markets choose to submit to the Commission a PURPA section 210(m) 

petition for termination of the PURPA mandatory purchase obligation for small power 

production QFs between 20 MW and 5 MW, then we would expect the following burdens 

and cost estimates to apply.

FERC-912, Changes Due to Final Rule in Docket Nos. RM19-15-000 and AD16-16-000

(termination 

of obligation 

to purchase)

Number of 

Respondents

(1)

Annual 

Number of 

Responses per 

Respondent 

(2)

Total 

Number of 

Responses

(1)x(2)=(3)

Increased 

Average 

Hours & 

Cost Per 

Response 

($)

(4)

Increased 

Total Annual 

Burden Hours 

& Total 

Annual Cost 

($)

(3)*(4)=(5) 

Increased Annual 

Cost Per Respondent 

(at $83/hr.)

(5)/(1)=(6)

Electric 

utility burden 

of reducing 

210(m) 

rebuttable 

presumption 

from 20 MW 

to 5 MW1054 30 1 30

12 hrs.; 

$996

360 hrs.; 

$29,880 $996

Total 30 1 30

12 hrs.; 

$996

360 hrs.; 

$29,880 $996

Title: FERC-556 (Certification of Qualifying Facility (QF) Status for a Small Power 

Production or Cogeneration Facility), and FERC-912 (PURPA Section 210(m) 

Notification Requirements Applicable to Cogeneration and Small Power Production 

Facilities).

1054 The staff estimates a total of 90 discretionary responses may be submitted in 

Years 1-3, with an annual average of 30.
Docket Nos. RM19-15-000 and AD16-16-000 - 389 -

Action: Revisions to existing information collections FERC-556 and FERC-912.

OMB Control No.: 1902-0075 (FERC-556) and 1902-0237 (FERC-912).

Respondents: Facilities that are self-certifying their status as a cogenerator or small 

power producer or that are submitting an application for Commission certification of their 

status as a cogenerator or small power producer; electric utilities filing to terminate their 

obligation to purchase, at avoided cost rates, the output of small power production QFs 

between 5 MW and 20 MW.

Frequency of Information: Ongoing.

Necessity of Information: The Commission directs the changes in this final rule revising 

its implementation of PURPA in order to continue to meet PURPA’s statutory 

requirements. 

Internal Review: The Commission has reviewed the changes and has determined that 

such changes are necessary. These requirements conform to the Commission’s need for 

efficient information collection, communication, and management within the energy 

industry. 

701. Interested persons may obtain information on the reporting requirements by 

contacting the Federal Energy Regulatory Commission, 888 First Street, NE, Washington, 

DC 20426 [Attention: Ellen Brown, Office of the Executive Director], by email to 

DataClearance@ferc.gov or by phone (202) 502-8663]. 

Please send comments concerning the collection of information and the associated burden 

estimates to: Office of Information and Regulatory Affairs, Office of Management and 

Budget [Attention: Federal Energy Regulatory Commission Desk Officer]. Due to 
Docket Nos. RM19-15-000 and AD16-16-000 - 390 -

security concerns, comments should be sent directly to 

www.reginfo.gov/public/do/PRAMain. Comments submitted to OMB should be sent 

within 30 days of publication of this notice in the Federal Register and should refer to 

FERC-556 (OMB Control No. 1902-0075) and FERC-912 (OMB Control No. 1902-

0237).

VI. Environmental Analysis

702. The Commission in the NOPR explained that it was not possible to determine the 

environmental effects of the changes proposed, given the numerous uncertainties 

regarding the potential effects of the changes proposed. The Commission in the NOPR 

stated that, given these uncertainties, the National Environmental Policy Act of 1969 

(NEPA)1055 does not require that the Commission conduct an environmental review of the 

proposed revised PURPA Regulations.1056

A. Comments

703. Several commenters argue that the Commission erred in failing to conduct such a 

review.1057

704. Biological Diversity asserts an urgent need to take measures to reduce greenhouse 

gas emissions to address climate change.1058 Biological Diversity states that the 

1055 42 U.S.C. 4321 et seq.

1056 NOPR, 169 FERC ¶ 61,184 at PP 154-55.

1057 Allco Comments at 21-22; Biological Diversity Comments at 14; NIPPC, 

CREA, REC, and OSEIA Comments at 83; Public Interest Organizations Comments at 21.

1058 Biological Diversity Comments at 2-7.
Docket Nos. RM19-15-000 and AD16-16-000 - 391 -

Commission’s rationale for revising the PURPA Regulations, namely the increased 

availability of “fossil gas,” requires the Commission to consider the reasonably 

foreseeable impacts on climate and the environment, including on threatened and 

endangered species, in order to fulfill its responsibilities under NEPA and the Endangered 

Species Act (ESA).

1059 Biological Diversity includes a list of what it alleges are 

reasonably foreseeable impacts from increased use of “fossil gas.”1060 Biological 

Diversity maintains that the proposed revised PURPA Regulations would prevent 

renewable energy development and lock in “fossil gas” development and supply, thereby 

requiring the Commission to prepare an environmental impact statement and to obtain a 

biological opinion before proceeding to a final rule.1061

705. NIPPC, CREA, REC, and OSEIA state that “the Commission must, at a minimum, 

complete the requisite scoping and other process associated with an EA and then revise 

and reissue, or abandon, the NOPR after considering the issues developed in the EA.”1062 

NIPPC, CREA, REC, and OSEIA argue that it would not be too speculative for the 

Commission to undertake a NEPA analysis.1063 NIPPC, CREA, REC, and OSEIA state 

1059 Id. at 14.

1060 Id. at 15-17.

1061 Id. at 17.

1062 NIPPC, CREA, REC, and OSEIA Comments at 83-85 (citing, e.g., 42 U.S.C. 

4332(A); 18 CFR 380.5, 380.4, 380.11; 40 CFR 1500.1, 1502.5; LaFlamme v. FERC, 852 

F.2d 389, 397 (9th Cir. 1988); Am. Bird Conservancy, Inc. v. FCC, 516 F.3d 1027, 1033-

34 (D.C. Cir. 2008); N. Plains Res. Council, Inc. v. Surface Transp. Bd., 668 F.3d 1067, 

1075 (9th Cir. 2011) (N. Plains Res. Council)).

1063 NIPPC, CREA, REC, and OSEIA Comments at 92-94 (citing, e.g., Am. Bird 
Docket Nos. RM19-15-000 and AD16-16-000 - 392 -

that it is possible to study the environmental effects of the NOPR proposals because the 

Commission undertook a NEPA analysis when it first implemented PURPA, imposing a 

moratorium on certifying cogeneration facilities as QFs until it completed an 

Environmental Impact Statement (EIS) and recognizing the environmental benefits from 

encouraging the development of QFs, and also studied the environmental impacts for 

Order No. 888.1064

706. Public Interest Organizations state that the Commission must prepare an 

Environmental Assessment (EA) in order to support its position that this rulemaking may 

not have any significant foreseeable environmental impacts.1065 Public Interest 

Organizations describe the NOPR’s “cursory treatment of the Commission’s 

environmental review obligations” as undermining NEPA’s purposes “that agencies give 

due consideration to environmental impacts when making major environmental decisions, 

and guaranteeing that the public is informed of such impacts.”1066 Public Interest 

Organizations argue that states’ exercise of new flexibility granted by the proposed 

revised PURPA Regulations are reasonably foreseeable indirect and cumulative impacts 

that the Commission must study. Public Interest Organizations assert that the 

Commission likely will “need to prepare a full EIS to evaluate the serious environmental 

Conservancy, Inc. v. FCC, 516 F.3d 1033); N. Plains Res. Council, 668 F.3d at 1076, 

1078-79.

1064 Id. at 94-96.

1065 Public Interest Organizations Comments at 21.

1066 Id.
Docket Nos. RM19-15-000 and AD16-16-000 - 393 -

impacts that will result from dismantling regulations that continue to play an important 

role in development of renewable generation resources across the country.”1067

707. NIPPC, CREA, REC, and OSEIA argue that the Commission has failed to explain 

how eliminating the market for at least 10% to 20% of renewable energy facilities would 

have no impact on the human environment.1068 NIPPC, CREA, REC, and OSEIA contend 

that the Commission has failed to analyze how the proposals would impact regions like 

the Northwest that lack robust implementation of PURPA, the 21 states without renewable 

power standards (such as the Idaho, whose Legislature affirmatively refused to adopt a 

renewable power standard), or the one third of the country that is not located in an RTO or 

ISO.1069 

708. Allco argues that it is reasonably foreseeable that the proposed revisions to the 

PURPA Regulations and resulting increased fossil fuels use could add significant levels of 

greenhouse gas emissions to the atmosphere and endanger the climate.1070 The effects of 

such endangerment to the climate from fossil fuel use and reduced renewable energy QF 

generation, according to Allco, include mass extinction of species, in violation of the 

ESA.

1071 Allco contends that the Commission’s failure to consult with the U.S. Fish and 

1067 Id. at 26.

1068 NIPPC, CREA, REC, and OSEIA Comments at 86-87.

1069 Id. at 87-88.

1070 Allco Comments at 31.

1071 Id.
Docket Nos. RM19-15-000 and AD16-16-000 - 394 -

Wildlife Service and the National Marine Fisheries Service (collectively, the Services) 

prior to issuing the NOPR constituted a violation of its obligations under the ESA, “to 

insure that its actions are not likely to jeopardize the continued existence of endangered or 

threatened species, or result in the destruction or adverse modification of critical 

habitat.”1072

709. According to Allco, the PURPA NOPR triggered the ESA’s consultation 

requirement because the proposed changes will increase fossil fuel generation that will, in 

turn, displace “over 2 [terawatts (TWs)] of solar generation over the next 20 years as 

compared to the baseline scenario of application and faithful adherence to existing 

PURPA rules.”1073 Allco alleges that increased fossil-fuel generation will “increase land 

and ocean temperatures above what they would have been, . . . resulting in increased 

pollution to the waters of the United States, and harming federally endangered and 

threatened species, including, without limitation, the Piping plover and the Right 

whale.”1074

B. Commission Determination

710. We find that no EA or EIS of the final rule is required. NEPA requires federal 

agencies to prepare a detailed statement on the environmental impact of “major Federal 

actions significantly affecting the quality of the human environment.”1075 The Council on 

1072 Id. at 34 (quoting 16 U.S.C. 1536(a)(2)) (internal quotations omitted).

1073 Id.

1074 Id. at 34-35.

1075 42 U.S.C. 4332(C) (2018); see also Regulations Implementing the National 
Docket Nos. RM19-15-000 and AD16-16-000 - 395 -

Environmental Quality’s (CEQ) regulations implementing NEPA provide that federal 

agencies can comply with NEPA by preparing: (a) an Environmental Impact Statement 

(EIS); or (b) an Environmental Assessment (EA) to determine whether the proposed 

action significantly affects the quality of the human environment and requires the 

preparation of an EIS.1076 CEQ regulations also state that federal agencies are not 

obligated to prepare either an EIS or an EA if they find that a categorical exclusion 

applies.1077 Additionally, courts have held that an EIS or EA is not required under NEPA 

“unless there is a particular project that ‘define[s] fairly precisely the scope and limits of 

the proposed development.’”1078 

711. No EA or EIS of the final rule is required because, as discussed below, the final 

rule does not propose or authorize, much less define, the scope and limits of any potential 

energy infrastructure and, as a result, there is no way to determine whether issuance of the 

rule will significantly affect the quality of the human environment. In the alternative, a 

Environmental Policy Act, Order No. 486, FERC Stats. & Regs. ¶ 30,783 (1987) (crossreferenced at 41 FERC ¶ 61,284).

1076 40 CFR 1501.4 (2019).

1077 CEQ regulations state that a categorical exclusion “means a category of actions 

which do not individually or cumulatively have a significant effect on the human 

environment and which have been found to have no such effect in procedures adopted by 

a federal agency in implementation of these regulations and for which, therefore, neither 

an environmental assessment nor an environmental impact statement is required.” 40 

CFR 1508.4 (2019).

1078 Center for Biological Diversity v. Ilano, 928 F.3d 774, 780 (9th Cir. 2019)

(Center for Biological Diversity) (quoting Kleppe v. Sierra Club, 427 U.S. 390, 402

(1976)).
Docket Nos. RM19-15-000 and AD16-16-000 - 396 -

categorical exclusion applies so that an EA or EIS need not be prepared. For similar 

reasons, there is no requirement that the Commission engage in consultation pursuant to 

the ESA with respect to this action.

1. No EIS or EA is Required

a. There is no Project that Defines the Scope and Limits of 

QF Development

712. In Center for Biological Diversity, the court held that no NEPA review was 

required with respect to actions taken by the United States Forest Service that were similar 

in all relevant respects to the action taken here by the Commission in promulgating the 

final rule. That case involved the designation by the Forest Service, pursuant to the 

Healthy Forests Restoration Act (HFRA), of certain forests as “landscape-scale areas.” 

Such designation meant that specific treatments could be proposed to address insect 

infestation in those designated “landscape-scale areas.”1079 The court held that no NEPA 

review was required for the designations, noting that no specific projects were proposed 

for any of the landscape-scale areas and stating that “[i]n such circumstances, ‘any attempt 

to produce an [EIS] would be little more than a study . . . containing estimates of potential 

development and attendant environmental consequences.’”1080 The court concluded that 

“unless there is a particular project that ‘define[s] fairly precisely the scope and limits of 

1079 Center for Biological Diversity, 928 F.3d at 778.

1080 Id. at 780 (quoting Kleppe v. Sierra Club, 427 U.S. 390, 402 (1976)).
Docket Nos. RM19-15-000 and AD16-16-000 - 397 -

the proposed development of the region,’ there can be ‘no factual predicate for the 

production of an [EIS] of the type envisioned by NEPA.’”1081

713. Similarly, here, the final rule does not authorize the development or construction of 

any facilities, but simply addresses the rates that QFs can charge and certain requirements 

under which proposed facilities may qualify as a QF.1082 The final rule does not fund any 

particular QFs, or issue permits for their construction or operation (neither of which the 

Commission has jurisdiction to do). The Commission does not, in its regulations or in this 

final rule, authorize or prohibit the use of any particular technology or fuel, nor does it 

mandate or prohibit where QFs should be or are built. This final rule does not exempt 

QFs from any Federal, state, or local environmental, siting, or similar laws or regulatory 

requirements, (again something the Commission has no authority to do). 

