The Federal Energy Regulatory Commission (FERC) is considering changes to its regulations implementing the Public Utility Regulatory Policies Act of 1978, or “PURPA,” in a pending notice of proposed rulemaking (NOPR). The act requires electric utilities, including public power utilities, to purchase electricity generated by certain small renewable power production resources and cogeneration facilities.
The proposed changes would update FERC’s regulations to account for significant industry changes since PURPA was enacted, while still appropriately encouraging cogeneration and small power production. In recent joint comments filed with FERC, the American Public Power Association and the Large Public Power Council (LPPC) expressed support for the NOPR’s proposed reforms.
A Short PURPA Primer
PURPA was enacted during a profoundly unsettled time in the U.S. energy industry. Oil prices skyrocketed during the 1973 oil embargo and remained elevated after the crisis abated. A central aim of PURPA was reducing the country’s reliance on then-declining oil and natural gas supplies by promoting development of renewable resources and more efficient use of fossil fuels through cogeneration. President Carter warned in a 1977 address that “unless profound changes are made to lower oil consumption, we now believe that early in the 1980s, the world will be demanding more oil than it can produce.”
The crisis directly impacted the power industry, as petroleum products fueled 16 percent of electric generation at that time. The structure of the electricity sector was also much different than it is today; vertically integrated utilities were the norm, and third-party generators had little opportunity to sell energy or capacity at wholesale.
Section 210 of the statute directed FERC to adopt rules “as it determines necessary to encourage cogeneration and small power production,” leaving many of the details to FERC. However, PURPA mandates some specific requirements for FERC’s rules. Most notably, the statute directed FERC to adopt a requirement that electric utilities purchase all power made available by “qualifying facilities” (QFs). This is commonly referred to as the “must purchase” requirement. PURPA defines two categories of QFs: small power production facilities and cogeneration facilities. Small power production facilities must have a capacity of 80 megawatts or less and a primary energy source from renewable, biomass, waste, or geothermal resources. A cogeneration facility (sometimes called combined heat and power) produces electric energy and other forms of useful energy such as steam or heat.
FERC’s regulations allow a QF to sell power to an electric utility on either an “as available” basis, or over a specified term pursuant to a legally enforceable obligation (such as a contract). Like the name implies, sales on an “as available” basis are made when the QF has energy available to sell to the utility but does not undertake a longer-term supply commitment. As available sales are limited to energy and do not include capacity. Sales pursuant to a legally enforceable obligation can include energy and capacity.
Under PURPA, an electric utility’s cost to buy power from a QF is not supposed to exceed what it would have cost the utility to generate the power itself or purchase the power from another source – a concept that FERC refers to as “avoided cost.” Although FERC establishes guidelines for calculating avoided costs, PURPA generally gives state public utility commissions responsibility for determining the avoided costs for the utilities they regulate. Under PURPA, electric utilities whose rates are not regulated by state PUCs (including most public power utilities) are called “nonregulated electric utilities,” and may set their own avoided cost rates.
Proposed Avoided Cost Changes Reflect an Evolving Industry
PURPA directs FERC to revise its regulations implementing the statute “from time to time,” but FERC has not comprehensively revised its PURPA rules since they were originally adopted in 1980. The proposals in the NOPR properly seek to account for the monumental changes in the energy industry over the last four decades, including FERC’s open access transmission requirements, the development of organized wholesale markets administered by regional transmission organizations (RTOs) and independent system operators (ISOs), and the explosive growth in non-PURPA-driven renewable generation.
The bulk of the proposed changes in FERC’s NOPR relate to implementation of PURPA’s “must purchase” requirement and, in particular, determining avoided cost rates in an evolving energy industry landscape. The Association has supported reasonable reforms to FERC’s PURPA rules, citing member concerns that the must purchase obligation requires public power utilities to buy power they do not need from QFs, often at rates that are higher than what can be obtained from the market.
The revisions contemplated by FERC’s NOPR would also make clear that states and nonregulated electric utilities can rely on competitively determined prices to set avoided costs in certain circumstances. For example, FERC proposes to clarify that the locational marginal price (LMP) in RTO/ISO markets could be used as a measure of avoided costs for QF sales of “as available” energy. This sensible suggestion recognizes 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.” (NOPR ¶ 45).
Outside organized RTO/ISO markets, FERC proposes to authorize other competitively determined prices to help utilities set avoided costs, such as prices set at a liquid market hub or based on a proxy combined cycle generating unit. FERC observes that states and nonregulated electric utilities would still need to show that the set cost reasonably represents a competitive market price for the specific electric utility purchasing QF energy.
The NOPR also proposes to explicitly allow for competitive solicitations, such as requests for proposals (RFPs), to set avoided cost rates for energy and capacity, provided that the solicitations are “transparent and non-discriminatory.” The concept of establishing avoided cost based on such solicitations is sound, as these processes can elicit price signals of the value of alternative energy and capacity, although the Association and LPPC have expressed some concerns with the factors FERC proposes to judge whether a competitive solicitation is suitably “transparent and non-discriminatory.”
