FERC’s Final PURPA Rule May Significantly Alter the Landscape for Qualifying Facilities


On July 16, 2020, the Federal Energy Regulatory Commission (“FERC” or “Commission”) issued Order No. 872 (“Order”),[1] a final rule that significantly revised its rules implementing the Public Utility Regulatory Policies Act of 1978 (“PURPA”).[2] Congress enacted PURPA to reduce the country’s reliance on oil and natural gas by promoting “Qualifying Facilities” (“QFs”) that rely on alternative energy sources or more efficient generation. Since their promulgation, FERC’s regulations implementing PURPA have been largely unaltered. FERC opined that the energy industry has substantially evolved since PURPA was promulgated and that the final rule is necessary to address the changing landscape and more closely align with underlying congressional intent.

Among other things, PURPA requires electric utilities to offer to purchase electric energy from QFs, which are categorized as either small power producers or cogenerators.[3] The rate that a QF may receive for energy must be a rate “not to exceed the incremental cost to the electric utility of alternative electric energy,” 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.”[4] In other words, “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.”[5] This is referred to as the utility’s “avoided cost.”

Rates for energy are generally categorized as either fixed or “as-available.” Fixed rates are generally fixed at the time of the contract or other legally enforceable obligation (“LEO”) between the QF and the utility and do not vary over the term of the contract or LEO. For example, many renewable energy projects, which generally produce only to sell into the market and rely on a fixed revenue stream for financing, often rely on fixed energy rates. Conversely, other types of generators, such as cogeneration facilities, might only sell into the market when they have excess energy and will take the prevailing price at the time of sale. This rate is referred to as an “as-available” energy rate and is variable. Rates for capacity are generally fixed at the time of contract or LEO. QF rates for energy and capacity are set by state commissions.

Order No. 872 follows a technical conference,[6] notice of proposed rulemaking (“NOPR”),[7] and multiple rounds of industry comments. The Order adopts most of the NOPR proposals and substantially alters the rules for QFs.

State Flexibility in Establishing QF Energy Rates

Much of Order No. 872 focused on providing state commissions additional options to establish the avoided cost rate for both as-available and contract rates. These options allow for additional reliance on variable energy rates keyed to local markets.

Changes Pertaining to As-Available Rates

  • As-available QF energy rates paid by electric utilities located in Regional Transmission Organization and Independent System Operator (“RTO/ISO”) markets may be based on the market’s locational marginal prices (“LMPs”), or similar energy price derived by the market, in effect at the time the energy is delivered. In such cases, there would be a rebuttable presumption rather than a per se rule that LMPs in RTO/ISOs can reflect a purchasing electric utility’s avoided energy costs. A QF seeking to rebut the presumption could do so in an appropriate forum under PURPA.
  • As-available QF energy rates paid by electric utilities located outside of RTO/ISO markets may be based on competitive prices determined by liquid market hub energy prices. This option 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. The price may also have to account for transmission costs.
  • As-available QF energy rates paid by electric utilities located outside of RTO/ISO markets may be based on competitive prices determined by formula rates based on observed natural gas prices and a specified heat rate. The price may also have to account for natural gas transportation costs.

Changes Pertaining to Contract/LEO Rates

  • Fixed energy rates may 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. Although FERC permitted this type of calculation before, in Order No. 872 it clarified that “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 could be a series of specified rates that change from year-to-year (or other periods) in future years.”[8]
  • Energy rates under QF contracts and LEOs may 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. This option allows states to require variable energy rates (in conjunction with fixed capacity rates). In doing so, FERC found that “a variable energy avoided cost approach is a more accurate way to ensure that payments to QFs equal, but do not exceed, avoided costs. 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.”[9]
  • Energy and/or capacity rates may be determined through a competitive solicitation process, such as an RFP, with the process designed to ensure that the competitive solicitation is performed in a transparent, non-discriminatory fashion. FERC required the following minimum criteria governing the use of solicitations: “(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.”[10]

Modification of “One-Mile Rule”

FERC clarified its one-mile rule to state that if affiliated small production QFs are located one mile or less from each other and use the same energy resource, they will be deemed to be at the same site, and if affiliated small power production QFs are located more than 10 miles apart and use the same energy sources, they will be deemed to be on separate sites. Additionally, FERC established a rebuttable presumption that affiliated small production QFs that are more than one mile apart but less than 10 miles apart and use the same energy source are at different sites.

Self-Certification Process

The Order allows interested parties to protest or challenge QF self-certifications without filing a petition for declaratory order. Additionally, the Commission clarified that protests can only be made to recertifications that make substantive changes to the existing certification.