714. Even with respect to rates, while the Commission has established and here revises 

the factors and approaches that states can take into account when they set QF rates, it is 

ultimately the states and not the Commission that set those rates. The final rule continues 

to give states wide discretion and it is impossible to know what the states may choose to 

1081 Id. (quoting Kleppe, 427 U.S. at 402); see also Northcoast Environmental 

Center v. Glickman, 136 F.3d 660, 668 (9th Cir. 1998) (citing Kleppe in support of its 

holding that NEPA does not require agency to complete environmental analysis where 

environmental effects are speculative or hypothetical).

1082 See Sugarloaf Citizens Ass’n v. FERC, 959 F.2d 508, 514 n.29 (4th Cir. 1992) 

(finding that in the QF certification context “FERC does little more than regulate the rates 

paid by utilities to the qualifying facility and does not control the financing, construction 

or operation of the project. Although the Facility receives an economic benefit, no direct 

federal funding or other substantial federal assistance is provided, and no licensing action 

is involved.”).
Docket Nos. RM19-15-000 and AD16-16-000 - 398 -

do in response to this final rule, whether they will make changes in their current practices 

or not, and how those state choices would impact QF development and the environment in 

any particular state, let along any particular locale. 

715. Moreover, the scope of this final rule is even less defined than the landscape-scale 

area designations at issue in the Center for Biological Diversity case. PURPA applies 

throughout the entire United States, and the revisions implemented by the final rule 

theoretically could affect future QF development anywhere in the country. 

716. While courts have held that NEPA requires “reasonable forecasting,” “NEPA does 

not require a ‘crystal ball’ inquiry.”1083 Further, an agency “is not required to engage in 

speculative analysis” or “to do the impractical, if not enough information is available to 

permit meaningful consideration”1084 or to “foresee the unforeseeable.”1085 In that vein, 

“[i]n determining what effects are ‘reasonably foreseeable,’ an agency must engage in 

‘reasonable forecasting and speculation,’ . . . with reasonable being the operative 

1083 Vt. Yankee Nuclear Power Corp. v. Nat. Res. Def. Council, Inc., 435 U.S. 519, 

534 (1978) (quoting Nat. Res. Def. Council, Inc. v. Morton, 458 F.2d 827, 837 (D.C. Cir. 

1972)).

1084 N. Plains Res. Council v. Surface Transp. Board, 668 F.3d 1067, 1078-79 (9th 

Cir. 2011) (citation omitted). 

1085 Concerned About Trident v. Rumsfeld, 555 F.2d 817, 830 (D.C. Cir. 1976)

(citation omitted).
Docket Nos. RM19-15-000 and AD16-16-000 - 399 -

word.”1086 Environmental impacts are not reasonably foreseeable if the impacts would 

result only through a lengthy causal chain of highly uncertain or unknowable events.1087

717. Commenters’ allegations regarding potentially reduced QF development hinge on 

the claim that the NOPR proposed to “repeal” or “eliminate” critical PURPA Regulations, 

which is not true. The Commission proposed in the NOPR, which this final rule generally 

affirms, to clarify some existing PURPA regulations and modify other PURPA 

Regulations to make them consistent with the statute, based on changed circumstances 

since the time those regulations originally were promulgated. Any consideration of 

whether the revised rules could potentially result in significant new environmental impacts 

due to less QF development and increased development of coal, nuclear, and combined 

cycle natural gas plants, would be highly speculative, based on the difficulty in 

determining which additional flexibilities the final rule provides to the states that each 

state will adopt, if any; how such state rules would impact QF development going 

forward; and whether any reduction in QF renewables would be replaced by the much 

1086 Sierra Club v. U.S. Dep’t of Energy, 867 F.3d 189, 198 (D.C. Cir. 2017) 

(emphasis in original) (citation omitted). 

1087 See Dep’t of Transp. v. Pub. Citizen, 541 U.S. 752, 767 (2004) (“NEPA 

requires a ‘reasonably close causal relationship’ between the environmental effect and the 

alleged cause.”); Metro. Edison Co. v. People Against Nuclear Energy, 460 U.S. 766, 774 

(1983) (noting effects may not fall within section 102 of NEPA because “the causal chain 

is too attenuated”).
Docket Nos. RM19-15-000 and AD16-16-000 - 400 -

greater amount of non-QF renewable resources with similar environmental 

characteristics.1088 

718. As was the case in Center for Biological Diversity, any attempt to evaluate the 

environmental effects of the final rule by necessity would involve nothing less than 

hypothesizing the potential development of QFs and the resultant environmental 

consequences. Indeed, any attempt by the Commission to estimate the potential 

environmental effects of the final rule would be considerably more speculative than the 

estimates of potential development and attendant environmental consequences that the 

court in Center for Biological Diversity held are not required under NEPA. That case

involved limited zones in which some projects to treat insect infestation almost certainly 

would be proposed. Here, it simply is not possible to provide any reasonable forecast of 

the effects of the final rule on future QF development, whether any affected potential QF 

would be a renewable resource (such as solar or wind) or employ carbon-emitting 

technology (e.g., a fossil-fuel-burning cogenerator or a waste-coal-burning small power 

production facility). Moreover, environmental effects on land use, vegetation, water 

quality, etc. are all dependent on location, which are unknown and could be anywhere in 

the United States. 

719. Because, even more so than in Center for Biological Diversity, the final rule does 

not authorize, or define any limit on the scope of, any potential QF or other infrastructure

development, any attempt to prepare an analysis of the potential effects of the final rule on 

1088 See infra VI.B.2.
Docket Nos. RM19-15-000 and AD16-16-000 - 401 -

future QF development would be so speculative as to render meaningless any 

environmental analysis of these impacts. Therefore, no such analysis is required by 

NEPA. 

b. A Categorical Exclusion Applies

720. There is a separate and independent alternative reason why no environmental 

analysis is warranted: the final rule falls within a categorical exclusion promulgated by 

the Commission pursuant to the CEQ’s NEPA regulations.1089 Specifically, the final rule 

falls within the categorical exclusion for rules that: (1) are clarifying in nature, (2) are 

corrective in nature, (3) are procedural in nature, or (4) do not substantially change the 

effect of the regulation being amended.1090 Here, each of the revisions to the PURPA 

Regulations implemented by the final rule fits into one of these categories:

i. Changes that are Clarifying in Nature

721. Several of the changes to the PURPA Regulations are clarifying in nature. These 

include the changes clarifying how market prices can be used to set as-available energy 

rates,1091 the changes clarifying how fixed energy rates in contracts or LEOs may be 

1089 CEQ regulations provide that agencies shall issue procedures that provide 

specific criteria for classes of action which “normally do not require either an 

environmental impact statement or an environmental assessment (categorical exclusion)”. 

40 CFR 1507.3 (2019).

1090 See 18 CFR 380.4(a)(2)(ii) (categorical exclusion applies to “promulgation of 

rules that are clarifying, corrective, or procedural, or that do not substantially change the 

effect of . . . regulations being amended.”).

1091 See Sections IV.B.2-5.
Docket Nos. RM19-15-000 and AD16-16-000 - 402 -

determined,1092 and the changes clarifying how competitive solicitations can be used to set 

avoided cost rates.1093 Other non-rate related clarifying revisions in the final rule include 

a clarification regarding the relationship between avoided costs and decreases in a 

purchasing utility’s load as a consequence of retail competition,1094 a clarification as to 

how electric generating equipment should be defined for purposes of determining whether 

small power production facilities are located at the same site,1095 and a clarification as to 

when a LEO is established.1096

ii. Changes that are Corrective in Nature

722. The Commission interprets the categorical exclusion for changes to its regulations 

that are corrective in nature as including changes needed in order to ensure that a 

regulation conforms to the requirements of the statutory provisions being implemented by 

the regulation.1097 To be clear, the Commission does not find that its existing PURPA 

1092 See Section IV.B.6.

1093 See Section IV.B.8.

1094 See Section IV.C.

1095 See Section IV.D.2.

1096 See Section IV.H. 

1097 For example, the Commission relied on this categorical exclusion when it 

revised the PURPA Regulations in 2006 to comply with the amendments to PURPA 

enacted as part of EPAct 2005. See Revised Regulations Governing Small Power 

Production and Cogeneration Facilities, Order No. 671, 114 FERC ⁋ 61,102 at P 118. 

Further, this interpretation is also consistent with the Supreme Court’s holding that NEPA 

review is not required when an agency’s action is required by statute. See Dep’t of 

Transp. v. Pub. Citizen, 541 U.S. 752, 770 (2004) (“where an agency has no ability to 

prevent a certain effect due to its limited statutory authority over the relevant actions, the 

agency cannot be considered a legally relevant “cause” of the effect [and] . . . under NEPA 
Docket Nos. RM19-15-000 and AD16-16-000 - 403 -

Regulations were inconsistent with the statutory requirements of PURPA when 

promulgated. Rather, the Commission finds that the changes adopted in this final rule are 

required to ensure continued future compliance of the PURPA Regulations with PURPA, 

based on the changed circumstances found by the Commission in this final rule. 

723. Three aspects of the final rule are corrective in nature. The first is the change 

allowing states to require variable energy rates in QF contracts.1098 As the Commission 

explains above, this change is required based on the Commission’s finding that, contrary 

to the Commission’s expectation in 1980, there have been numerous instances where 

overestimates and underestimates of energy avoided costs used in fixed energy rate 

contracts have not balanced out, causing the contract rate to not violate the statutory 

avoided cost rate cap. Giving states the ability to require energy rates in QF contracts to 

vary based on the purchasing utility’s avoided cost of energy at the time of delivery 

ensures that QF rates do not exceed the avoided cost rate cap imposed by PURPA.1099 

724. The second corrective aspect is the change in the PURPA Regulations regarding 

the determination of what facilities are located at the same site for purposes of complying 

with the statutory 80 MW limit on small power production facilities located at the same 

and the implementing CEQ regulations, the agency need not consider these effects in its 

EA.”); see also Safari Club Intern. v. Jewell, 960 F.Supp.2d 17, 79-80 (D.D.C. 2013) 

(relying on Dep’t of Transp. v. Pub. Citizen to hold that NEPA review is not required for

an agency rule issued to comply with a statutory requirement). 

1098 See Section IV.B.7.

1099 Id.
Docket Nos. RM19-15-000 and AD16-16-000 - 404 -

site.1100 As explained above, the Commission found, based on changed circumstances, 

that the current one-mile rule is inadequate to determine which facilities are located at the 

same site. Based on this finding, the Commission was obligated by PURPA to revise its 

definition of when facilities are located at the same site.1101

725. The third corrective aspect of the final rule relates to the implementation of PURPA 

section 210(m). That statutory provision allows purchasing utilities to terminate their 

obligation to purchase from QFs that have nondiscriminatory access to certain statutorilydefined markets, which the Commission has determined to be the RTO/ISO markets. The 

final rule revises the presumption in the PURPA Regulations that QFs with a capacity of 

20 MW or less do not have non-discriminatory access to such markets, reducing the 

threshold for such presumption to 5 MW.

1102 

726. The Commission has determined in the final rule that, since the 20 MW threshold 

was established in 2005, the RTO/ISO markets have matured and the industry has 

developed a better understanding of the mechanics of market participation. This 

determination has rendered inaccurate the presumption currently reflected in the PURPA 

Regulations that QFs 20 MW and below do not have non-discriminatory access to the 

relevant markets. Once the Commission made this determination, it was appropriate for 

1100 See Section IV.D.

1101 See Section IV.D.1.c.

1102 See Section IV.G.1.
Docket Nos. RM19-15-000 and AD16-16-000 - 405 -

the Commission to update the 20 MW threshold to comply with the requirements of 

PURPA section 210(m).1103

i. Changes that are Procedural in Nature

727. The remaining two revisions implemented by the final rule are procedural in nature. 

The first is a revision to the procedures that apply to QF certification.1104 The second is a 

revision to the Commission’s Form 556, used by QFs seeking certification.1105

2. The NEPA Analysis for Promulgation of the Original PURPA 

Regulations in 1980 Cannot be Replicated Here

728. As commenters note, in 1980 the Commission conducted an EA and later an EIS 

for its initial rules implementing PURPA. Initially, the Commission found (and the Final 

EIS also found) that new diesel cogeneration, and dual-fuel cogeneration particularly, in 

New York City, could cause significant environmental effects on air quality.1106 In Order 

No. 70-E, however, the Commission ultimately opted to treat such cogeneration the same 

as all other cogeneration given, among other things, that the PURPA Regulations were not 

the driving force behind the development of such cogeneration in New York City.1107 In 

doing so, the Commission emphasized that QF status was not a license nor a permit to 

operate but instead only entitled the QF to a rate for purchases and to certain exemptions 

1103 Id.

1104 See Section IV.E.

1105 See Section IV.F

1106 Final EIS at I-7a.

1107 See Order No. 70-E, 46 FR 33,025, 33,026 (June 18, 1981).
Docket Nos. RM19-15-000 and AD16-16-000 - 406 -

from regulation. Moreover, QFs were not exempted from any Federal, state, or local 

environmental, siting or other similar requirements.1108

729. The original PURPA EA for the pre-existing PURPA Regulations was based on a 

market penetration study of PURPA-induced facilities. In order to carry out that market 

penetration study, the original PURPA EA had to make the simplifying assumption that 

the mere implementation of PURPA would necessarily result in the development and 

operation of certain types of generation facilities that would not otherwise be 

1108 Id. The Commission stated in its EA that: 

The rules provide encouragement to the development of 

certain types of facilities. They do not prevent any facility 

which does not qualify from using cogeneration or small 

power production, or from using any type of fuel. The rules 

merely grant or deny certain benefits to certain facilities.

In this environmental assessment, the environmental effects of 

these rules are limited to the effects resulting from the 

construction and/or operation of facilities which occur as a 

result of the granting of these benefits, or from changes in the 

operating characteristics of existing facilities which results 

from the granting of these benefits. If a cogeneration or small 

power production facility would be constructed or operated 

without the incentives of these rules, the environmental effects 

resulting therefrom cannot properly be described as 

environmental effects of these rules. However, a technical and 

environmental discussion of each technology is provided 

whether or not its use is expected to be encouraged by these 

rules.

