On September 19, 2019, the Federal Energy Regulatory Commission (“FERC” or “Commission”) issued a long-anticipated proposal to reform implementation of the Public Utility Regulatory Policies Act (“PURPA”). FERC’s Notice of Proposed Rulemaking (“NOPR”)1 contains key modifications that would provide additional flexibility for electric utilities and some state utility regulatory commissions, but it drew a partial dissent from Commissioner Richard Glick and will likely not satisfy some advocates of renewable power.
I. The Proposal
PURPA was passed in response to the 1970s energy crisis in the U.S., when natural gas was scarce and expensive and electric utilities were predominantly vertically integrated generation, transmission and retail monopolies. Among other features, PURPA created a market for power generated from non-utility owned producers by requiring utilities to purchase power from independent cogeneration and non-fossil or waste fueled facilities at prices equivalent to a utility’s avoided cost. The NOPR proposes to change FERC’s PURPA regulations in six key areas: (1) rate-setting approaches; (2) proximity requirements; (3) protest procedures; (4) non-discriminatory access thresholds; (5) minimum standards for legally enforceable obligations; and (6) reduced purchase obligations for certain electric utilities.
The NOPR’s most significant feature is a set of proposed rules that would allow states to set rates for purchases of electric energy from qualifying small power production facilities that vary over the term of a contract. In contrast, current regulations provide a Qualified Facility2 (“QF”) with two options for how to sell its power to an electric utility: the QF may 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 (the so-called “as-available” rate); or, the QF may choose to sell pursuant to a contract over a specified term (a fixed-price option that has caused one state — Idaho — to implement two-year contract terms).
The Commission proposes several approaches to set “as available” energy prices that vary throughout the life of a contract. These include the use of locational marginal prices ("LMPs") in Independent System Operator (“ISO”) and Regional Transmission Organization (“RTO”) markets or, outside of ISOs and RTOs, competitive methods like: (1) prices set at liquid electric market hubs; (2) prices calculated for efficient gas-fired generators based on proxy heat rates and gas-price indices; and (3) competitive solicitations that meet Commission-established criteria. States and non-jurisdictional utilities would retain the ability, but not the obligation, to offer fixed-priced contracts with prices established when a legally enforceable obligation is incurred. In such cases, FERC proposes to allow the use of projected revenue flows to establish either fixed energy rates or a series of specified rates in different contract years. To the extent that rates are not set through LMPs or a competitive method, FERC also proposes factors that states should consider in establishing rates for sales from PURPA-qualified sellers.
PURPA sellers would remain entitled to a fixed long-term contract price for capacity sales, with the price set through a competitive, transparent and non-discriminatory solicitation process.
The Commission proposes to reform its so-called one-mile rule, under which affiliated QFs that use the same energy resource are conclusively presumed to not be at the same site so long as they are at least one mile apart. The Commission notes that it has received reports suggesting that this presumption has given rise to gaming by some facility developers, who “segment” projects — particularly wind projects — to avoid exceeding the 80-megawatt (“MW”) small-power producer cap. In place of the one-mile rule, the Commission proposes to create a rebuttable presumption that affiliated facilities using the same resource within one to ten miles of one another are not at the same site. Facilities beyond ten miles would be conclusively presumed to be different sites, and facilities separated by less than a mile would be conclusively presumed to be at the same site.3 The Commission also provides guidance regarding how to properly measure the distance between sites.
Reduced barriers to protest
To facilitate the process of rebutting the “different sites” presumption, as well as to generally ease the burden of protesting QF certification filings, FERC proposes to do away with its current requirement that an entity must file for a declaratory order and pay an associated fee (currently $28,990) to challenge a QF certification or recertification. Instead, an entity would have an opportunity to intervene in a certification proceeding and protest outright. If a protester makes at least a prima facie case that the facility does not satisfy PURPA requirements, then the burden would shift to the certifying entity to show that the project is compliant. The Commission proposes a 90-day window in which it will act on protested filings, subject to extension to allow responses to information requests and tolling for complex or time-consuming cases.
Non-discriminatory access threshold
The NOPR proposes to reduce from 20 MW to one MW the amount of capacity necessary to establish a rebuttable presumption that a small power production facility has non-discriminatory access to electric markets within an ISO or RTO. Under the current rule, a small power production facility within the footprint of an ISO or RTO and producing less than 20 MW is rebuttably presumed not to have non-discriminatory market access, and can therefore require a utility to purchase its power; however, under the NOPR, that purchase requirement would attach only to those small power production facilities producing less than one MW. This proposed change would not apply to cogeneration facilities, where the rebuttable presumption would remain at 20 MW.
Minimum requirements for legally enforceable obligations
Under FERC policy, a legally enforceable obligation to purchase a qualifying facility’s output can exist even in the absence of a contract. Current regulations allow a QF to lock in an avoided-cost rate when a legally enforceable obligation is incurred, but they provide no guidance as to when such an obligation attaches.