It is important to point out that the proposed changes to FERC’s avoided cost regulations would largely confirm authority that states and nonregulated electric utilities already possess. Ever since FERC adopted its PURPA regulations, it has made clear that states and nonregulated electric utilities have “great latitude” in implementing the rules (NOPR ¶ 35), and the record in the NOPR proceeding indicates that competitively determined prices are already in use as a measure of avoided costs in some areas. FERC specifically acknowledges in the NOPR, for example, that some states already use LMP to set avoided cost rates, and explains that its proposed rules would clarify that “a state [or nonregulated electric utility] would be able to adopt LMP as a per se appropriate measure of the as-available energy component of avoided costs.” (NOPR ¶ 50).
Modifying the “Lock-in Rule”
In addition to the proposed changes that address how a utility’s avoided costs may be calculated, the NOPR also proposes changes to when they may be calculated.
Under FERC’s existing rules, a QF selling energy or capacity to a utility under a legally enforceable obligation can elect to be paid a rate based on the electric utility’s avoided costs calculated either at the time of delivery or when the legally enforceable obligation is incurred. The latter option is sometimes referred to as the “lock-in rule,” as it gives QFs the option of locking in an avoided cost rate for the term of an agreement. FERC recognized from the outset that locked in QF rates could exceed avoided costs if the purchasing utility’s costs decline after a contract is executed, but FERC assumed that over- and under-estimates of avoided costs would “balance out” over time. In the NOPR, however, FERC points to evidence that “overestimations of avoided cost have not been balanced by underestimations.” (NOPR ¶ 30). This was reinforced by a recent report from Concentric Energy Advisors prepared for the Edison Electric Institute, which found that annual over-recovery relative to market prices for a sampling of solar QF agreements between 2013 and 2019 was up to $116.8 million, and an over-recovery for a sampling of wind contracts between 2009 and 2018 was up to $99.4 million.
In light of this evidence, a rule permitting energy rates to vary over the term of a contract would more accurately reflect the purchasing utility’s avoided cost, in compliance with PURPA’s statutory requirements. As such, FERC proposes to explicitly allow states and nonregulated electric utilities to require QF energy rates to vary during the term of the contract. FERC also preliminarily finds that this revision would not materially affect QFs’ ability to obtain financing.
Lifting the Must Purchase Obligation
The NOPR also proposes reasonable changes to when electric utilities can be relieved of the must purchase obligation under section 210(m) of PURPA. Added in 2005, section 210(m) allows an electric utility to terminate its obligation to incur new QF purchase obligations where the Commission finds that QFs have non-discriminatory access to markets with certain defined characteristics, such as organized RTO/ISO markets. FERC currently presumes that any QF with a capacity of 20 MW or less does not have non-discriminatory access to markets, but the NOPR proposes to reduce this figure to 1 MW for small power production facilities (the presumption would remain at 20 MW for cogeneration facilities). FERC cites greater experience with organized markets and rules promoting market access for smaller resources as reasons for the proposed change and observes that resources larger than 1 MW should be able to obtain the expertise required to participate in the wholesale markets.
While termination of the must purchase obligation under PURPA section 210(m) has generally been limited to RTO/ISO markets, the NOPR seeks input on whether QF access to other kinds of wholesale markets could support termination of the obligation. The Association and LPPC strongly supported this inquiry in their comments on the NOPR, urging FERC to examine whether QF access to liquid market hubs outside RTOs/ISOs could support relief under PURPA section 210(m).
In calculating the 80 MW limit for small power production facilities, FERC must account for all power production facilities “located at the same site.” FERC currently assumes that affiliated facilities using the same energy resource are separate facilities so long as they are more than one mile apart from each other. The NOPR cites concerns that some QF developers have strategically located related facilities slightly more than one mile apart to evade the 80 MW limit, and there appears to be broad support for reasonable reforms to address these concerns. The NOPR proposes replacing the strict “one-mile rule” with a tiered approach, under which interested parties would have the opportunity “to show that facilities between one and ten miles apart (i.e., more than one mile apart and less than ten miles apart) actually are a single facility (with distances one mile or less still irrebuttably a single facility, and distances ten miles or more irrebuttably separate and different facilities).” (NOPR ¶ 9).
Finally, FERC proposes fair and reasonable changes to a number of other PURPA regulations. For example, clarity on when, short of an actual contract, a QF can establish a legally enforceable obligation for an electric utility to purchase its energy. While states and nonregulated utilities would continue to have discretion on this issue, FERC proposes that establishing a legally enforceable obligation would require that a QF be able “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, state-determined criteria.” (NOPR ¶ 140). The Commission also proposes to allow interested parties to challenge QF self-certifications or self-recertifications by filing a protest – a departure from the current burdensome policy that requires a party challenging a QF certification to file a petition for declaratory order at FERC.
In his remarks announcing the NOPR, FERC Chairman Neil Chatterjee emphasized that the agency’s regulations implementing PURPA need to “reflect today’s markets rather than the energy landscape of the ‘70s.” FERC’s NOPR proposes a collection of reasonable reforms that acknowledge the profound industry changes since 1978 and take into account the agency’s experience with the implementation of its existing PURPA rules. The Association encourages the Commission to move forward and adopt the NOPR proposals in a final rule.