Small Power Production and Cogeneration Facilities--Environmental Findings; No 

Significant Impact and Notice of Intent To Prepare Environmental Impact Statement, 

45 FR 23,661, 23,664 (Apr. 8, 1980) (Original PURPA EA).
Docket Nos. RM19-15-000 and AD16-16-000 - 407 -

developed.1109 Based on these types of facilities, that EA identified specific resource 

conflicts related to each type of facility, which were nothing more than a generalized 

listing of potential impacts.1110 That EA found that, because the various types of facilities 

operate differently, there would be no cumulative impacts and this finding, coupled with 

the geographic distribution of facility development from the market penetration study, 

resulted in a finding of no significant impact for all types of facilities except diesel and 

dual-fueled cogeneration facilities in the Mid-Atlantic, which that EA found could cause 

significant environmental impacts on air quality.1111 

730. Subsequently, an EIS was prepared that addressed only air quality in New York 

City and the broader Mid-Atlantic region. The bulk of the EIS focused on how national, 

state, and local air pollution regimes would address air quality surrounding the 

construction and operation of such facilities.1112

731. Several commenters cite to this previous NEPA analysis conducted in connection 

with the original PURPA Regulations to support their assertion that a NEPA analysis 

similarly should be possible for this rulemaking. However, those assertions are 

undermined by the fact that circumstances have changed significantly since the 

promulgation of the original PURPA Regulations in 1980. Prior to 1980, essentially no 

1109 Id. at 23,665.

1110 Id. at 23,675-82.

1111 Id. at 23,679, 23,682-83.

1112 Order No. 70-E, 46 FR at 33,026.
Docket Nos. RM19-15-000 and AD16-16-000 - 408 -

QF generation technologies or other independent generation facilities (other than those 

used to supply the loads of the owners rather than to sell at wholesale) had been 

constructed. By contrast, today QF generation technologies and other independent 

generation facilities are common, and they are predominantly built and operated outside of 

PURPA.

1113

732. Because there was virtually no QF or independent power development in 1980, the 

original PURPA EA could reasonably project that the incentives created by PURPA and 

the original PURPA Regulations would lead to increased development of power generated 

by QF technologies. The market penetration study conducted by the Commission, and the 

Commission’s conclusion that the PURPA Regulations could lead to an increase in dieselfired cogeneration in New York City, were based on these projections.

733. By contrast, it is not possible here to make simplifying assumptions that the mere 

implementation of the revised regulations necessarily would result in specific changes in 

the development of particular generation technologies compared to the status quo. First, 

the revisions to the PURPA regulations are premised on a finding that, even after the 

revisions, the PURPA regulations will continue to encourage QFs. Consequently, there is 

no way to estimate whether any reduction in QF development, as opposed to the status 

quo, will be focused on one or more of the many different types of QF technologies, some 

of which are renewable resources and some of which are fueled by fossil fuels1114 and 

1113 See supra P 240.

1114 This would include both cogeneration, which typically is fossil fueled, and 

those small power production facilities that are fueled by waste, which would include a 
Docket Nos. RM19-15-000 and AD16-16-000 - 409 -

have emissions comparable to non-QF fossil fueled generators. Moreover, because the 

rule primarily increases state flexibility in setting QF rates, including giving states the 

option of not changing their current rate-setting approaches, there is no way to develop 

any estimate of the location or size of any hypothetical reduction in QF development. 

734. In addition, as mentioned above, renewable generation technologies today are 

commonly, and even predominantly, built and operated outside of PURPA. Current 

projections show that most new generation construction will be of renewable 

resources.1115 Indeed, the cost of renewables has declined so much that in some regions 

renewables are the most cost effective new generation technology available.1116 Thus, 

even if the final rule was to result in reduced renewable QF development, there is little 

likelihood today that hypothetical, unbuilt QFs necessarily would be replaced by new 

conventional fossil fuel generation. 

735. Alternatively, in the absence of these hypothetical, unbuilt QFs, existing generation 

units – whose current emissions, if any, would already be part of the baseline for any 

environmental analysis of the impacts of the final rule – might continue to operate without 

any change in their emissions; in sum, in the absence of these hypothetical, unbuilt QFs, 

emissions would remain at the baseline and might not increase at all. Indeed, in the 

range of fossil fuel-based waste. See 18 CFR 292.202(b), 292.204(b)(1).

1115 EIA, Annual Energy Outlook 2020, at tbl.9 (Jan. 29, 2020) (in table see rows 

labeled Cumulative Planned Additions and Cumulative Unplanned Additions in the 

reference case) (Annual Energy Outlook 2020), https://www.eia.gov/outlooks/aeo/.

1116 See supra P 240.
Docket Nos. RM19-15-000 and AD16-16-000 - 410 -

current environment where stagnant load growth has prevailed in recent years, this would 

seem to be a more likely scenario than an alternative where these hypothetical, unbuilt 

QFs are replaced by brand new fossil fuel generation that would increase emissions over 

the baseline. 

736. Given these facts, it would not be possible to perform a market penetration study 

of the effects of the final rule that would not be wholly speculative. Without such a study, 

there could be no analysis defining the types and geographic location of facilities that 

could serve as the basis for any NEPA analysis similar to that performed in 1980. 

3. This Proceeding Does Not Trigger Any ESA Consultation 

Requirement

737. Similar to our finding that it would be nearly impossible to conduct a meaningful 

NEPA review, we disagree with Biological Diversity and Allco that either the PURPA 

NOPR or this final rule trigger any consultation requirement under the ESA. 

The ESA requires that agencies consult with the Secretary of the Interior or the Secretary 

of Commerce to “insure that any action authorized, funded, or carried out by such 

agency . . . is not likely to jeopardize the continued existence of any endangered species 

or threatened species or result in the destruction or adverse modification of [critical] 

habitat of such species.”1117

1117 16 U.S.C. 1536(a)(2). 
Docket Nos. RM19-15-000 and AD16-16-000 - 411 -

738. The ESA regulations require consultation only if the Commission determines that a 

proposed action may affect listed species or critical habitat.1118 We find that there are no 

effects from the final rule for which the Commission could consult with the Services. 

Under the ESA regulations, as recently revised, the effects of an agency’s action are 

all consequences to listed species and critical habitat that are 

caused by the proposed action. A consequence is caused by the 

proposed action if it would not occur but for the proposed 

action and it is reasonably certain to occur.

1119

The ESA regulations also state that a consequence is not considered to be caused by a 

proposed action if “[t]he consequence is only reached through a lengthy causal chain that 

involves so many steps as to make the consequence not reasonably certain to occur.”1120 

This determination must be made “based on clear and substantial information,”1121 and 

“should not be based on speculation or conjecture.”1122 In addition to the above, the same 

ESA regulation states that factors for the agency to consider when determining whether a 

consequence is not caused by the proposed agency action include: “(1) The consequence 

is so remote in time from the action under consultation that it is not reasonably certain to 

1118 50 CFR 402.14(a).

1119 50 CFR 402.2 (emphasis added).

1120 50 CFR 402.17(b)(3) (emphasis added).

1121 Id.

1122 Endangered and Threatened Wildlife and Plants; Regulations for Interagency 

Cooperation, 84 FR 44976, 44993 (Aug. 27, 2019).
Docket Nos. RM19-15-000 and AD16-16-000 - 412 -

occur; or (2) [t]he consequence is so geographically remote from the immediate area 

involved in the action that it is not reasonably certain to occur[.]”1123

739. Because the NOPR was a proposed rule that in and of itself had no legal effect, the 

NOPR is not an agency “action” under the regulations implementing the ESA, which 

define agency action as the “the promulgation of regulations.”1124 Because the NOPR did

not constitute agency action, the Commission was not required to engage in consultation 

under the ESA prior to the NOPR’s issuance.

740. In this final rule, we are promulgating regulations, which does constitute agency 

action. Nevertheless, for the same reasons that an environmental review of the impacts of 

this final rule under NEPA would be impossible to conduct, there is similarly no basis to 

conclude that harm to endangered species is reasonably certain to occur as a result of this 

final rule. 

741. We find that the effects on endangered and threatened species alleged by Allco are 

not reasonably certain to occur, not only because any such harm is completely speculative, 

but also because it could result only through a lengthy causal chain of highly uncertain or 

unknowable events, none of which are within the Commission’s authority to authorize or 

preclude: (1) that the final rule causes a reduction in the aggregate amount of QF capacity 

constructed in the future; (2) that any reduction in renewable resource QFs would not be 

offset by increased construction of renewable resources outside of PURPA, resulting from 

1123 50 CFR 402.17(b).

1124 50 CFR 402.2 (emphasis added).
Docket Nos. RM19-15-000 and AD16-16-000 - 413 -

either other incentive programs or simply the increased cost-competitiveness of such 

resources; (3) that construction of such non-QF renewable resources would yield an 

increase in carbon emissions resulting from the reduction in renewable resource QFs that 

is not offset by other renewable resources; and (4) that such increase in carbon emissions 

would have an adverse effect on endangered and threatened species. Furthermore, the 

consequences of this rule would be remote in time and geographically remote because it 

would require action by individual generators, QF or non-QF, to propose, site, permit, 

construct, and operate a facility, in underdetermined locations potentially anywhere in the 

United States. In addition, many of these generators, QF and non-QF, would be subject to 

state approval and permitting requirements over which the Commission has no control. 

742. Further, there is no support in the record for Allco’s claim that the changes 

proposed in the PURPA NOPR would displace over 2 TWs of solar generation over the 

next 20 years.1125 Allco provides no citation or other support whatsoever for this assertion 

but simply makes the claim with no elaboration. We find that such speculation or 

conjecture provides no basis upon which to either initiate or conduct any meaningful 

consultation with the Services on the impacts to endangered species from this final rule.

VII. Regulatory Flexibility Act Certification

743. The Regulatory Flexibility Act of 1980 (RFA)1126 generally requires a description 

and analysis of rules that will have significant economic impact on a substantial number of 

1125 Allco Comments at 34.

1126 5 U.S.C. 601-12.
Docket Nos. RM19-15-000 and AD16-16-000 - 414 -

small entities. In lieu of preparing a regulatory flexibility analysis, an agency may certify 

that a rule will not have a significant economic impact on a substantial number of small 

entities.1127 The Commission in the NOPR stated that the proposed rule would not 

significantly impact a substantial number of small entities. Some commenters argue 

otherwise.1128

744. The Small Business Administration’s (SBA) Office of Size Standards develops the 

numerical definition of a small business.1129 The SBA size standard for electric utilities is 

based on the number of employees, including affiliates.1130 Under SBA’s current size 

standards, the threshold for a small entity (including its affiliates) is 250 employees for 

cogeneration and small power production applicants in the following NAICS1131

categories:

• NAICS code 221114 for Solar Electric Power Generation 

• NAICS code 221115 for Wind Electric Power Generation 

• NAICS code 221116 for Geothermal Electric Power Generation 

1127 5 U.S.C. 605(b). 

1128 See Allco Comments at 33.

1129 13 CFR 121.101.

1130 SBA final rule on “Small Business Size Standards: Utilities,” 78 FR 77343 

(Dec. 23, 2013).

1131 The North American Industry Classification System (NAICS) is an industry 

classification system that Federal statistical agencies use to categorize businesses for the 

purpose of collecting, analyzing, and publishing statistical data related to the U.S. 

economy. United States Census Bureau, North American Industry Classification System, 

https://www.census.gov/eos/www/naics/ (accessed April 11, 2018).
Docket Nos. RM19-15-000 and AD16-16-000 - 415 -

• NAICS code 221117 for Biomass Electric Power Generation 

• NAICS code 221118 for Other Electric Power Generation 

The threshold for a small entity (including its affiliates) is 500 employees for NAICS code 

221111 for Hydroelectric Power Generation.

745. This rule directly affects qualifying small power production facilities and 

cogeneration facilities, the majority of which the Commission estimates are small 

businesses. With respect to the changes related to the Form No. 556 and new protests 

allowed pursuant to this rule, as reflected in the burden and cost estimates provided above, 

the Commission does not anticipate that any additional reporting burden or cost imposed 

on QFs, regardless of their status as a small or large business, would be significant. Those 

revisions may result in additional information being submitted by some small power 

production QF applicants (especially those with affiliated small power production 

qualifying facilities using the same energy resource located over one and less than 10 

miles away). The Commission estimates that less than 10 percent of QF applications and 

self-certifications meet these criteria. 

746. In the final analysis, the other changes in this final rule1132 largely impact payments 

to QFs by electric utilities. More accurate avoided cost rates may result in lower 

1132 I.e., use of locational marginal prices, competitive market price, and use of 

forecasted stream of market revenues for energy rate component of QF contracts or legally 

enforceable obligations; use of variable energy rates in QF contracts or legally enforceable 

obligations; use of competitive solicitations to set avoided energy and capacity rates;

reducing the PURPA section 210(m) rebuttable presumption regarding access to markets 

from 20 MW to 5 MW; and the commercial viability and financial commitment to 

construct demonstration necessary to obtaining a legally enforceable obligation.
Docket Nos. RM19-15-000 and AD16-16-000 - 416 -

payments from certain electric utilities to certain QFs. In this regard, the final rule 

provides states greater flexibility than they have today to set the rate that electric utilities 

will pay QFs, but there is no way to know in advance which new flexibility state 

regulatory authorities and nonregulated electric utilities will exercise, or what impact that 

new flexibility might have given the different circumstances likely to apply to each 

determination of avoided cost. Under the final rule, additionally, states also have the 

discretion to continue setting the rate as they do today and not to adopt the Commission’ 

proposed greater rate flexibilities. Therefore, it is not possible to estimate what the dollar 

impact might be. However, because of the way PURPA is structured, whatever the 

potential dollar impacts of these changes on small QFs may be, to the extent that they 

reduce the amounts paid to certain QFs, such reductions could be matched dollar-fordollar by savings experienced by purchasing electric utilities, which should be flowed 

through to their retail ratepayers, some of whom would also tend to qualify as small 

entities.1133 

1133 While this potential beneficial impact on retail ratepayers would be an indirect 

impact of this final rule, the Small Business Administration Office of Advocacy 

encourages such indirect costs to be analyzed as well: “Although it is not required by the 

RFA, the Office of Advocacy believes that it is good public policy for the agency to 

perform a regulatory flexibility analysis even when the impacts of its regulation are 

indirect.” SBA, Office of Advocacy, A Guide for Government Agencies: How to Comply 

with the Regulatory Flexibility Act at 23 (Aug. 2017), 

https://www.sba.gov/sites/default/files/advocacy/How-to-Comply-with-the-RFAWEB.pdf. But see Mid-Tex Elec. Co-op., Inc. v. FERC, 773 F.2d 327, 343 (D.C. Cir. 