While initially intended to prevent utilities from circumventing PURPA requirements by refusing to enter into contracts with QFs, commenters in recent Commission proceedings have pointed out that some developers use the legally enforceable obligation to attempt to lock in an avoided-cost rate at the time a developer notifies the electric utility of a potential project, regardless of whether the project is likely to be completed.
In response, FERC proposes to establish minimum requirements for the creation of legally enforceable obligations, including that a project must (1) be commercially viable; and (2) have a financial commitment to support construction. The Commission proposes to allow states to establish the criteria necessary for commercial viability and financial commitment.
Reduction in purchase obligation
Current regulations require electric utilities to purchase “any” energy and capacity available from QFs. However, in jurisdictions that have implemented retail electric choice programs, electric utilities no longer provide electricity to all customers, and their provider-of-last-resort (“POLR”) obligations may continue to decline as customers elect competitive suppliers. Consequently, FERC proposes, prospectively from the rule’s effective date, to reduce the obligation to purchase from a QF for any electric utilities whose supply obligations decline as a result of state-implemented choice programs. FERC also states that, in cases where utilities acquire electric supply for POLR purposes through competitive solicitations with a particular contract term (e.g., one year), the utility’s PURPA-purchase contracts should utilize the same term to accurately reflect avoided costs.
II. Dissenting Views
In a separate, partial dissent, Commissioner Richard Glick stated that the NOPR “would effectively gut” PURPA. Moreover, he expressed concern that FERC would usurp Congress’ role by implementing such sweeping changes, some of which, he claims, are inconsistent with statutory obligations. In particular, he took issue with the proposed removal of the requirement to offer fixed-price contracts, which, he argued, will negatively affect the ability of small power producers to finance their projects. Commissioner Glick also argued that small power producers of one MW or greater do not necessarily have non-discriminatory access to markets, given the level of sophistication necessary to participate in complex RTO and ISO markets. He agreed, however, with reforms of the one-mile rule, commercial viability requirements and reduced barriers to protest.
Certain segments of the renewable energy industry may also argue that the NOPR does not adequately protect their rights under PURPA. For example, in a move that seems to foreshadow some renewable-industry stakeholders’ concerns, the Solar Energy Industries Association (“SEIA”) filed supplemental comments in late August in an underlying FERC administrative docket. Among other positions, SEIA expressed support for mandatory purchase obligations by electric utilities outside of ISOs and RTOs, where, SEIA claims, markets do not necessarily discipline utility behavior. SEIA also argued that long-term, fixed-price contracts are essential to financing qualifying facilities, and that FERC should establish a federal standard for formation of a legally enforceable obligation.
III. Next Steps
The NOPR is the latest move in FERC’s years-long process of considering PURPA reforms. Comments on the NOPR will be due to FERC 60 days after the NOPR is published in the Federal Register, which should occur before the end of September. After the comment period closes, assuming no extension is granted, the FERC staff will review what is likely to be a significant volume of comments. A final order is unlikely before the end of the year, by which time one or more new commissioners may influence the Commission’s thinking, and a new presidential campaign will be in full swing, with the potential for an unusual level of political scrutiny.
In the meantime, FERC and stakeholders will continue to test PURPA’s reach. In the most recent example, in a separate decision issued the same day,4 FERC found that a recently enacted New Hampshire statute, Senate Bill 365, is preempted by PURPA and the Federal Power Act. With respect to PURPA, FERC found that the bill’s mandate for electric utilities to purchase electric energy from certain biomass and waste facilities at 80 percent of default retail rates likely results in prices that exceed PURPA-mandated avoided costs (based on findings by the New Hampshire Commission), while the statute provides no means for state-level authorities to prevent rates paid to the generators from exceeding avoided costs.
The NOPR has the potential to give states more flexibility in how they implement PURPA by providing increased latitude for policies that impact the incentives for continued growth in small renewable generation. The proposal appears to lower both the floor and ceiling for such state policies, with the opportunity for more significant movement on the floor. As indicated by Commissioner Glick’s dissent, commenting parties are likely to dispute whether FERC’s proposal, if adopted, would lower the floor beyond the statutory limit.
1. Qualifying Facility Rates and Requirements, Implementation Issues Under the Public Utility Regulatory Policies Act of 1978, 168 FERC ¶ 61,184 (2019).↩
2. A QF is a facility that uses the same energy source, owned by the same person(s) or its affiliates, is located at the same site (within one mile of the facility sought for qualification), and does not exceed 80 MW. See 18 C.F.R. §§ 292.203 and 202.204.↩
3. Hydroelectric facilities would be conclusively presumed to be at the same site if within one mile and on the same impoundment.↩
4. New England Ratepayers Association, 168 FERC ¶ 61,169 (2019). ↩
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