September 26, 2019 | 6 minute read

On September 19, 2019, the Federal Energy Regulatory Commission (“FERC” or “Commission”) issued a Notice of Proposed Rulemaking (“NOPR”)[1] proposing significant changes to FERC’s regulations governing qualifying facilities (“QFs”)[2] pursuant to the Public Utility Regulatory Policies Act of 1978, as amended (“PURPA”).[3]  If implemented as proposed, the changes would significantly scale back some of the benefits afforded to many QFs, particularly small QFs.  FERC considers the proposed changes appropriate due to changed circumstances since Congress enacted PURPA in 1978, including “sweeping changes” to the natural gas industry resulting in increased supply, renewable energy resource development, and developments in the competitive wholesale electricity market.  Among other things, FERC proposes to revise its regulations to:

  • Permit states to implement energy rates in QF power sales contracts or other legally enforceable obligations (“LEOs”) that vary, potentially eliminating the ability of a QF to fix its energy rate for the term of the power sales contract or LEO with the purchasing utility.[4]

    • Grant states the authority to set “as-available” QF energy rates at either:(1) locational marginal price (“LMP”) for QFs selling into organized electric markets; or (2) competitive prices from liquid market hubs or calculated from a formula based on natural gas price indices and specified heat rates for QFs selling energy to utilities outside of organized electric markets.[5]

  • Permit states to allow fixed energy rates in QF power sale contracts based on projected energy prices for the anticipated delivery dates of the QF’s contract.[6]

  • Reduce a utility’s obligation to purchase power from QFs (often referred to as the “PURPA put” obligation) if the utility’s supply obligation has been reduced by a state retail choice program.[7]

  • Modify the current “one-mile rule” for determining whether generation facilities should be considered to be part of a single facility for purposes of qualifying as a small power production facility by:(1) allowing utilities, state regulatory authorities, and other interested parties to show that facilities between 1 and 10 miles apart are a single facility; and (2) allowing entities seeking QF status to preemptively defend against challenges that may allege other affiliated generation resources located within 10 miles of the generation facility are indeed separate facilities at a separate site.[8]

  • Provide an opportunity for a utility to be relieved from its obligation to purchase from a QF located in organized energy markets for QFs with a net capacity in excess of 1 MW (current regulations provide that a QF with 20 MW or less of net capacity is entitled to a rebuttable presumption that it does not have nondiscriminatory access to certain markets).[9]

  • Require QFs to demonstrate commercial viability and financial commitment to construct their facility before the QF is entitled to a contract or LEO.[10]

  • Allow an interested party to challenge a self-certification or self-recertification of a facility without having to file a separate petition for declaratory order and pay the associated filing fee.[11]

Certain key reforms proposed in the NOPR are discussed in further detail below:

Proposed Expansion of PURPA Purchase Relief

Currently, utilities may seek relief from the mandatory PURPA purchase obligation if FERC finds that QFs interconnected to the utility have nondiscriminatory access to the wholesale electricity markets.[12]  FERC applies a rebuttable presumption in considering a utility’s request for PURPA purchase relief that a QF at or below 20 MW of net power production capacity lacks nondiscriminatory access to certain markets.  For the most part, FERC had not extended relief from the PURPA purchase obligation for QFs 20 MW or smaller.  The NOPR seeks to modify that threshold to over 1 MW for small power production facilities in organized markets (i.e., there would be a rebuttable presumption that QFs larger than 1 MW are able to access the market directly).[13]   FERC cited to the maturity of organized electric markets as support for this proposed reduction.[14]  A QF in excess of 1 MW would have the opportunity to rebut the presumption of nondiscriminatory access “due to operational characteristics or transmission constraints.”[15] 

The NOPR also proposes utilities in states with retail choice programs could reduce their  PURPA purchase obligations if those utilities’ supply obligations have been reduced as part of the retail choice regulatory scheme. 

QF Rates

The NOPR proposes to change requirements for state avoided cost determinations such that a QF may now have a variable rather than a fixed revenue stream for its energy sales.   The proposed alternative methods to calculate avoided cost for energy sales would not be mandatory and are intended to give states additional flexibility in setting QF rates.[16]  State regulatory authorities could choose to continue to set long-term fixed energy rates as they do today subject to certain conditions set forth in the NOPR.[17]  Also, FERC is not proposing any revisions to avoided capacity costs in the current PURPA regulations,  “a QF would continue to be entitled to a contract with avoided capacity costs . . . .”[18] 

FERC’s current PURPA regulations provide QFs with two options for selling their output to a utility:  (1) a QF may sell as much of its energy as it chooses when it becomes available in accordance with the rate calculated at the time of delivery; (2) a QF may sell its output pursuant to contract over a specified term at either (a) a fixed rate based on the utility’s avoided cost at the LEO is incurred, or (b) the utility’s avoided cost calculated at the time of delivery.  State regulatory proceedings to determine avoided cost rates are typically heavily litigated. 