1985) (“Congress did not intend to require that every agency consider every indirect effect 

that any regulation might have on small businesses in any stratum of the national 

economy.”).
Docket Nos. RM19-15-000 and AD16-16-000 - 417 -

747. While Allco argues that the Commission should have attempted to minimize the 

impacts on small renewable energy producers and consider alternative structures, the fact 

is that these offsetting impacts result from changes that are necessary to ensure the 

Commission’s regulations continue to meet PURPA’s statutory requirements. For 

example, allowing states to use competitive prices may benefit small QFs inasmuch as the 

rate-setting process for purchases of energy from these entities would be more 

straightforward and efficient than the administrative processes currently in use. 

Furthermore, providing flexibility in setting energy rates may result in state entities 

approving longer duration contracts for capacity (at fixed rates) and energy. The impacts 

of these changes, therefore, are reasonable alternatives to the status quo while adhering to 

the requirements of PURPA. 

748. This final rule establishes a rebuttable presumption that a qualifying small power 

production facility whose electrical generating equipment is more than one but less than 

10 miles from affiliated electrical generating equipment using the same energy resource is 

at a separate site. The Commission finds that this rebuttable presumption imposes a lower 

burden than imposing a rule that any affiliated electrical generating equipment less than

10 miles apart is presumed to be at the same site. Similarly, the Commission, while 

removing the rebuttable presumption that qualifying small power production facilities 

more than 5 MW but under 20 MW lack nondiscriminatory access, has provided factors 

that such facilities could use to demonstrate lack of such access – allowing them to retain 

the mandatory purchase obligation. The Commission estimates that annual additional 

compliance costs on industry (detailed above) will be approximately $1,149,965 (or an 
Docket Nos. RM19-15-000 and AD16-16-000 - 418 -

average additional burden and cost per response, of 3.187 hrs. and the corresponding 

$264.51) to comply with these requirements.1134 

749. Accordingly, pursuant to section 605(b) of the RFA, the Commission certifies that 

this rule will not have a significant economic impact on a substantial number of small 

entities. 

VIII. Document Availability

750. In addition to publishing the full text of this document in the Federal Register, the 

Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through the Commission’s Home Page 

(http://www.ferc.gov). At this time, the Commission has suspended access to the 

Commission’s Public Reference Room due to the President’s March 13, 2020 

proclamation declaring a National Emergency concerning the Novel Coronavirus Disease 

(COVID-19).

751. From the Commission’s Home Page on the Internet, this information is available 

on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft 

Word format for viewing, printing, and/or downloading. To access this document in 

eLibrary, type the docket number excluding the last three digits of this document in the 

docket number field.

1134 Annual additional cost of $1,149,965 [($1,120,085 for FERC-556)+(29,880 for 

FERC-912)] and average additional burden of 13,855 hours [(13,495 hrs. for FERC556)+(360 hrs. for FERC-912)] divided by the number of affected responses of 4,347.5

[(4,317.5 for FERC-556)+(30 responses for FERC-912)]. 
Docket Nos. RM19-15-000 and AD16-16-000 - 419 -

752. User assistance is available for eLibrary and the Commission’s website during 

normal business hours from the Commission’s Online Support at 202-502-6652 (toll free 

at 1-866-208-3676) or email at ferconlinesupport@ferc.gov, or the Public Reference 

Room at (202) 502-8371, TTY (202)502-8659. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov.

IX. Effective Dates and Congressional Notification

753. These regulations are effective [INSERT DATE 120 DAYS AFTER THE DATE 

OF PUBLICATION IN THE FEDERAL REGISTER]. The Commission has 

determined, with the concurrence of the Administrator of the Office of Information and 

Regulatory Affairs of OMB, that this rule is not a “major rule” as defined in section 351 of 

the Small Business Regulatory Enforcement Fairness Act of 1996. This final rule is being 

submitted to the Senate, House, Government Accountability Office, and Small Business 

Administration.

List of subjects in 18 CFR Part 292 

Electric power plants; Electric utilities, Reporting and recordkeeping requirements .

List of subjects in 18 CFR Part 375

Authority delegations (Government agencies); Seals and insignia; Sunshine Act.

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

 attached.

( S E A L )

Nathaniel J. Davis, Sr.,

Deputy Secretary.
Docket Nos. RM19-15-000 and AD16-16-000 - 420 -

In consideration of the foregoing, the Commission proposes to amend Parts 292 

and 375, Chapter I, Title 18, Code of Federal Regulations, as follows.

SUBCHAPTER K – REGULATIONS UNDER THE PUBLIC UTILITY 

REGULATORY POLICIES ACT OF 1978

* * * * * 

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. Section 292.101 is revised to add paragraphs (12) through (16):

§ 292.101 Definitions.

* * * * *

(12) Locational marginal price means the price for energy at a particular location 

as determined in a market defined in § 292.309(e), (f), or (g).

(13) Competitive Price means a Market Hub Price or a Combined Cycle Price.

(14) Market Hub Price means a price for as-delivered energy determined pursuant 

to § 292.304(b)(7)(i).

(15) Combined Cycle Price means a price for as-delivered energy determined 

pursuant to § 292.304(b)(7)(ii).

(16) Competitive Solicitation Price means a price for energy and/or capacity 
Docket Nos. RM19-15-000 and AD16-16-000 - 421 -

determined pursuant to § 292.304(b)(8).

3. Section 292.202 is revised to add paragraph (t):

§ 292.202 Definitions.

* * * * * 

(t) Electrical generating equipment means all boilers, heat recovery steam 

generators, prime movers (any mechanical equipment driving an electric generator), 

electrical generators, photovoltaic solar panels, inverters, fuel cell equipment and/or other 

primary power generation equipment used in the facility, excluding equipment for 

gathering energy to be used in the facility.

4. Section 292.204(a) is revised to read:

§ 292.204 Criteria for qualifying small power production facilities.

(a) Size of the facility—

(1) Maximum size. Except as provided in paragraph (a)(4) of this section, the power 

production capacity of a facility for which qualification is sought, together with the power 

production capacity of any other small power production qualifying facilities that use the 

same energy resource, are owned by the same person(s) or its affiliates, and are located at 

the same site, may not exceed 80 megawatts.

(2) Method of calculation.

(i) (A) For purposes of this paragraph, there is an irrebuttable presumption that 

affiliated small power production qualifying facilities that use the same energy resource 

and are located one mile or less from the facility for which qualification or recertification 
Docket Nos. RM19-15-000 and AD16-16-000 - 422 -

is sought are located at the same site as the facility for which qualification or 

recertification is sought. 

(B) For purposes of this paragraph, for facilities for which qualification or 

recertification is filed on or after [INSERT DATE 120 DAYS AFTER THE DATE 

OF PUBLICATION IN THE FEDERAL REGISTER] there is an irrebuttable 

presumption that affiliated small power production qualifying facilities that use the same 

energy resource and are located 10 miles or more from the facility for which qualification

or recertification is sought are located at separate sites from the facility for which 

qualification or recertification is sought. 

(C) For purposes of this paragraph, for facilities for which qualification or 

recertification is filed on or after [INSERT DATE 120 DAYS AFTER THE DATE 

OF PUBLICATION IN THE FEDERAL REGISTER], there is a rebuttable 

presumption that affiliated small power production qualifying facilities that use the same 

energy resource and are located more than one mile and less than 10 miles from the 

facility for which qualification or recertification is sought are located at separate sites 

from the facility for which qualification or recertification is sought. 

(D) For hydroelectric facilities, facilities are considered to be located at the same 

site as the facility for which qualification or recertification is sought if they are located 

within one mile of the facility for which qualification or recertification is sought and use 

water from the same impoundment for power generation.
Docket Nos. RM19-15-000 and AD16-16-000 - 423 -

(ii) For purposes of making the determinations in clause (i), the distance between 

two facilities shall be measured from the edge of the closest electrical generating 

equipment for which qualification or recertification is sought to the edge of the nearest

electrical generating equipment of the other affiliated small power production qualifying 

facility using the same energy resource. 

(3) Waiver. The Commission may modify the application of paragraph (a)(2) of 

this section, for good cause.

(4) Exception. Facilities meeting the criteria in section 3(17)(E) of the Federal 

Power Act (16 U.S.C. 796(17)(E)) have no maximum size, and the power production 

capacity of such facilities shall be excluded from consideration when determining the size 

of other small power production facilities less than 10 miles from such facilities.

* * * * * 

5. Section 292.207(a) and (b) is revised to read:

§ 292.207 Procedures for obtaining qualifying status.

(a) Self-certification.

(1) FERC Form No. 556. The qualifying facility status of an existing or a proposed 

facility that meets the requirements of § 292.203 may be self-certified by the owner or 

operator of the facility or its representative by properly completing a FERC Form No. 556 

and filing that form with the Commission, pursuant to § 131.80 of this chapter, and 

complying with paragraph (e) of this section.
Docket Nos. RM19-15-000 and AD16-16-000 - 424 -

(2) Factors. For small power production facilities pursuant to § 292.204, the owner 

or operator of the facility or its representative may, when completing the FERC Form No. 

556, provide information asserting factors showing that the facility for which qualification 

or recertification is sought is at a separate site from other facilities using the same energy 

resource and owned by the same person(s) or its affiliates. 

(3) Commission action. Self-certification and self-recertification are effective 

upon filing. If no protests to a self-certification or self-recertification are timely filed 

pursuant to § 292.207(c), no further action by the Commission is required for a selfcertification or self-recertification to be effective. If protests to a self-certification or selfrecertification are timely filed pursuant to § 292.207(c), a self-certification or selfrecertification will remain effective until the Commission issues an order revoking QF 

certification. The Commission will act on the protest within 90 days from the date the 

protest is filed; provided that, if the Commission requests more information from the 

protester, the entity seeking qualification or recertification, or both, the time for the 

Commission to act will be extended to 60 days from the filing of a complete answer to the 

information request. In addition to any extension resulting from a request for information, 

the Commission also may toll the 90-day period for one additional 60-day period if so 

required to rule on a protest. Authority to toll the 90-day period for this purpose is 

delegated to the Secretary or the Secretary’s designee. Absent Commission action before

the expiration of the tolling period, a protest will be deemed denied, and the selfcertification or self-recertification will remain effective. 
Docket Nos. RM19-15-000 and AD16-16-000 - 425 -

(b) Optional procedure—Commission certification. 

(1) Application for Commission certification. In lieu of the self-certification 

procedures in paragraph (a) of this section, an owner or operator of an existing or a 

proposed facility, or its representative, may file with the Commission an application for 

Commission certification that the facility is a qualifying facility. The application must be 

accompanied by the fee prescribed by part 381 of this chapter, and the applicant for 

Commission certification must comply with paragraph (c) of this section.

(2) General contents of application. The application must include a properly 

completed FERC Form No. 556 pursuant to § 131.80 of this chapter. For small power 

production facilities pursuant to § 292.204, the owner or operator of the facility or its 

representative may, when completing the FERC Form No. 556, provide information 

asserting factors showing that the facility for which qualification is sought is at a separate 

site from other facilities using the same energy resource and owned by the same person(s) 

or its affiliates.

* * * * *

(c) Protests and Interventions. 

(i) Filing a Protest. Any person, as defined in § 385.102(d) of this chapter, who 

opposes either a self-certification or self-recertification making substantive changes to the 

existing certification filed pursuant to § 292.207(a) or an application for Commission 

certification or Commission recertification making substantive changes to the existing 

certification filed pursuant to § 292.207(b) for which qualification or recertification is 

filed on or after [INSERT DATE 120 DAYS AFTER THE DATE OF PUBLICATION 
Docket Nos. RM19-15-000 and AD16-16-000 - 426 -

IN THE FEDERAL REGISTER], may file a protest with the Commission. Any protest 

to and any intervention in a self-certification or self-recertification must be filed in 

accordance with §§ 385.211 and 385.214 of this chapter, on or before 30 days from the 

date the self-certification or self-recertification is filed. Any protestor must concurrently 

serve a copy of such filing pursuant to § 385.211 of this chapter. Any protest must be 

adequately supported, and provide any supporting documents, contracts, or affidavits to 

substantiate the claims in the protest. 

(ii) Limitations on protest. Protests may be filed to any initial self-certification or 

application for Commission certification filed on or after the effective date of this final 

rule, and to any self-recertification or application for Commission recertification that are 

filed on or after [INSERT DATE 120 DAYS AFTER THE DATE OF PUBLICATION 

IN THE FEDERAL REGISTER] that makes substantive changes to the existing 

certification. Once the Commission has certified an applicant’s qualifying facility status 

either in response to a protest opposing a self-certification or self-recertification, or in 

response to an application for Commission certification or Commission recertification, 

any later protest to a self-recertification or application for Commission recertification

making substantive changes to a qualifying facility’s certification must demonstrate 

changed circumstances that call into question the continued validity of the certification.

(d) Response to protests. Any response to a protest must be filed on or before 30 

days from the date of filing of that protest and will be allowed under § 385.213(a)(2) of 

this chapter.
Docket Nos. RM19-15-000 and AD16-16-000 - 427 -

(e) Notice requirements.

(1) General. An applicant filing a self-certification, self-recertification, application 

for Commission certification or application for Commission recertification of the 

qualifying status of its facility must concurrently serve a copy of such filing on each 

electric utility with which it expects to interconnect, transmit or sell electric energy to, or 

purchase supplementary, standby, back-up or maintenance power from, and the State 

regulatory authority of each state where the facility and each affected electric utility is 

located. The Commission will publish a notice in the Federal Register for each application 

for Commission certification and for each self-certification of a cogeneration facility that 

is subject to the requirements of § 292.205(d).

