The Federal Energy Regulatory Commission (“FERC”) issued a proposed rulemaking on September 19, 2019, that entails a sweeping overhaul of the Public Utility Policy Act of 1978 ("PURPA") which could have significant impact on the development of renewable energy projects. It addresses a number of subjects, including the price a utility must pay for electricity from a PURPA qualifying facility ("QF"), further elimination of a utility's obligation to purchase from a QF and refining the definition of what constitutes a single QF to potentially encompass multiple facilities of a single owner within 10 miles distance. ^[1]  Although the NOPR was approved by a majority of FERC Commissioners, a dissenting Commissioner stated that the NOPR “would effectively gut the Public Utility Regulatory Policy Act” and House Energy and Commerce Committee Chairman, Frank Palline, Jr., called the NOPR “a senseless, partisan move to gut an absolutely crucial tool for promoting competitiveness and sustainable energy.”

The true impact of the NOPR is not so black and white.  In regions of the country that are regulated and vertically integrated (meaning the utility controls electric generation and transmission), the NOPR may be more impactful because the independently developed renewable small power production facilities under 80MW and cogeneration facilities (collectively referred to as qualifying facilities or QFs) may no longer have access to long-term fixed-price contracts with utility purchasers.  On the other hand in unregulated electric generation markets, such as the PJM ISO/RTO where 10 of this law firm’s offices are located, the overall impact of the NOPR may be less significant because other incentives and mandates are in place for renewables such as renewable energy credits under renewable portfolio standards.  Nevertheless, interested parties and renewable energy generation developers should continue to monitor these developments, especially at State level public service commissions which likely will undertake responsive rulemakings after this FERC rule becomes final.

SUMMARY OF NOPR

The primary changes to PURPA proposed under the NOPR include:

Energy Rate Changes^[2]

1. For QF power purchase agreements, the NOPR would give state regulatory commissions the authority to set energy rates (but not capacity rates) utilizing a number of alternative approaches:
   
   
   • Fixed energy rates to be based on forecasted estimates of the stream of revenue flows during the term of the contract. The state regulatory commission could rely on market estimates of forecasted energy prices at the times of delivery over the anticipated life of the contract utilizing a forward price curve to develop a fixed energy rate component for the contract; OR
   • Rates that vary in accordance with changes in the purchasing utility’s avoided costs at the time the energy is delivered but where the QF would continue to be entitled to a contract with avoided capacity costs calculated and fixed at the inception of the contract.
2. The NOPR would give state regulatory commissions choices in setting “as-available” QF energy rates:
   
   
   • based on market prices (such as locational marginal price in deregulated markets for states located in a regional transmission organization having an independent system operator)^[3] ; or
   • for QFs selling to electric utilities located outside of organized electric markets pricing could be at competitive prices from liquid market hubs or rates or based on combined cycle prices based on a formula rate established by the state regulatory commission using published natural gas price indices and a proxy heat rate for an efficient natural gas combined-cycle generating facility.
3. State regulatory commissions also could have the flexibility to set energy and capacity rates pursuant to a competitive solicitation process conducted pursuant to transparent and non-discriminatory procedures.
4. The NOPR would permit the state regulatory commissions to take into account that an electric utility’s obligation to purchase from QFs may be reduced to the extent the purchasing electric utility’s supply obligation has been reduced by a state retail choice program.  Some states already take this into account by imposing shorter term contracts to recognize the potential more limited supply obligation of utilities^[4]. As stated in the NOPR, ‘…allowing states to require contractual energy rates to vary could result in longer QF contracts…”

Relief From Utility Purchase Obligations

The NOPR would revise the PURPA regulations to reduce the rebuttable presumption threshold  that a QF has nondiscriminatory access to certain markets for small power production facilities (but not cogeneration facilities) from 20 MW to 1 MW, with the net effect that only very small QF facilities could demand a utility purchase contract within certain RTO/ISOs. For cogeneration facilities, the 20 MW presumption would remain.

Modification to One-Mile Rule

The NOPR would replace the “one-mile rule” for determining whether generation facilities should be considered to be part of a single facility.  The NOPR contemplates that in some cases equipment within 10 miles could be deemed to be part of the same facility.  This provision is apparently largely targeted at wind facilities that could be spread at a wider distance and where some of the benefits of PURPA are restricted to facilities below designated sizes.

Legally Enforceable Obligation to Purchase

The NOPR would more tightly clarify when a binding obligation attaches to the utility to purchase a QF’s energy based on objective factors specified by the state regulatory commission such as demonstrate commercial viability and obtaining financial commitments for construction.

Right to Challenge a QF Self-Certification

The NOPR would allow a third-party to protest a self-certification or self-recertification of a QF without being required to file a separate petition for declaratory order and to pay the associated filing fee.