Limiting Mandatory Obligation to Purchase

FERC revised PURPA Section 210(m), “which provide[s] for the termination of an electric utility’s obligation to purchase from a QF with nondiscriminatory access to certain markets.”[11] FERC revised the rebuttable presumption that small power production QFs have nondiscriminatory access to markets by reducing the net capacity threshold from 20 MW to 5 MW. Additionally, the Order sets forth factors that QFs may utilize to argue a lack of nondiscriminatory access to markets.

State-Specific Criteria for Legally Enforceable Obligation

The Commission set forth new guidance for states regarding how LEOs can be established utilizing state-specific criteria, including a requirement that QFs demonstrate commercial viability and a financial commitment to development. Examples of criteria may include taking meaningful steps to obtain site control adequate to commence construction of the project at the proposed location, submitting applications to obtain necessary local permitting and zoning approval, and filing an interconnection application with the appropriate entity.

Glick Dissent

In a partial dissent, Commissioner Glick stated that Order No. 872 is, in effect, the Commission “administratively gutting”[12] its implementation of PURPA and is “not just poor public policy, but also arbitrary and capricious agency action.”[13] In his opinion, the Order failed to encourage QF development and promote competition and failed to address core issues in the implementation of PURPA on a state-by-state basis. He argued that fixed-price contracts are essential for financing and the future cost recovery of QFs. He also disagreed with the rebuttable presumption set forth that LMPs in RTO/ISOs can reflect a purchasing electric utility’s avoided energy costs and argued that LMPs do not provide a proper representative measure of avoided cost rates. Finally, Commissioner Glick asserted that the Commission failed to explain or provide any evidence supporting the Order’s reduction in the threshold for the rebuttable presumption that small power production QFs have nondiscriminatory access to markets from 20MW to 5MW.


Arguably the most controversial aspects of Order No. 872 pertain to allowing states to make energy rates variable rather than fixed. FERC argued that the final rule does not eliminate fixed energy rates but rather provides a level of flexibility to states to require either variable “as available” energy rates and fixed capacity rates, or both fixed energy capacity rates. FERC explained that states that opt for a “fixed energy rate may base it on projected energy prices during the term of a QF’s contract based on the anticipated dates of delivery.”[14] On the other hand, FERC also argued that the revisions in the final rule were necessary because PURPA does not allow the Commission to require QF rates in excess of actual avoided costs. The Commission found that there have been instances where long-term fixed QF rates were higher than the purchasing electric utility’s actual avoided costs, which has resulted in consumers having to absorb the cost.

Many renewable energy projects rely on fixed revenues for financing. In Order No. 872, FERC responded to this concern by arguing that financing arrangements such as contracts for difference are available.[15] Contracts for difference are a type of hedging arrangement where a renewable generating facility is paid a fixed rate by a bank or large corporation, sells its output into the market, and the bank or corporation receives the market price (in addition to other consideration). This arrangement allows the project to receive a fixed energy rate in lieu of a variable market rate. However, these types of arrangements require organized markets like RTOs/ISOs in which to sell.

Another troubling aspect of the Order is that a utility may resort a competitive bidding/RFP process to establish avoided cost in non-ISO/RTO markets. Assuming renewable energy projects were willing to engage in such a process, the point of the process would be to establish a “lowest common denominator” for avoided cost. The effect would be to discourage development of projects, in part because not all renewable energy projects are alike and the competitive price for one project may not be viable for other projects. While the Order allows other means of establishing avoided cost in non-ISO/RTO markets, it potentially gives utilities the option of engaging in a process which could impede renewable project development.

The final rule will go into effect 120 days after the date of publication in the Federal Register. The Commission stated that the rule will not affect “existing contracts or [legally enforceable obligations] or existing facility certifications.”[16]

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

[2] 18 CFR pt. 292 (2019); 16 U.S.C. 796(17)-(18), 824a-3.

[3] See 16 U.S.C. § 824a-3(a).

[4] 16 U.S.C. 824a-3(d).

[5] Order No. 872 at P 14.

[6] Supplemental Notice of Technical Conference, Implementation Issues Under the Public Utility Regulatory Policies Act of 1978, Docket No. AD16-16-000 (May 9, 2016).

[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).

[8] Order No. 872 at P 227.

[9] Id. at P 253.

[10] Id. at P 413.

[11] Id. at P 64.

[12] Partial Dissent, P 5.

[13] Id. at P 7.

[14] Order No. 872 at P 58.

[15] Id. at P 238.

[16] Id. at P 66.

© 2020 Blank Rome LLP. All rights reserved. Please contact Blank Rome for permission to reprint. Notice: The purpose of this update is to identify select developments that may be of interest to readers. The information contained herein is abridged and summarized from various sources, the accuracy and completeness of which cannot be assured. This update should not be construed as legal advice or opinion, and is not a substitute for the advice of counsel.