(2) Facilities of 500 kW or more. An electric utility is not required to purchase 

electric energy from a facility with a net power production capacity of 500 kW or more 

until 90 days after the facility notifies the facility that it is a qualifying facility or 90 days 

after the utility meets the notice requirements in paragraph (c)(1) of this section.

(f) Revocation of qualifying status.

(1)(i) If a qualifying facility fails to conform with any material facts or 

representations presented by the cogenerator or small power producer in its submittals to 

the Commission, the notice of self-certification or Commission order certifying the 

qualifying status of the facility may no longer be relied upon. At that point, if the facility 

continues to conform to the Commission's qualifying criteria under this part, the 

cogenerator or small power producer may file either a notice of self-recertification of 

qualifying status pursuant to the requirements of paragraph (a) of this section, or an 
Docket Nos. RM19-15-000 and AD16-16-000 - 428 -

application for Commission recertification pursuant to the requirements of paragraph (b) 

of this section, as appropriate.

(ii) The Commission may, on its own motion or on the motion of any person, 

revoke the qualifying status of a facility that has been certified under paragraph (b) of this 

section, if the facility fails to conform to any of the Commission's qualifying facility 

criteria under this part.

(iii) The Commission may, on its own motion or on the motion of any person, 

revoke the qualifying status of a self-certified or self-recertified qualifying facility if it 

finds that the self-certified or self-recertified qualifying facility does not meet the 

applicable requirements for qualifying facilities.

(2) Prior to undertaking any substantial alteration or modification of a qualifying 

facility which has been certified under paragraph (b) of this section, a small power 

producer or cogenerator may apply to the Commission for a determination that the 

proposed alteration or modification will not result in a revocation of qualifying status. 

This application for Commission recertification of qualifying status should be submitted 

in accordance with paragraph (b) of this section.

6. Section 292.304(b), (d), and (e) is revised to read:

§ 292.304 Rates for purchases.

* * * * *

(b) Relationship to avoided costs.
Docket Nos. RM19-15-000 and AD16-16-000 - 429 -

* * *

(6) Locational Marginal Price. There is a rebuttable presumption that a state 

regulatory authority or nonregulated electric utility may use a Locational Marginal Price 

as a rate for as-available qualifying facility energy sales to electric utilities located in a 

market defined in § 292.309(e), (f), or (g). 

(7) Competitive Price. A state regulatory authority or nonregulated electric 

utility may use a Competitive Price as a rate for as-available qualifying facility energy 

sales to electric utilities located outside a market defined in § 292.309(e), (f), or (g). A 

Competitive Price may be either a Market Hub Price or a Combined Cycle Price, 

determined as follows:

(i) A Market Hub Price is a price established at a liquid market hub which a state 

regulatory authority or nonregulated electric utility determines represents an appropriate 

measure of the electric utility’s avoided cost for as-available energy, and is a hub to which 

the electric utility has reasonable access, based on an evaluation by the state regulatory 

authority or nonregulated electric utility of the relevant factors, including but not limited 

to the following:

(A) whether the hub is sufficiently liquid that prices at the hub represent a 

competitive price; 

(B) whether prices developed at the hub are sufficiently transparent;

(C) whether the electric utility has the ability to deliver power from such hub 

to its load, even if its load is not directly connected to the hub; and

(D) whether the hub represents an appropriate market to derive an energy 
Docket Nos. RM19-15-000 and AD16-16-000 - 430 -

price for the electric utility’s purchases from the relevant qualifying facility given 

the electric utility’s physical proximity to the hub or other factors. 

(ii) A Combined Cycle Price is a price determined pursuant to a formula 

established by a state regulatory authority or nonregulated electric utility using published 

natural gas price indices, a proxy heat rate, and variable operations and maintenance costs

for an efficient natural gas combined-cycle generating facility. Before establishing such a 

formula rate, a state regulatory authority or nonregulated electric utility must determine 

that the resulting Combined Cycle Price represents an appropriate measure of the 

purchasing electric utility’s avoided cost for energy, based on its evaluation of the relevant 

factors, including but not limited to the following: 

(A) whether the cost of energy from an efficient natural gas combined 

cycle generating facility represents a reasonable measure of a competitive 

price in the purchasing electric utility’s region; 

(B) whether natural gas priced pursuant to particular proposed natural 

gas price indices would be available in the relevant market; 

(C) whether there should be an adjustment to the natural gas price to 

appropriately reflect the cost of transporting natural gas to the relevant 

market; and 

(D) whether the proxy heat rate used in the formula should be 

updated regularly to reflect improvements in generation technology. 

(8) Competitive Solicitation Price. (i) A state regulatory authority or 

nonregulated electric utility may use a price determined pursuant to a competitive 
Docket Nos. RM19-15-000 and AD16-16-000 - 431 -

solicitation process to establish qualifying facility energy and/or capacity rates for sales to 

electric utilities, provided that such competitive solicitation process is conducted pursuant 

to procedures ensuring the solicitation is conducted in a transparent and nondiscriminatory manner including, but not limited to, the following:

(A) the solicitation process is an open and transparent process that includes, 

but is not limited to, providing equally to all potential bidders substantial and 

meaningful information regarding transmission constraints, levels of congestion, 

and interconnections, subject to appropriate confidentiality safeguards; 

(B) solicitations are open to all sources, to satisfy that electric utility’s 

capacity needs, taking into account the required operating characteristics of the 

needed capacity;

(C) solicitations are conducted at regular intervals; 

(D) solicitations are subject to oversight by an independent administrator; 

and 

(E) solicitations are certified as fulfilling the above criteria by the relevant 

state regulatory authority or nonregulated electric utility through a post-solicitation 

report.

(ii) To the extent that the electric utility procures all of its capacity, including 

capacity resources constructed or otherwise acquired by the electric utility, through a 

competitive solicitation process conducted pursuant to subsection (8)(i), 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 
Docket Nos. RM19-15-000 and AD16-16-000 - 432 -

utility shall nevertheless be required to purchase energy from qualifying small power 

producers and qualifying cogeneration facilities.

(iii) To the extent that the electric utility does not procure all of its capacity 

through a competitive solicitation process conducted pursuant to subsection (8)(i), then 

there shall be no presumption that the electric utility has no avoided capacity costs.

* * * * *

(d) Purchases “as available” or pursuant to a legally enforceable obligation.

(1) Each qualifying facility shall have the option either:

(i) To provide energy as the qualifying facility determines such energy to be available 

for such purchases, in which case the rates for such purchases shall be based on the 

electric utility’s avoided cost for energy calculated at the time of delivery; or

(ii) To provide energy or capacity pursuant to a legally enforceable obligation for the 

delivery of energy or capacity over a specified term, in which case the rates for such 

purchases shall, except as provided in subsection (d)(2) below, be based on either:

(A) The avoided costs calculated at the time of delivery; or

(B) The avoided costs calculated at the time the obligation is incurred.

(iii) The rate for delivery of energy calculated at the time the obligation is incurred 

may be based on estimates of the present value of the stream of revenue flows of future 

locational marginal prices, or Competitive Prices during the anticipated period of delivery.

(2) Notwithstanding paragraph (d)(1)(ii)(B), a state regulatory authority or 

nonregulated electric utility may require that rates for purchases of energy from a 

qualifying facility pursuant to a legally enforceable obligation vary through the life of the 
Docket Nos. RM19-15-000 and AD16-16-000 - 433 -

obligation, and be set at the electric utility’s avoided cost for energy calculated at the time 

of delivery. 

(3) Obtaining a legally enforceable obligation. A qualifying facility must 

demonstrate commercial viability and financial commitment to construct its facility 

pursuant to criteria determined by the state regulatory authority or nonregulated electric 

utility as a prerequisite to a qualifying facility obtaining a legally enforceable obligation. 

Such criteria must be objective and reasonable.

(e) Factors affecting rates for purchases. 

(1) A state regulatory authority or nonregulated electric utility may establish rates for 

purchases of energy from a qualifying facility based on a purchasing electric utility’s 

locational marginal price calculated by the applicable market defined in § 292.309(e), (f), 

or (g), or the purchasing electric utility’s applicable Competitive Price. Alternatively, a 

state regulatory authority or nonregulated electric utility may establish rates for purchases 

of energy and/or capacity from a qualifying facility based on a Competitive Solicitation 

Price. To the extent that capacity rates are not set pursuant to this section, capacity rates 

shall be set pursuant to subsection (2).

(2) To the extent that a state regulatory authority or nonregulated electric utility does 

not set energy and/or capacity rates pursuant to subsection (1), the following factors shall, 

to the extent practicable, be taken into account in determining rates for purchases from a 

qualifying facility:

(i) The data provided pursuant to § 292.302(b), (c), or (d), including State review of 

any such data;
Docket Nos. RM19-15-000 and AD16-16-000 - 434 -

(ii) The availability of capacity or energy from a qualifying facility during the system 

daily and seasonal peak periods, including:

(A) The ability of the electric utility to dispatch the qualifying facility;

(B) The expected or demonstrated reliability of the qualifying facility;

(C) The terms of any contract or other legally enforceable obligation, including the 

duration of the obligation, termination notice requirement and sanctions for noncompliance;

(D) The extent to which scheduled outages of the qualifying facility can be usefully 

coordinated with scheduled outages of the electric utility’s facilities;

(E) The usefulness of energy and capacity supplied from a qualifying facility during 

system emergencies, including its ability to separate its load from its generation;

(F) The individual and aggregate value of energy and capacity from qualifying 

facilities on the electric utility’s system; and

(G) The smaller capacity increments and the shorter lead times available with 

additions of capacity from qualifying facilities; and

(iii) The relationship of the availability of energy or capacity from the qualifying 

facility as derived in paragraph (e)(2)(ii) of this section, to the ability of the electric utility 

to avoid costs, including the deferral of capacity additions and the reduction of fossil fuel 

use; and

(iv) The costs or savings resulting from variations in line losses from those that would 

have existed in the absence of purchases from a qualifying facility, if the purchasing 
Docket Nos. RM19-15-000 and AD16-16-000 - 435 -

electric utility generated an equivalent amount of energy itself or purchased an equivalent 

amount of electric energy or capacity.

* * * * *

7. Section 292.309(c), (d), (e), and (f) is revised to read as follows:

§ 292.309 Termination of obligation to purchase from qualifying facilities.

* * * * *

(c) For purposes of § 292.309(a)(1), (2) and (3), 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 Commissionapproved 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 § 292.309(a)(1), 

(2) or (3), 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 § 292.309(a)(1), (2), and (3), 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: 
Docket Nos. RM19-15-000 and AD16-16-000 - 436 -

(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 § 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. 

(d)(1) For purposes of § 292.309(a)(1), (2), and (3), there is a rebuttable presumption 

that a qualifying cogeneration facility with a capacity at or below 20 megawatts does not 

have nondiscriminatory access to the market.

(2) For purposes of § 292.309(a)(1), (2), and (3), there is a rebuttable presumption 

that a qualifying small power production facility with a capacity at or below 5 megawatts

does not have nondiscriminatory access to the market.
Docket Nos. RM19-15-000 and AD16-16-000 - 437 -

(3) Nothing in § 292.309 (d)(1)-(d)(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 [INSERT DATE 

120 DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], 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 (d)(2) of this section, the 

Commission will not be bound by the standards set forth in § 292.204(a)(2).

(e) Midcontinent Independent System Operator, Inc. (MISO), PJM Interconnection, 

L.L.C. (PJM), ISO New England Inc. (ISO-NE), and New York Independent System 

Operator, Inc. (NYISO) qualify as markets described in § 292.309(a)(1)(i) and (ii), and 

there is a rebuttable presumption that small power production facilities with a capacity 

greater than 5 megawatts and cogeneration facilities with a capacity greater than 20 

megawatts have nondiscriminatory access to those markets through Commission-approved 

open access transmission tariffs and interconnection rules, and that electric utilities that 

are members of such regional transmission organizations or independent system operators 

(RTO/ISOs) should be relieved of the obligation to purchase electric energy from the 

qualifying facilities. A qualifying facility may seek to rebut this presumption by 

demonstrating, inter alia, that:

(1) The qualifying facility has certain operational characteristics that effectively 
Docket Nos. RM19-15-000 and AD16-16-000 - 438 -

prevent the qualifying facility's participation in a market; or

(2) The qualifying facility lacks access to markets due to transmission constraints. 

The qualifying facility may show that it is located in an area where persistent transmission 

constraints in effect cause the qualifying facility not to have access to markets outside a 

persistently congested area to sell the qualifying facility output or capacity.

(f) The Electric Reliability Council of Texas (ERCOT) qualifies as a market 

described in § 292.309(a)(3), and there is a rebuttable presumption that small power 

production facilities with a capacity greater than five megawatts and cogeneration 

facilities with a capacity greater than 20 megawatts have nondiscriminatory access to that 

market through Public Utility Commission of Texas (PUCT) approved open access 

protocols, and that electric utilities that operate within ERCOT should be relieved of the 

obligation to purchase electric energy from the qualifying facilities. A qualifying facility 

may seek to rebut this presumption by demonstrating, inter alia, that:

(1) The qualifying facility has certain operational characteristics that effectively 

prevent the qualifying facility’s participation in a market; or

(2) The qualifying facility lacks access to markets due to transmission constraints. 

The qualifying facility may show that it is located in an area where persistent transmission 

constraints in effect cause the qualifying facility not to have access to markets outside a 

persistently congested area to sell the qualifying facility output or capacity.

* * * * *
Docket Nos. RM19-15-000 and AD16-16-000 - 439 -

SUBCHAPTER W – REVISED GENERAL RULES

* * * * * 

PART 375 – THE COMMISSION

1. The authority citation for part 375 continues to read as follows:

 Authority: 5 U.S.C. 551-557; 15 U.S.C. 717-717w, 3301-3432; 16 U.S.C. 791-825r, 

2601-2645; 42 U.S.C. 7101-7352.

2. Section 375.302(v) is revised to read:

§ 375.302 Delegations to the Secretary.