IMPACT
The proposed NOPR could have significant impact on QF facilities being developed in sections of the country that are not located in deregulated competitive markets.  Although the impact may be less significant in the unregulated markets, such as the PJM ISO/RTO where ten of this firm’s officers are located, interested parties should monitor and possibly participate in responsive rulemakings at state public utility commissions.  Potential impacts of the NOPR are as follows:

1. In regulated markets, the NOPR may be significant by inhibiting QF financing because QFs may no longer have access to long-term fixed-price contracts with utility purchasers.
2. In unregulated electric generation markets like PJM, (with the possible exception of Virginia), the NOPR may be less impactful because states have enacted and more recently supplemented renewable portfolio standards programs such that a significant part of a renewable project’s revenue stream comes from the sale of RECs. Further, the Maryland Offshore Wind REC (“OREC”) program provides the utility making a payment intended to cover the entire capital cost of the facility with the OREC project selling its energy into the PJM market and disgorging the revenues back to the utilities, such that the ORECs provide the entire revenue stream to the project.
3. Upon a quick review of PJM, there does not appear to have been any significant use of the must-purchase provisions of PURPA to obtain long-term fixed price contracts in the region in recent years, making the NOPR less impactful.
4. A limited sampling of utility tariffs and riders for utilities within PJM that relate to the purchase of QF power would indicate that pricing for “as-available” QF sales to utilities is already largely geared to short term locational marginal costs, again making the NOPR less impactful.
5. A number of major utilities in PJM already have received FERC confirmation under the provisions of the Energy Policy Act of 2005 that competitive markets exist above the 20 MW level thus already precluding QF facilities above 20 MW from utilizing the utility must-purchase option and making the NOPR less impactful.
6. The modification of the one-mile rule possibly to ten miles might impact the development of disperse renewable energy generation facilities such as wind farms, because wind turbines between one and ten miles now might not be considered separate small power QFs and thus not qualify for the benefits of PURPA if under the new rule deemed to be greater than an 80MW facility.
7. A number of the PJM states had to address market pricing of QF facilities in connection with their deregulation orders in the early 2000s.  For example, in New Jersey, the utilities were accorded stranded cost payments for the above-market costs paid to QF facilities resulting in rate-payer charges of several billion dollars.  Consequently, the rate-changes to PURPA, which are intended to better mirror market rates, may not be viewed negatively by rate-payers because they bore the burden of paying QF pricing significantly in excess of the market rate.
8. In the New England ISO (where this firm’s Boston office is located), the Commonwealth of Massachusetts recently put into effect the SMART program that gives solar facilities of 5 MW or less the opportunity to sell both electric energy and renewable energy certificates to the Massachusetts electric utilities based on pricing initially set by a competitive auction process and so small solar facilities in Massachusetts currently have an outlet for a long-term sale of both its energy and RECs, again making the NOPR less impactful.

WHAT COMES NEXT

Comments by interested parties on the proposed rules are due to be filed at FERC within 60 days of the NOPR publication in the federal register.  A proceeding will then take place at FERC to review comments and formulate final changes to PURPA regulations.

Because some sections of the proposed regulations provide options to state regulatory commissions, interested parties must monitor and possibly participate in subsequent proceedings at state regulatory commissions to select among the options available and issue appropriate orders to utilities to incorporate such options in their procedures for interacting with the PURPA Qualifying Facilities in their service territory. The state regulatory proceedings themselves will entail a process that will permit parties an opportunity to comment.

BACKGROUND SUMMARY OF PURPA

PURPA was enacted by Congress in 1978 with the FERC implementing the associated regulations in 1980.  PURPA was part of a package of legislation enacted in response to the oil embargo in the late 1970s and the concerns for shortages of oil and natural gas. Where the electric utilities at that time nation-wide were all vertically integrated (i.e, the utility, with limited exception, owned all of the generation, transmission and distribution facilities and had monopoly franchised service territories where there was no third-party right to generate and sell electricity), PURPA was the first step in permitting non-utility third parties (and to a limited degree non-regulated utility affiliates) to build, own and operate certain classes of electric generation (termed a “Qualifying Facility” or “QF”) that were either: (i) a Qualifying Small Power Producer, which consisted of renewable energy facilities in the form of Solar, Wind, Hydroelectric, Geothermal, Biomass and Waste Fuel, or (ii) Qualifying Cogeneration Facilities that created efficiencies by utilizing waste heat from the electric generation process for a secondary productive use.

Among other things, PURPA mandated utilities to interconnect the QF facilities to the utility system, provide backup power and to enter into contracts to purchase the energy produced by the facilities where such rates for QFs must: (1) be just and reasonable to the electric consumers of the electric utility and in the public interest; (2) not discriminate against qualifying cogenerators or qualifying small power producers;  and (3) not 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 Qualifying Facility, such utility would generate or purchase from another source.” Such pricing is generally referred to in the electric power industry as “avoided cost.”

In addition, the PURPA Regulations currently provide a QF 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 elect to sell pursuant to a contract over a specified term.  In the second half of the 1980s through the middle of the 1990s, the contracts based on avoided costs had taken the form of a long-term fixed price contract that helped ensure a predictable revenue stream that allowed the QF owner to attract financing for the QF.

PURPA also exempted certain sized QFs from certain regulations under the Federal Power Act, the Public Utility Holding Company Act of 1935 and state rate regulation.  A facility currently gains FERC QF status by filing a self-certification form with FERC that describes the necessary characteristics of the facility and its owners.

<sup>1. For those readers not familiar with PURPA, a summary of the existing law and its origin are provided at the back of this Alert.  Terms used but not defined below are defined in the summary.
2. In the NOPR, FERC expressed an underlying objective that QF rates better mirror market prices and set as the objective proposing mechanisms to avoid large deviations from the market price.
3. The Commission acknowledged in the NOPR  that some states already use LMP to establish avoided cost energy rates under our PURPA Regulations.
4. In this setting, utility procurement of energy for its customers has been under a state regulatory agency supervised procurement program utilizing wholesale procurement contracts usually having durations of five years or less and often only one or two years.</sup>