The proposed reforms provides states with the option of implementing avoided cost energy rates based on market prices, based on LMP, for utilities in an  RTO or ISO.[19]  Interestingly, FERC also asked for comments on whether the California Independent System Operator Corp. administered Energy Imbalance Market are similar for these purposes to the LMP in RTOs/ISOs.  Some states already rely on LMP for avoided cost pricing, for example, some New England states rely on the ISO New England Inc. LMP.  FERC recognized that states already concluded that LMP was an appropriate measure of the energy component of avoided costs.  However, the NOPR proposal would allow a state to adopt LMP as a “per se appropriate measure of the as-available energy component of avoided costs.” 

For utilities outside RTO or ISO markets, the NOPR proposes to allow state regulatory authorities to set variable QF rates at a “competitive price.”  The NOPR proposes that  “Competitive Prices” could mean “(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.”[20]  As examples of liquid market hubs, FERC referenced the Mid-Columbia hub in the Pacific Northwest and Palo Verde hub in the Southwest.  As to reliance on natural gas indices coupled with the heat rate of an efficient natural gas combined-cycle generating facility, FERC proposed this may be a reasonably accurate measure of avoided cost in markets where natural gas is the marginal fuel.  Additionally, FERC is proposing to allow states the ability to set energy and capacity rates through a competitive solicitation process such as an RFP.[21]

FERC anticipates that providing states with the ability to implement variable avoided cost determinations will not create an obstacle to financing.  FERC pointed to non-QFs that have negotiated contractual arrangements for financing.  FERC also referenced state concerns that long contract terms at fixed rates could lead to payments above avoided costs and noted the resulting shorter QF contract terms.  Idaho, for example, limited QF contracts to two-year terms.  FERC reasoned that these shorter QF contracts made financing difficult and that the longer contracts that could result when variable pricing is used could actually improve the ability of developers to finance QF projects.  FERC sees financial hedges as a contractual approach for QF developers to guarantee a steady fixed price revenue stream even when the PURPA contract included variable pricing.  FERC also noted that QFs receive benefits outside of their PURPA contracts, including federal and state incentives designed to encourage the construction of renewable resources.  

Separate Facilities

Currently, there is an irrebuttable presumption that affiliated small power production facilities using the same energy resource that are more than 1 mile apart from each other are located at separate sites.  As separate sites, the projects are designated as separate facilities for QF purposes.  Designation as separate facilities can make the difference for satisfying the cap on the capacity of small power production facilities of 80 MW.[22]  FERC is proposing to change the irrebutable presumption for facilities located more than 1 mile but less than 10 miles apart as being separate facilities to a rebuttable presumption.[23]  Facilities located 10 miles or more apart would continue to have an irrebuttable presumption that these facilities are separate pursuant to the NOPR.

Commercial Viability and Financial Commitment Requirements

Currently, a QF owner may choose to have its rates calculated either at the time of delivery or at the time a LEO is incurred.[24]  To date, the Commission has not established specific criteria for state regulatory authorities to determine when a LEO is created.  However, the Commission has found some state prerequisites to LEO formation to be unreasonable, e.g., the interconnection agreement or power purchase agreement must be signed by the utility before a LEO is established.[25]  To aide states in determining what criteria may be objective and reasonable in determining the QF has met the commercial viability and financial commitment requirements, the NOPR sets forth three, non-exhaustive criteria that states may employ:  (1) obtaining site control adequate to commence construction of the project at the proposed location; (2) filing an interconnection application with the appropriate entity; and (3) securing local permitting and zoning.[26]


[1] Qualifying Facility Rates and Requirements Implementation Issues Under the Public Utility Regulatory Policies Act of 1978, 168 FERC ¶ 61,184 (2019).

[2] See 18 C.F.R. Part 292 (2019).

[3] 16 U.S.C. §§ 796(17)-(18), 824a-3 (2012).

[4] NOPR at P 5.

[5] Id. P 7.

[6] Id. P 6.

[7] Id. P 8.

[8] Id. P 9.

[9] Id. P 10.

[10] Id. P 11.

[11] Id. P 12.

[12] See 18 C.F.R. § 292.309.

[13] NOPR at P 118.

[14] Id. P 127.

[15] Id. P 129.

[16] Id. P 79.

[17] Id. P 81.

[18] Id. (emphasis in original).

[19] Id. PP 32, 43-50.

[20] Id. P 51.

[21] Id. PP 33, 82-88.

[22] 18 C.F.R. § 292.204(a)(1); N. Laramie Range Alliance, 139 FERC ¶ 61,190, at PP 22-24 (2012).

[23] NOPR at P 94.

[24] 18 C.F.R. § 292.304(d).

[25] NOPR at PP 134-135.

[26] Id.