* * * * *

(v) Toll the time for action on requests for rehearing, and toll the time for action on 

protested self-certifications and self-recertifications of qualifying facilities.
Docket Nos. RM19-15-000 and AD16-16-000 - 440 -

Note: The following appendix will not appear in the Code of Federal Regulations or the 

Federal Register.

Appendix A

List of Commenters and Acronyms

Commenter Short Name/Acronym

Advanced Energy Economy Advanced Energy Economy

Alaska Power Association Alaska Power

Allco Finance Limited, Allco Renewable Energy 

Limited, Windham Solar LLC, Winding Creek Solar 

LLC

Allco

AllEarth Renewables, Inc. AllEarth

Alliant Energy Corporate Services, Inc. Alliant Energy

American Biogas Council Biogas

Americans for Limited Government – Richard 

Manning, President Mr. Manning

Americans for Tax Reform Tax Reform

American Public Power Association, Large Public 

Power Council APPA

Anthony O’Donnell – Montana Public Service 

Commissioner Commissioner O’Donnell

Ares EIF Management, LLC Ares

Arizona Corporation Commission Arizona Commission

Arizona Public Service Company Arizona Public Service

Basin Electric Power Cooperative Basin

Berkshire Hathaway Energy Company Berkshire Hathaway
Docket Nos. RM19-15-000 and AD16-16-000 - 441 -

Biomass Power Association Biomass Power

Bloom Energy Corporation Bloom Energy

BluEarth Renewables US LLC BluEarth

Borrego Solar Systems, Inc. Borrego Solar

Californians for Renewable Energy, Inc. CARE

California Public Utilities Commission California Commission

Center for Biological Diversity Biological Diversity

Center for Freedom and Prosperity Freedom Center

Center for Growth and Opportunity Growth and Opportunity 

Center

City of Boulder Colorado Boulder

Cogeneration Association of California CA Cogeneration

Colorado Independent Energy Association Colorado Independent 

Energy

Competitive Enterprise Institute Competitive Enterprise

Consolidated Edison Development, Inc. Con Edison

Connecticut Public Utilities Regulatory Authority Connecticut Authority

Conservative Action Project Conservative Action 

Consumer Energy Alliance Consumer Alliance

Consumers Energy Company Consumers Energy

Covanta Energy, LLC Covanta

David J. Bardin Mr. Bardin

Distributed Sun LLC Distributed Sun

Distributed Wind Energy Association Distributed Wind
Docket Nos. RM19-15-000 and AD16-16-000 - 442 -

District of Columbia Public Service Commission DC Commission

DTE Electric Company DTE Electric

Duke Energy Corporation Duke Energy

East Kentucky Power Cooperative, Inc. East Kentucky

East River Electric Power Cooperative, Inc. East River

Edison Electric Institute EEI

EIM Entities EIM Entities

El Paso Electric Company El Paso Electric

ELCON, American Chemistry Council, American 

Forest & Paper Association ELCON

Electric Power Supply Association EPSA

Energy Recovery Council Energy Recovery

Energy Storage Association Energy Storage

ENGIE North America Inc. ENGIE

Finadvice AG Finadvice

FirstEnergy Utilities FirstEnergy

Frontiers of Freedom Frontiers of Freedom

Golden Valley Electric Association, Inc. Golden Valley

Green Power Institute Green Power

GridLab GridLab

Harvard Electricity Law Initiative Harvard Electricity Law

Idaho Hydroelectric Power Producers Trust IdaHydro

Idaho Power Company Idaho Power

Idaho Public Utilities Commission Idaho Commission
Docket Nos. RM19-15-000 and AD16-16-000 - 443 -

Indiana Municipal Power Agency Indiana Municipal

Indiana Utility Regulatory Commission Indiana Commission

Industrial Energy Consumers of America Industrial Energy Consumers

Institute for Energy Research Institute for Energy Research

Institute for Liberty – Andrew Langer Institute for Liberty

J. Kenneth Blackwell Mr. Blackwell

Kentucky Public Service Commission Kentucky Commission

Louisville Gas and Electric Co. / Kentucky Utilities Co. LG&E-KU

Massachusetts Attorney General Maura Healey Massachusetts AG

Massachusetts Department of Public Utilities Massachusetts DPU

Michigan Public Service Commission Michigan Commission

Missouri River Energy Services Missouri River Energy

Montana Public Service Commission Montana Commission

Mr. and Mrs. Swecker Mr. and Mrs. Swecker

Rebecca Kelly Slaughter – Federal Trade Commissioner Commissioner Slaughter

National Association of Regulatory Utility 

Commissioners

NARUC

National Hydropower Association Hydropower Association

National Rural Electric Cooperative Association NRECA

Natural Resources Defense Council, and the Sustainable 

FERC Project 

NRDC

Nebraska Power Review Board Nebraska Board

New England Hydropower Company, LLC New England Hydro
Docket Nos. RM19-15-000 and AD16-16-000 - 444 -

New England Small Hydro Coalition (New England 

Small Hydro)

New England Small Hydro

NextEra Energy, Inc. (NextEra) NextEra

North American-Central, LLC North American-Central

North Carolina Department of Justice North Carolina DOJ

North Carolina Sustainable Energy Association NC Sustainable Energy)

North Carolina Utilities Commission Public Staff North Carolina Commission 

Staff

Northern Laramie Range Alliance Northern Laramie Range 

Alliance

Northwest and Intermountain Power Producers 

Coalition, Community Renewable Energy Association, 

Renewable Energy Coalition, Oregon Solar Energy 

Industries Association

NIPPC, CREA, REC, and 

OSEIA

NorthWestern Corporation NorthWestern

Ohio Consumers’ Counsel Ohio Consumers’ Counsel

One Energy Enterprises LLC One Energy

Oregon Public Utility Commission Oregon Commission

Pennsylvania Public Utility Commission Pennsylvania Commission

PJM Interconnection, L.L.C. PJM

Portland General Electric Company Portland General

Public Utilities Commission of Ohio’s Office of the 

Federal Energy Advocate 

Ohio Commission Energy 

Advocate

Progressive Policy Institute Progressive Policy Institute

R Street Institute R Street Institute

Resources for the Future Resources for the Future
Docket Nos. RM19-15-000 and AD16-16-000 - 445 -

SBE Council, Karen Kerrigan, President SBE Council

Sierra Club, EarthJustice, Vote Solar, Sustainable FERC 

Project, Natural Resources Defense Council, Pace 

Energy and Climate Center, Southern Environmental 

Law Center, Environmental Law & Policy Center, 

North Carolina Sustainable Energy Association, 

Montana Environmental Information Center

Public Interest Organizations

Solar Energy Industries Association Solar Energy Industries

Southern Company Services, Inc. Southern

South Carolina Solar Business Alliance SC Solar Alliance

South Dakota Public Utilities Commission South Dakota Commission

Southern California Edison Company, Pacific Gas & 

Electric Company, San Diego Gas & Electric Company

California Utilities

Southern Environmental Law Center, North Carolina 

Sustainable Energy Association, Alabama Interfaith 

Power & Light, Alabama Solar Industry Association, 

Inc., Appalachian Voices, Energy Alabama, Georgia 

Interfaith Power & Light, Georgia Solar Energy 

Association, Greater-Birmingham Alliance to Stop 

Pollution, North Carolina Chapter of the Sierra Club, 

North Carolina Interfaith Power & Light, North 

Carolina Justice Center, South Carolina Coastal 

Conservation League, South Carolina Interfaith Power 

& Light, Southern Alliance for Clean Energy, Southface 

Institute, Tennessee Interfaith Power & Light, Upstate 

Forever, and Vote Solar

Southeast Public Interest

Organizations

sPower Development Company, LLC sPower

State Entities State Entities

State of Idaho Idaho

Stephen Moore Mr. Moore

Steven Transeth Mr. Transeth
Docket Nos. RM19-15-000 and AD16-16-000 - 446 -

Subsurface Utility Engineering Association – John M, 

Palatiello

Subsurface Engineering 

Association

Taxpayers Protection Alliance Taxpayers Protection 

Alliance

Terna Energy USA Holding Corporation Terna Energy

Thomas Mattson Mr. Mattson

Transmission Access Policy Study Group TAPS

Two Dot Wind, LLC Two Dot Wind

Union of Concerned Scientists Union of Concerned 

Scientists

US Chamber of Commerce Chamber of Commerce

We Stand for Energy - Project of Edison Electric 

Institute

We Stand

Western Organization of Resource Councils Western Resource Councils

Xcel Energy Services Inc. Xcel*

*Out of Time comments were also filed by American Dams, Arizona Corporation 

Commission, Solar Energy Industries, and TerraForm Power Inc.
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Note: The following appendix will not appear in the Code of Federal Regulations or the 

Federal Register.

Appendix B

REVISED FORM NO. 556
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UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

 

Qualifying Facility Rates and Requirements 

Implementation Issues Under the Public Utility 

Regulatory Policies Act of 1978

Docket Nos. RM19-15-000

AD16-16-000

(Issued July 16, 2020)

GLICK, Commissioner, dissenting in part:

1. I dissent in part from today’s final rule (Final Rule1

) because it effectively guts the 

Commission’s implementation of the Public Utility Regulatory Policies Act (PURPA).2

 

The Commission’s basic responsibilities under PURPA are three-fold: (1) to encourage 

the development of qualifying facilities (QFs); (2) to prevent discrimination against QFs 

by incumbent utilities; and (3) to ensure that the resulting rates paid by electricity 

customers remain just and reasonable, in the public interest, and do not exceed the 

incremental costs to the utility of alternative energy.3

 I do not believe that today’s Final 

Rule satisfies those responsibilities. Instead, the Final Rule raises as many questions as it 

answers, not least of which is the long-term legal viability of an approach that does so 

little to encourage QF development. 

2. Although I have concerns about many of the individual changes imposed by the 

Final Rule,4 I remain, on a broader level, dismayed that the Commission is attempting to 

accomplish via administrative fiat what Congress has repeatedly declined to do via 

legislation. I am especially disappointed because Congress expressly provided the 

1 Qualifying Facility Rates and Requirements Implementation Issues Under the 

Public Utility Regulatory Policies Act of 1978, Order No. 872, 172 FERC ¶ 61,041 (2020) 

(Final Rule). 

2 Pub. L. No. 95-617, 92 Stat. 3117 (1978). 

3 See 16 U.S.C. § 824a-3(a)-(b) (2018).

4 Notwithstanding those concerns, I support certain aspects of this Final Rule. First 

and foremost, I agree with the update to the “one-mile” rule, which prior to today 

provided an irrebuttable presumption that resources located more than one mile apart are 

separate QFs. In addition, I support requiring that QFs demonstrate commercial viability 

before securing a legally enforceable obligation with the relevant utility. Finally, I also 

support the revision to allow stakeholders to protest a QF’s self-certification. 
Docket Nos. RM19-15-000 and AD16-16-000 - 2 -

Commission with a different avenue for “modernizing” our administration of PURPA. 

The Energy Policy Act of 2005 gave the Commission the authority to excuse utilities from 

their obligations under PURPA where QFs have non-discriminatory access to competitive 

wholesale markets.5

 Had we pursued reforms based on those provisions, rather than 

gutting our longstanding regulations, I believe we could have reached a durable, 

consensus solution that would ultimately have done more for all interested parties, even 

those that may celebrate the immediate effects of this Final Rule.

I. PURPA’s Continuing Relevance Is an Issue for Congress to Decide

3. This proceeding began with a bang. My colleagues championed the proposed rule 

as a “truly significant” action that would fundamentally overhaul the Commission’s 

implementation of PURPA.6

 And so it was. The NOPR proposed to alter almost every 

significant aspect of the Commission’s PURPA regulations, thereby transforming the 

foundation on which the Commission had carried out its statutory responsibility to 

“encourage” the development of QFs. 

4. I dissented from the NOPR in large part because I believe that it is not the 

Commission’s role to sit in judgment of a duly enacted statute and determine whether it 

has outlived its usefulness. As I explained, “almost from the moment PURPA was passed, 

Congress began to hear many of the arguments being used today to justify scaling the law 

back.”7

 Congress, however, has seen fit to significantly amend PURPA only once in its 

more-than-forty-year lifespan. As part of the Energy Policy Act of 2005, Congress 

amended PURPA, leaving in place the law’s basic framework, while adding a series of 

provisions that allowed the Commission to excuse utilities from its requirements in 

regions of the country with sufficiently competitive wholesale energy markets.8

 And 

while Congress considered numerous proposals to further reform the law, it never saw fit 

to act on them.9

 Against that background, I could not support my colleagues’ willingness 

to “remove[] an important debate from the halls of Congress and isolate[] it within the 

Commission.”10 Whatever your position on PURPA—and I recognize views vary 

5 Pub. L. No. 109-58, § 1253, 119 Stat. 594 (2005).

6 Sept. 2019 Commission Meeting Tr. at 8. 

7 Qualifying Facility Rates and Requirements Implementation Issues Under the 

Public Utility Regulatory Policies Act of 1978, Notice of Proposed Rulemaking, 168 

FERC ¶ 61,184 (2019) (NOPR) (Glick, Comm’r, dissenting in part at P 3).

8 Pub. L. No. 109-58, § 1253, 119 Stat. 594 (2005). 

9 See Solar Energy Industries Association (SEIA) Comments at 11. 

10 NOPR, 168 FERC ¶ 61,184 (Glick, Comm’r, dissenting in part at P 4).
Docket Nos. RM19-15-000 and AD16-16-000 - 3 -

widely—“what should concern all of us is that resolving these sorts of questions by 

regulatory edict rather than congressional legislation is neither a durable nor desirable 

approach for developing energy policy.”11 

5. Today’s Final Rule retreats from much of the original rationale used to support the 

NOPR, but the effect is the same: The Commission is administratively gutting PURPA. 

Make no mistake, although the Commission has dropped much of the NOPR preamble’s 

opening screed against PURPA’s continuing relevance, this Final Rule is a full-throated 

endorsement of the conclusion that PURPA has outlived its usefulness. And while 

walking back the argument that PURPA is antiquated may reduce the risk that this Final 

Rule is overturned on appeal, that does not change the fact that today’s Final Rule usurps 

what should be Congress’s proper role. 

