The FERC recently issued a final rule (Order No. 872) revising its regulations implementing the Public Utility Regulatory Policies Act of 1978 (PURPA), which encourages the development of certain renewable and cogeneration facilities.  PURPA, and FERC’s rules implementing it, establish benefits to those facilities by obligating electric utilities to purchase electricity from them.  As discussed in a prior post to this blog, FERC considered reforming its regulations due in part to changes in the electric power industry over the last several decades.

This final rule should be of interest to a wide range of electricity market participants, including utilities and investors in cogeneration and certain types of small scale generation facilities.  The new regulations are expected to alter somewhat the commercial benefits accorded qualifying generation facilities under PURPA.  The revised rules are certain to be controversial.  Notably, one FERC commissioner dissented from the order “because it effectively guts the Commission’s implementation” of PURPA.


PURPA established a framework to encourage the development of small power production facilities, i.e., those 80 MW and under, that do not rely on fossil fuel, and cogeneration facilities, and directed FERC to set implementation rules.  Generation resources that meet specified standards are deemed “Qualifying Facilities,” or QFs, and, among other benefits, have the right to sell electricity to a utility at the utility’s avoided cost or at a negotiated rate.  Responsibility for implementing PURPA’s provisions is shared between FERC and the states.  FERC establishes the standards for qualification and certifies QFs.  FERC also sets the general standards for determining a utility’s avoided costs, but each state is responsible for determining the actual avoided costs of its utilities.[1]

In its Notice of Proposed Rulemaking (NOPR) in this proceeding, FERC noted that the electric power industry has changed quite a bit since the rules implementing PURPA were issued in 1980.  Then, the industry was dominated by vertically integrated utilities that served customers from their own generation resources.  Today, there are organized wholesale markets administered by Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs) where independent generators can sell power at competitive prices.  These  markets have helped support the entry of renewable resources.

Final Rule

In the final rule, FERC revised its PURPA regulations principally with regard to: (1) the determination of QF rates based on a utility’s avoided costs; (2) the application of the 80 MW limitation to the combined capacity of affiliated small power production QFs located at the same site; and (3) the termination of the utilities’ mandatory purchase obligation from QFs with nondiscriminatory access to competitive markets, such as those administered by ISOs and RTOs.

Avoided cost determinations for QF rates

Old Rule.  Under the PURPA statute, a QF’s rates that a purchasing utility must pay are capped at the utility’s “avoided costs,” i.e., the purchasing utility’s incremental costs for power. Under long-standing FERC regulations, QFs could elect to have the avoided cost rate established at the time of energy delivery (i.e., a variable rate) or at the time of contract execution (i.e., a fixed rate).  Thus, QFs could obtain a long term purchase commitment (under a contract or a “legally enforceable obligation”) from the purchasing utility at a fixed avoided cost rate, which would not vary over the term of the contract even though the purchasing utility’s actual avoided costs would be expected to fluctuate over the term of the contract.

New Rule. FERC’s final rule gives states the authority to require variable energy rates in long-term contracts or legally enforceable obligations, i.e., that avoided costs may be determined at the time of energy delivery and not be fixed for the duration of a long-term purchase commitment.  The variable energy rate in a QF’s long-term contract may be based on transparent, competitive market prices, determined using publicly available price indices.  Specifically, states may adopt a presumption that locational marginal prices in RTO and ISO markets establish fair avoided cost rates for purchasing utilities.  Thus, the new rule allows states to abandon the use of administrative mechanisms to determine avoided costs and to require QFs and purchasing utilities to rely upon price indexed long-term contracts.  For competitive markets outside of RTOs and ISOs, states may rely upon prices at liquid market hubs or formulas using price indices and generator heat rates to establish avoided costs.  The new rule also permits states to establish avoided costs for both energy and capacity based on transparent and non-discriminatory competitive solicitations.[2]

QFs would still retain the ability to elect use of a fixed capacity rate in a long-term contract or legally enforceable obligation, determined at execution, based on the purchasing utility’s avoided capacity costs at that time.  The QF industry is concerned that the switch to variable energy rates, even with fixed capacity rates, will make financing QFs more difficult.

The new rule also provides greater certainty as to when a legally enforceable obligation (a “LEO”) is created and thereby vesting a QF’s entitlement to the mandatory purchase obligation.  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 a LEO.  The new rule prohibits states from using other requirements for establishing LEOs, which had been relied upon under the old rules, such as execution of interconnection agreements or power purchase agreements, or that QFs demonstrate their ability to deliver firm energy or energy within 90 days.

FERC declined to adopt a proposal from the NOPR, that would have allowed purchasing utilities in states with retail choice to obtain special relief from the avoided costs rules.

QF facilities located at the “same site”–  the “one-mile rule”

Old Rule.  By statute, PURPA’s benefits are available only to renewable facilities that do not exceed a production capacity of 80 MW at the “same site.”  By regulation, FERC defined these small power production facilities located at the “same site” as facilities owned by the same person or its affiliates, using the same energy resource, and located within one-mile of the facility seeking QF qualification (the “one-mile rule”).  The one-mile rule precluded circumvention of the 80 MW size limit through arbitrary division of a single project into multiple projects.

New Rule.  The new rule retains the one-mile rule, with its non-rebuttable presumption that affiliated facilities located within one mile of each other are deemed to be at the same site and adds a new non-rebuttable presumption that affiliated facilities located more than 10 miles apart are deemed to be at separate sites.  The new rule allows 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 and are, therefore, subject to the 80 MW size limitation.