6. Throughout this proceeding, the Commission has been quick to point to Congress’s 

directive to from time to time amend our regulations implementing PURPA.12 This Final 

Rule, however, is a wholesale overhaul of the Commission’s PURPA regulations that 

reflects a deep skepticism of the need for the law we are charged with implementing. I 

doubt that is what Congress had in mind when it gave us responsibility for periodically 

updating our implementing regulations. 

II. The Commission’s Proposed Reforms Are Inconsistent with Our Statutory 

Mandate

7. PURPA directs the Commission to adopt such regulations as are “necessary to 

encourage” QFs,13 including by establishing rates for sales by QFs that are just and 

reasonable and by ensuring that such rates “shall not discriminate” against QFs.14 As 

explained below, many of the changes adopted by the Commission in the Final Rule fail to 

meet that standard. In addition, many of the reforms are unsupported—or, in many cases, 

contradicted—by the evidence in the record.15 Accordingly, I believe today’s Final Rule 

is not just poor public policy, but also arbitrary and capricious agency action. 

11 Id.

12 Final Rule, 172 FERC ¶ 61,041 at PP 24, 48, 54, 67, 296, 628; NOPR, 168 

FERC ¶ 61,184 at PP 4, 16, 29, 155. 

13 A QF is a cogeneration facility or a small power production facility. See 18 

C.F.R. § 292.101(b)(1) (2019).

14 16 U.S.C. § 824a–3(a)-(b). 

15 Genuine Parts Co. v. EPA, 890 F.3d 304, 312 (D.C. Cir. 2018) (“[A]n agency 

cannot ignore evidence that undercuts its judgment; and it may not minimize such 

evidence without adequate explanation.”) (citations omitted); id. (“Conclusory 
Docket Nos. RM19-15-000 and AD16-16-000 - 4 -

A. Avoided Cost

8. The Final Rule adopts two fundamental changes to how QF rates are determined. 

First, and most importantly, it eliminates the requirement that a utility must afford a QF 

the option to enter a contract at a rate for energy that is either fixed for the duration of the 

contract or determined at the outset—e.g., based on a forward curve reflecting estimated 

prices over the term of the contract.16 Second, it presumptively allows states to set the 

rate for as-available energy at the relevant locational marginal price (LMP) or a similarly 

“competitive market price.”17 The record in this proceeding does not support either of 

those changes.

i. Elimination of Fixed Energy Rate

9. Prior to today’s Final Rule, a QF generally had two options for selling its output to 

a utility. Under the first option, the QF could sell its energy on an as-available basis and 

receive an avoided cost rate calculated at the time of delivery. This is generally known as 

the as-available option. Under the second option, a QF could enter into a fixed-duration 

contract at an avoided cost rate that was fixed either at the time the QF established a 

legally enforceable obligation (LEO) or at the time of delivery. This is generally known 

as the contract option. The ability to choose between both types of sale options played an 

important role in fostering the development of a variety of QFs. For example, the asavailable option provided a way for QFs whose principal business was not generating 

electricity, such as industrial cogeneration facilities, to monetize their excess electricity 

generation. The contract option, by contrast, provided QFs who were principally in the 

business of generating electricity, such as small renewable electricity generators, a stable 

option that would allow them to secure financing. Together, the presence of these two 

options allowed the Commission to satisfy its statutory mandate to encourage the 

development of QFs and ensured that the rates they received were non-discriminatory. 

10. The Final Rule eliminates the requirement that states provide a contract option that 

includes a fixed energy rate.

18 Prior to this proceeding, the Commission recognized time 

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)).

16 Final Rule, 172 FERC ¶ 61,041 at P 253.

17 Id. PP 151, 189, 211.

18 Id. P 253.
Docket Nos. RM19-15-000 and AD16-16-000 - 5 -

and again that fixed-price contracts play an essential role in the financing of QF facilities, 

making them a necessary element of any effort to encourage QF development, at least in 

certain regions of the country.19 In addition, fixed-price contracts have helped prevent 

discrimination against QFs by ensuring that they are not structurally disadvantaged 

relative to vertically integrated utilities that are guaranteed to recover the costs of their 

prudently incurred investments through retail rates.20 

19 See, e.g., Small Power Production and Cogeneration Facilities; Regulations

Implementing Section 210 of the Public Utility Regulatory Policies Act of 1978, Order

No. 69, FERC Stats. & Regs. ¶ 30,128, at 30,880, order on reh’g sub nom. Order

No. 69-A, FERC Stats. & Regs. ¶ 30,160 (1980), aff’d in part vacated in part, Am. Elec.

Power Serv. Corp. v. FERC, 675 F.2d 1226 (D.C. Cir. 1982), rev’d in part sub nom. Am.

Paper Inst. v. Am. Elec. Power Serv. Corp., 461 U.S. 402 (1983). (justifying the rule on 

the basis of “the need for certainty with regard to return on investment in new 

technologies”); NOPR, 168 FERC ¶ 61,184 at P 63 (“The Commission’s justification for 

allowing QFs to fix their rate at the time of the LEO for the entire term of a contract was 

that fixing the rate provides certainty necessary for the QF to obtain financing.”); 

Windham Solar LLC, 157 FERC ¶ 61,134, at P 8 (2016).

1. 20 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]savailable 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);
Docket Nos. RM19-15-000 and AD16-16-000 - 6 -

11. If anything, the record before us confirms the continuing importance of fixed-price 

contracts. Numerous entities with experience financing and developing QFs explain that a 

fixed revenue stream of some sort is necessary to obtain the financing needed to develop a 

new QF.21 The fixed revenue stream is particularly important because QFs are 

overwhelmingly developed outside of the organized markets, meaning that developers 

cannot necessarily obtain hedging contracts to create the revenue predictability needed to 

obtain financing.22 And that is why the Final Rule’s parade of statistics about the growth 

of renewables misses the point.23 It is true that, primarily in organized markets, 

independently developed renewables are able to develop without the entitlement to a 

fixed-price contract for energy from the relevant utility.24 But the growth of renewables 

sPower Comments at 13; see also Statement of Travis Kavulla, Docket No. AD16-16-000, 

at 2 (June 29, 2016).

21 See, e.g., SEIA Comments at 29; North Carolina Attorney General’s Office 

Comments at 5; Con Ed Development Comments at 3; South Carolina Solar Business 

Association Comments at 6; sPower Comments at 11; Resources for the Future Comments 

at 6-7. 

22 See, e.g., SEIA Comments at 29-30 (“As both Mr. Shem and Mr. McConnell 

explain, financial hedge products are not available outside of ISO/RTO markets.”); 

Resources for the Future Comments at 6-7 (“[W]hile hedge products do support wind and 

solar project financing, they would not be suited for most QF projects. To hedge energy 

prices, wind projects have used three products: bank hedges, synthetic power purchase 

agreements (synthetic PPAs), and proxy revenue swaps. . . . From 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.”) (emphasis 

added).

23 Harvard Electricity Law Comments at 22 (referring to a similar statistical parade 

in the NOPR and observing that “[a]ll [the Commission] can actually conclude from this 

loosely connected array of facts, data, and speculation is that some non-QF generators are 

developed with variable-rate energy contracts. That unremarkable conclusion has no 

bearing on whether repeal will discourage QF development by ‘materially affect[ing] the 

ability of QFs to obtain financing.’” (citing NOPR, 168 FERC ¶ 61,184 at P 69)); SEIA 

Comments at 30.

24 See Final Rule, 172 FERC ¶ 61,041 at P 340 (“EIA data demonstrates that net 

generation of energy by non-utility owned renewable resources in the United States grew 

by almost 700% between 2005 and 2018.”). Although independent power producers, 

renewable or otherwise, within the RTO/ISO markets are not entitled to fixed price 
Docket Nos. RM19-15-000 and AD16-16-000 - 7 -

and their financeability in organized markets tells us almost nothing about what is 

required to sufficiently encourage QFs outside those markets.25

12. It would be one thing to eliminate the requirement to provide a fixed-price option 

for energy rates for QFs that are entitled to a fixed price for capacity. Although 

reasonable minds might disagree about whether a fixed price for capacity alone is 

sufficient encouragement, combining one with a variable price for energy would provide 

at least some guaranteed revenue stream with which to finance new development.26 

Indeed, much of the Commission’s justification for eliminating the fixed-price contract 

option for energy rests on the availability of a fixed-price contract option for capacity.27 

Commission precedent, however, permits utilities to offer a capacity rate of zero to QFs 

contracts for energy as a matter of law, they generally do rely on alternative tools, such as 

commodity hedges, to lock-in energy revenue streams. See, e.g., EEI Comments at 36; 

sPower Comments at 12.

25 In the logical leap of the year, the Commission notes that in some areas of the 

country, unspecified resources are developed with a fixed-price contract for capacity and a 

variable price for energy and, separately, that renewables have grown nationwide more 

than seven-fold between 2005 and 2018. Final Rule, 172 FERC ¶ 61,041 at P 340. From 

those disparate observations, the Commission concludes that “renewable resources are 

able to acquire financing even without the right to require long-term fixed energy rates.” 

Id. But nothing in the record suggests that that phenomenal growth in renewables was at 

all the result of that bifurcated contract structure. That, it should be clear, is not reasoned 

decisionmaking. Cf. Nat’l Ass’n of Recycling Indus., Inc. v. Fed. Mar. Comm’n, 658 F.2d 

816, 820 n.10 (D.C. Cir. 1980) (“We do not want, after all, blithely to compare apples and 

oranges. Likewise, an agency should also avoid unavailing comparisons of 

nonsubstitutes.”); see also Commissioner Slaughter Comments at 4 (noting the 

“widespread geographic differentiation” in renewable energy progress and “barriers to 

independent renewable energy-based power producers”).

26 See, e.g., SEIA Comments at 29 (“While securing financing based on an AsAvailable Energy rate and a fixed capacity rate may be a rare possibility in a few submarkets across the country, as Mr. Shem explains, it certainly is not the case in any state 

that does not participate in an ISO/RTO market.”).

27 See Final Rule, 172 FERC ¶ 61,041 at P 36 (“This assertion that the Commission 

has eliminated fixed rates for QFs is not correct. . . . The NOPR thus made clear: under 

the proposed revisions to § 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.”).
Docket Nos. RM19-15-000 and AD16-16-000 - 8 -

when the utility does not need incremental capacity.

28 That means that, as a result of this 

Final Rule, QF developers will face the very real prospect of not receiving any fixed 

revenue stream, whether for energy or capacity, in areas where they also cannot secure 

hedging products or other mechanisms needed to finance a new QF.29 It is hard for me to 

understand how the Commission can, with a straight face, claim to be encouraging QF 

development while at the same time eliminating the conditions necessary to develop QFs 

in the regions where they are being built.30 

13. The Commission sidesteps this point in responding that PURPA does not require 

that QFs be financeable. That is true in a literal sense; nothing in PURPA directs the 

Commission to ensure that at least some QFs be financeable. But it does require the 

Commission to encourage their development, which we have previously equated with 

financeability.31 If the Commission is going to abandon that standard, it must then explain 

why what is left of its regulations provides the requisite encouragement—an explanation 

that is lacking from this Final Rule, notwithstanding the Commission’s repeated assertions 

to the contrary. 

14. The Commission also does not sufficiently explain how eliminating the fixed-price 

contract requirement is consistent with PURPA’s requirement that rates “shall not 

discriminate against” QFs.32 Vertically integrated utilities effectively receive guaranteed 

28 See, e.g., id. P 422 (citing to City of Ketchikan, Alaska, 94 FERC ¶ 61,293, at 

62,061 (2001)).

29 See, e.g., Resources for the Future Comments at 6; SEIA Comments at 30; 

Southeast Public Interest Organizations Comments at 12.

30 See Public Interest Organizations Comments at 10-11 (“Obviously, rules that 

have an effect of discouraging QFs cannot be ‘necessary to’ encouraging them.”); see also

Massachusetts Attorney General Maura Healey Comments at 6 (“This action may reduce 

investor confidence and discourage future development. That outcome is a negative one 

for the Commonwealth and its ratepayers.”).

31 See, e.g., Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,880 (justifying the 

rule on the basis of “the need for certainty with regard to return on investment in new 

technologies”); NOPR, 168 FERC ¶ 61,184 at P 63 (“The Commission’s justification for 

allowing QFs to fix their rate at the time of the LEO for the entire term of a contract was 

that fixing the rate provides certainty necessary for the QF to obtain financing.”).

32 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 

ELCON Comments at 21-22; South Carolina Solar Business Alliance Comments at 7-8; 

sPower Comments at 13.
Docket Nos. RM19-15-000 and AD16-16-000 - 9 -

fixed-price contracts through their rights to recover prudently incurred investments. The 

equivalent right to receive fixed-price contracts has to date proved an integral element of 

the Commission’s ability to satisfy PURPA’s prohibition on discriminatory rates.33

15. And yet this Final Rule fails to explain how eliminating the fixed-price option is 

consistent with that prohibition or, moreover, how permitting QFs to receive variable 

contract rates while vertically integrated utilities receive fixed ones is consistent with the 

Commission’s obligation to promote QFs.34 Instead, the Commission notes that, through 

so-called fuel adjustment clauses, vertically integrated utilities’ rates change as the price 

of fuel changes.35 The idea that those clauses, which ensure that utilities recover a 

specific variable cost (i.e., their cost of fuel), is the same thing as having your entire 

revenue exposed to variations in prevailing market conditions is hogwash. The presence 

of fuel adjustment clauses in no way suggests that vertically integrated utilities are subject 

to anything remotely close to the level of revenue variation contemplated in this Final 

Rule. 

16. Finally, the Commission fails to explain why allegations of QF rates exceeding a 

utility’s actual avoided cost requires us to abandon the Commission’s long-held principles 

regarding certainty and financing.36 As an initial matter, the Commission has recognized 

that QF rates may exceed actual avoided costs, but, at the same time, recognized that 

avoided cost rates might also turn out to be lower than the electric utility’s avoided costs 

over the course of the contract. The Commission has reasoned that, “in the long run, 

‘overestimations’ and ‘underestimations’ of avoided costs will balance out.”37 However, 

when presented with a couple allegations that avoided costs were overestimated,38 the 

Commission now concludes that that possibility suggests it must abandon the fixed-energy 

rate contract altogether. The Commission, however, makes no effort to validate these 

33 See supra n.20; Commissioner Slaughter Comments at 4.

34 Public Interest Organizations Comments at 51 (“[L]imiting QFs to contracts 

providing no price certainty for energy values, while non-QF generation regularly obtains 

fixed price contracts and utility-owned generation receives guaranteed cost recovery from 

captive ratepayers, constitutes discrimination.”).