Termination of mandatory purchase obligation from QFs with access to competitive markets

Old Rule.  A utility may terminate its obligation to enter into new contracts to purchase power from QFs if the utility can show that the QF has nondiscriminatory access to competitive wholesale markets, such as those operated by RTOs or ISOs.  There is a rebuttable presumption that QFs with a net capacity at or below 20 MW do not have such access and are, therefore, entitled to sell their energy to a utility at avoided cost rates.

New Rule.  The new rule lowers the competitive market rebuttable presumption from a threshold of 20 MW to 5 MW (not 1 MW as had been proposed in the NOPR) for small power production facilities but not for cogeneration facilities.  The new rule provides examples of factors relevant to a showing that QFs lack nondiscriminatory access to particular competitive markets.

Other rule changes

Challenges to a QF’s self-certification or recertification.  Under the old rules, an entity seeking to challenge a QF’s self-certification or recertification had to file a declaratory order and pay the associated filing fee.  The new rule allows any interested party to file a protest of a QF’s self-certification or recertification (if the latter makes substantive changes to the existing certification), without paying a filing fee.

Effective Date of New Rules.  The new rules will be effective 120 days after their publication in the Federal Register.  The new rules are generally effective prospectively for new contracts or LEOs and for new facility certifications and recertifications filed on or after the effective date of the final rule.  FERC does not intend that the final rule permit disturbance of existing QF certifications or existing contracts or LEOs that are pending before state commissions prior to the effective date of the final rule.

Commissioner Glick’s dissent

Commissioner Richard Glick dissented in part from the final rule order “because it effectively guts the Commission’s implementation of the Public Utility Regulatory Policies Act (PURPA)” and  “the Commission is attempting to accomplish via administrative fiat what Congress has repeatedly declined to do via legislation.”  The Commissioner’s basic point is that PURPA in part charged FERC with encouraging the development of QFs and preventing discrimination against QFs by incumbent utilities, and the final rule does not satisfy these responsibilities.

Commissioner Glick warns of the following consequences of the final rule:

  • Eliminating the requirement that states provide a contract option that includes a fixed energy rate means that QF developers may face the prospect of not receiving any fixed revenue stream, whether for energy or capacity. FERC precedent permits utilities to offer a capacity rate of zero to QFs when the utility does not need incremental capacity.  FERC has recognized in the past that fixed-price contracts play an essential role in financing QF facilities, and entities with experience financing and developing QFs explain in this proceeding that a fixed revenue stream is necessary to obtain the financing.
  • Allowing states to set the rate for as-available energy at the relevant locational marginal price (LMP) or a similarly “competitive market price” may result in a rate that is not a representative measure of avoided cost. Many regions of the country have not established sufficiently competitive markets, and short-term or spot prices, such as LMP, may not reflect the long-term marginal energy costs avoided by purchasing utilities.
  • Reducing the size threshold from 20 MW to 5 MW for preservation of the mandatory purchase obligation in competitive markets will diminish renewables development in ISO/RTO market areas. Commissioner Glick disputed the final rule’s conclusion that small renewables projects will not face access barriers in RTO/ISO markets.

[1] Avoided cost is the incremental cost of electric energy or capacity which, but for the purchase from the QF, a utility would generate itself or purchase from another source.

[2] Energy rates generally recover the variable costs of producing energy.  Capacity rates generally recover the fixed costs of a generating facility.

Photo of Mark Perlis Mark Perlis

Mark Perlis is a seasoned energy and environmental attorney with a broad-based federal regulatory and litigation practice encompassing all aspects of the electric utility industry.  He regularly represents clients in adjudicatory and rulemaking proceedings before the Federal Energy Regulatory Commission and state public…

Mark Perlis is a seasoned energy and environmental attorney with a broad-based federal regulatory and litigation practice encompassing all aspects of the electric utility industry.  He regularly represents clients in adjudicatory and rulemaking proceedings before the Federal Energy Regulatory Commission and state public utility commissions, and in stakeholder proceedings conducted by ISOs and RTOs across the country.  Mr. Perlis represents independent power producers, power marketers, traditional electric utilities, and renewables developers.  Mr. Perlis specializes in regulatory issues associated with the design of and participation in organized electric markets, including energy and capacity markets, generation interconnection, and transmission service.

Mr. Perlis has led representations of numerous clients faced with non-public, FERC enforcement investigations and has negotiated favorable settlements with the FERC Office of Enforcement.  He also regularly advises companies on compliance policies and procedures and conducts compliance program audits and reviews.  In addition, he counsels clients across the industry on Department of Energy efficiency regulations, energy trading compliance, project development, commercial agreements, and contract disputes.

Mr. Perlis also advises clients in the electricity industry and in the biofuels and biotechnology industries on matters pertaining to federal and state responses to climate change.  He advises clients on U.S. EPA’s Clean Power Plan and potential state implementation plans.  He also advises producers of conventional ethanol and advanced biofuels on federal and state regulatory issues, including the federal Renewable Fuels Standard program, California’s Low-Carbon Fuels Standard, and emerging markets for Renewable Identification Numbers and Low-Carbon Fuel credits.  Mr. Perlis has also advised clients on trading emission allowances and credits, including for sulfur dioxide and carbon dioxide, as well as on renewable energy credit trading.