2. 35 Final Rule, 172 FERC ¶ 61,041 at P 122.

3.

36 See supra n.19.

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

38 Final Rule, 172 FERC ¶ 61,041 at PP 265, 268.
Docket Nos. RM19-15-000 and AD16-16-000 - 10 -

allegations,39 or assess whether the overestimations of avoided cost were, in fact, balanced 

out.40 It is arbitrary and capricious to point to only half the picture in abandoning a fortyyear-old principle.

ii. Rebuttable Presumption for Setting Avoided Cost at LMP and 

Similar Measures

17. I also do not support the Commission’s decision to treat LMP or other “competitive 

market prices” as a presumptively reasonable measure of an as-available avoided cost for 

energy.41 Liquid price signals can be useful and transparent inputs and ought to be 

considered in calculating an appropriate avoided-cost figure. But considering those price 

signals in setting avoided cost is not the same thing as presuming that LMP or similar 

measures are alone sufficient to establish avoided cost. Many regions of the country—

often the same regions where the debates about PURPA are most heated—have not 

established sufficiently competitive markets. In these regions it is not clear from the 

record that the prices in, for example, a neighboring RTO, are a representative measure of 

a utility’s avoided cost. In those less competitive markets, it simply does not make sense 

to presume that LMP or other “competitive market prices” are a representative measure of 

avoided cost, rather than one of many criteria that should go into that determination.42

18. For similar reasons, I share the concern of many commenters that short-term or 

spot prices, such as LMP, may not reflect the long-term marginal energy costs avoided by 

39 Id. PP 291, 293.

40 The Commission is quick to point to “the precipitous decline in natural gas 

prices” starting in 2008 that may have caused QF contracts fixed prior to that period to 

underestimate the actual cost of energy. See, e.g., Final Rule, 172 FERC ¶ 61,041 at P 

287). However, PURPA has been in place for forty years, and the Commission does not 

wrestle with the magnitude of potential savings conveyed to consumers from the fixedprice energy contracts that locked-in low rates for consumers during the decades prior 

when natural gas prices were several times higher. See Energy Information 

Administration Total Energy, tbl. 9.10 (last viewed July 15, 2020), 

https://www.eia.gov/totalenergy/data/browser/. 

41 Final Rule, 172 FERC ¶ 61,041 at PP 151, 189, 211.

42 Congress itself seems to have contemplated that states would not rely solely on 

spot market prices when establishing avoided cost. H.R. Rep. No. 95-1750, at 7833

(1978) (“In interpreting the term ‘incremental cost of alternative energy,’ the conferees 

expect that the Commission and the states may look beyond the cost of alternative sources 

which are instantaneously available to the utility.”). 
Docket Nos. RM19-15-000 and AD16-16-000 - 11 -

purchasing utilities, especially outside of organized markets.43 Although the Commission 

revises the NOPR’s per se rule to be a rebuttable presumption, it nevertheless plows ahead 

with the conclusion that LMP, and similar measures, reflect a utility’s avoided cost of 

energy. Where there is good reason to believe that those measures do not actually reflect 

the long-term value of energy that they are supposed to represent, it makes no sense to put 

the burden on QFs to prove the point,44 rather than leaving the burden with the proponents 

of using such measures. 

19. The Commission’s presumptive approval of LMP and similar measures is even 

more problematic when combined with the decision to allow utilities to eliminate the 

fixed-price contract option. Following this Final Rule, QFs may be reduced to relying 

solely on some synthetic and highly variable measure of what spot prices should be in a 

competitive market based on gas prices and heat rates, all while the utilities whose costs 

the QF is avoiding recovers an effectively guaranteed rate potentially in excess of this 

representative “competitive market price.” I am not persuaded that this approach will 

satisfy our obligation to encourage QFs and to do so using rates that are nondiscriminatory across all regions of the country.

B. Rebuttable Presumption 20 MW to 5 MW

20. Following the Energy Policy Act of 2005, the Commission established a rebuttable 

presumption that QFs with a capacity greater than 20 MW operating in RTOs and ISOs 

have non-discriminatory access to competitive markets, eliminating utilities’ must43 Final Rule, 172 FERC ¶ 61,041 at n.163; Hydro Comments at 11; Southeast 

Public Interest Organizations Comments at 19; NIPPC, CREA, REC, and OSEIA 

Comments at 52, 55; Union of Concerned Scientists Comments at 6. Take, for example, 

the Commission’s approval of the Mid-Columbia market hub price as presumptively 

reflecting a utility’s avoided cost for energy. See Final Rule, 172 FERC ¶ 61,041 at

PP 180, 189. Notwithstanding explicit support for this approach from the regulated utility 

industry, the Washington Utilities and Transportation Commission which, when 

addressing Puget Sound Energy’s plan to increase wholesale purchases from the MidColumbia market “liquid hub” to 1,600 MW, expressed a concern about the regulated 

utility’s overreliance on such wholesale market pricing and directed them to pursue an 

alternative plan to eliminate this “excessive risk.” That is the exact type of tension 

conveyed in the record—i.e, that such competitive market prices may not accurately 

reflect a utility’s avoided cost, as approved by regulators. See Washington UTC, 

Acknowledgment Letter Attachment, Puget Sound Energy’s 2017 Electric and Natural 

Gas Integrated Resource Plan, Wash. UTC Docket Nos. UE-160918, UG-160919 

(Revised June 19, 2018); see NIPPC, CREA, REC, and OSEIA Comments at 56.

44 Final Rule, 172 FERC ¶ 61,041 at P 152.
Docket Nos. RM19-15-000 and AD16-16-000 - 12 -

purchase obligation from those resources.45 The Final Rule reduces the threshold for that 

presumption from 20 MW to 5 MW. 46 That is an improvement over the NOPR, which—

without any support whatsoever—proposed to lower that threshold to 1 MW.47 But, even 

so, the reduced 5 MW threshold is unsupported by the record and inadequately justified in 

today’s Final Rule. 

21. When it originally established the 20 MW threshold, the Commission pointed to an 

array of barriers that prevented resources below that level from having truly nondiscriminatory access to RTO/ISO markets. Those barriers included complications 

associated with accessing the transmission system through the distribution system (a 

common occurrence for such small resources), challenges with reaching distant off-takers, 

as well as “jurisdictional differences, pancaked delivery rates, and additional 

administrative procedures” that complicate those resources’ ability to participate in those 

markets on a level playing field.48 In just the last few years, the Commission has 

recognized the persistence of those barriers “that gave rise to the rebuttable presumption 

that smaller QFs lack nondiscriminatory access to markets.”49

22. Nevertheless, the Final Rule abandons the 20 MW threshold based on the 

conclusory assertion that “it is reasonable to presume that access to RTO/ISO markets has 

improved” and it is, therefore, “appropriate to update the presumption.”50 No doubt 

markets have improved. But a borderline-truism about maturing markets does not explain 

how the barriers arrayed against small resources have dissipated, why it is reasonable to 

“presume” that the remaining barriers do not inhibit non-discriminatory access, or why 5 

MW is an appropriate new threshold for that presumption. 

45 New PURPA Section 210(m) Regulations Applicable to Small Power Production 

and Cogeneration Facilities, Order No. 688, 117 FERC ¶ 61,078, at P 72 (2006), order on 

reh’g, Order No. 688-A, 119 FERC ¶ 61,305 (2007), aff’d sub nom. Am. Forest & Paper 

Ass’n v. FERC, 550 F.3d 1179 (D.C. Cir. 2008); see 16 U.S.C. § 824a-3(m).

46 Final Rule, 172 FERC ¶ 61,041 at P 625.

47 NOPR, 168 FERC ¶ 61,184 at P 126.

48 Order No. 688-A, 119 FERC ¶ 61,305 at PP 96, 103.

49 E.g., N. States Power Co., 151 FERC ¶ 61,110, at P 34 (2015). 

50 Final Rule, 172 FERC ¶ 61,041 at P 629 (“Over the last 15 years, the RTO/ISO 

markets have matured, market participants have gained a better understanding of the 

mechanics of such markets and, as a result, we find that it is reasonable to presume that 

access to the RTO/ISO markets has improved and that it is appropriate to update the 

presumption for smaller production facilities.”).
Docket Nos. RM19-15-000 and AD16-16-000 - 13 -

23. Instead of any such evidence, the Final Rule notes that the Commission uses the 5 

MW as a demarcating line for other rules applying to small resources. Specifically, it 

points to the fact that resources below 5 MW can use a “fast-track” interconnection 

process, whereas larger ones must use the large generator interconnection procedures.51 

But the fact that the Commission used 5 MW as the cut off in another context hardly 

shows that it is the right cut off to use in this context. 

24. Lacking substantial evidence to support the 5 MW threshold, the Commission falls 

back on a deferential standard of review.52 But while judicial review of agency 

policymaking is deferential, it is not toothless. The same cases on which the Commission 

relies require that, when an agency’s policy reversal “rests upon factual findings that 

contradict those which underlay its prior policy,” the agency must “provide a more 

detailed justification than what would suffice for a new policy created on a blank slate.”53 

That is because reasoned decisionmaking requires that, when an agency changes course, it 

must provide “a reasoned explanation . . . for disregarding facts and circumstances that 

underlay or were engendered by the prior policy.”54 For the foregoing reasons, the 

Commission has failed to produce any such explanation, making its change of course 

arbitrary and capricious. 

III. Environmental Review under the National Environmental Policy Act

25. In contrast to the Commission’s crowing over the significance of its PURPA 

overhaul, the Final Rule describes the changes adopted as merely corrective and clarifying 

in nature when it comes to conducting an environmental review.55 In particular, the 

Commission contends that “the changes adopted in this final rule are required to ensure 

continued future compliance of the PURPA Regulations with PURPA, based on the 

51 Id. P 630.

52 Id. P 637 (citing FCC v. Fox Television, 556 U.S. 502, 515 (2009), for the 

proposition that an agency “need not demonstrate to a court’s satisfaction that the reasons 

for the new policy are better than the reasons for the old one; it suffices that the new 

policy is permissible under the statute, that there are good reasons for it, and that the 

agency believes it to be better, which the conscious change of course adequately 

indicates.”).

53 Fox Television, 556 U.S. at 515; Advanced Energy Economy Comments at 6.

54 Fox Television, 556 U.S. at 516; Advanced Energy Economy Comments at 6-7.

55 Under the National Environmental Policy Act (NEPA), the Commission must 

consider whether its action associated with rulemakings will have a significant impact on 

the environment. See 42 U.S.C. §§ 4321 et seq.
Docket Nos. RM19-15-000 and AD16-16-000 - 14 -

changed circumstances found by the Commission in this final rule.”56 In other words, 

because the Commission believes that the changes adopted are necessary to conform with 

the statute, they are mere corrective changes, which, in turn, qualifies them for the 

categorical exemption from any environmental review under NEPA, or so the argument 

goes. 

26. But by that logic, any Commission action needed to comply with our various 

statutory mandates—whether “just and reasonable” or the “public interest”—would be 

deemed corrective in nature and, therefore, excluded from environmental review. The 

Commission, however, fails to point to any evidence suggesting that is what the Council 

on Environmental Quality contemplated when it allowed for categorical exemptions.

IV. The Way to Revise PURPA Is to Create More Competition, Not Less

27. It didn’t have to be this way. When Congress reformed PURPA in the 2005 

Energy Policy Act amendments, it indicated an unmistakable preference for using market 

competition as the off-ramp for utilities seeking relief from their PURPA obligations.57 

Those reforms directed the Commission to excuse utilities from those obligations where 

QFs had non-discriminatory access to RTO/ISO markets or other sufficiently competitive 

constructs.58 

28. This record contains numerous comments explaining how the Commission could 

use those amendments as a way to “modernize” PURPA in a manner that both promotes 

actual competition and reflects Congress’s unambiguous intent.59 For example, in a white 

paper released prior to the NOPR, the National Association of Regulatory Utility 

Commissioners (NARUC) urged the Commission to give meaning to the 2005 

amendments by establishing criteria by which a vertically integrated utility outside of an 

RTO or ISO could apply to terminate the must-purchase obligation if it conducts 

sufficiently competitive solicitations for energy and capacity.60 Other groups, including 

56 Final Rule, 172 FERC ¶ 61,041 at P 722.

57 16 U.S.C. § 824a-3(m).

58 See Order No. 688, 117 FERC ¶ 61,078 at P 8.

59 See Advanced Energy Economy Comments at 13; Industrial Energy Consumers 

Comments at 13-14; EPSA Comments at 16.

60 National Association of Regulatory Utility Commissioners Supplemental 

Comments, Docket No. AD16-16-00, Attach. A, at 8 (Oct. 17, 2018); id. (proposing the 

Commission’s Edgar-Allegheny criteria as a basis for evaluating whether a proposal was 

adequately competitive).
Docket Nos. RM19-15-000 and AD16-16-000 - 15 -

representatives of QF interests, submitted additional comments on how an approach along 

those lines might work.61 Several parties commented on those proposals.62 

29. It is a shame that the Commission has elected to administratively gut its longstanding PURPA implementation regime, rather than pursuing reform rooted in PURPA 

section 210(m), such as the NARUC proposal. Pursuing an option along those lines could 

have produced a durable, consensus solution to the issues before us. I continue to believe 

that the way to modernize PURPA is to promote real competition, not to gut the 

provisions that the Commission has relied on for decades out of frustration that Congress 

has repeatedly failed to repeal the statute itself.

For these reasons, I respectfully dissent in part.

________________

Richard Glick

Commissioner

61 See, e.g., SEIA Supplemental Comments, Docket No. AD16-16-000 (Aug. 28, 

2019).

62 See, e.g., Advanced Energy Economy Comments at 12; APPA Comments at 29; 

Colorado Independent Energy Comments at 7; ELCON Comments at 19; Public Interest 

Organizations Comments at 90; SEIA Comments at 24; Xcel Comments at 11.