Will FERC's New PURPA Regulations Have a Chilling Effect on Renewable Energy Development?

The Public Utility Regulatory Policies Act of 1978 ("PURPA") was enacted during the height of the energy crisis and was intended to reduce the country's dependence on oil and natural gas. Among its provisions is a requirement that electric utilities purchase energy and capacity generated by wind, solar, and other renewable generation technologies from so-called "qualifying facilities" ("QFs") at a rate less than the utility's "avoided cost" (i.e., the cost of its own generation that will be avoided if other generation comes on line). Seemingly overnight, in certain regions of the country, PURPA transitioned from being an afterthought to a key driver in renewable project development. Dramatic declines in utility-scale wind and solar costs over the last decade have permitted developers to offer rates below the utility's avoided cost, allowing them to secure long-term offtake contracts at fixed rates. These long-term offtake contracts proved critical to developers in securing financing for their renewable projects, particularly outside of the major regional energy markets and in states without renewable portfolio standards.

But while PURPA was a boon for renewable energy developers, utilities who were forced to buy power—rather than to build and own their own generation or sign power purchase agreements after competitive solicitations—began to criticize the "gaming" of PURPA by well-financed developers, such as those who use the so-called "one-mile rule" to build multiple solar farms just over one mile apart in order to evade regulatory size limitations on their PURPA-qualifying projects. Increasingly, utilities argued in state regulatory proceedings that energy procured through PURPA was raising rates for ratepayers and circumventing the utilities' resource planning and procurement processes. Several state commissions and legislatures responded by revising their states' interpretation of PURPA. Certain states passed reforms that effectively make it more difficult for QF developers to secure financing, such as shorter contract lengths, reduced maximum size limitations, and differing methods of calculating avoided cost, resulting in lower rates recovered by developers under offtake contracts. North Carolina, for example, passed a law that required facilities larger than one megawatt ("MW") to undergo competitive solicitation and limited offtake contracts to 10 years.

The Federal Energy Regulatory Commission ("FERC") recently entered the fray in this long-running fight between utilities and project developers by proposing to "modernize" its PURPA regulations. In its recent Notice of Proposed Rulemaking ("NOPR"), FERC set out a series of proposed reforms, many of which offer additional flexibility to state commissions as they implement PURPA. In determining the rates utilities are required to pay for energy generated by QFs, FERC proposed to permit states to base rates on the utility's avoided cost at the time of delivery or on projected energy prices at the time of delivery, and to allow states to set energy and capacity rates in competitive solicitations. FERC also proposed to require that states develop objective and reasonable criteria assessing a QF's commercial viability and financial commitment to construction before the QF is deemed to have a "legally enforceable obligation," which determines the date on which a QF can elect to have its avoided cost rate determined. The NOPR also offered new regulations on the one-mile rule that would permit third parties to challenge whether adjacent wind and solar facilities between one and 10 miles apart are a single facility for purposes of implementing size restrictions. FERC also proposed to provide utilities a rebuttable presumption that QFs as small as one MW (rather than 20 MW) have nondiscriminatory access to markets, which ultimately would require QFs to sell energy directly in regional markets rather than under a long-term contract with their host utilities.

In the face of these sweeping changes, however, FERC Commissioner Richard Glick issued a strident dissent, claiming that if adopted the NOPR would make it difficult (if not impossible) for QFs to obtain project financing. Further, Glick accused his fellow commissioners of "using the success of competition in certain parts of the country" (i.e., those with robust wholesale energy markets) "as a reason to scale back PURPA throughout the country" (i.e., in those regions without robust wholesale energy markets). In short, Glick opined that the NOPR "would effectively gut" PURPA and usurp the role of Congress in setting national energy policy.

What effect these proposals will ultimately have on PURPA and on renewable energy development remains to be seen at this point, as FERC's modernizing proposals are just that—proposals. FERC will accept comments on the NOPR until December 3, 2019, and may revise its proposals in light of such feedback. Thereafter, the new regulations will be subject to judicial review, and states will revise and apply their own rules. Nevertheless, if finalized and if Commissioner Glick's predictions come to pass, a niche but important means through which developers have secured offtake contracts and financed renewable energy projects could be eliminated.

Continued Uncertainty for Domestic, Commercial-Scale Offshore Wind

Recent demands by the U.S. Department of the Interior are delaying agency approval of the first commercial-scale offshore wind farm in the United States. The project under review is the Vineyard Wind project, an 800-megawatt wind farm off the shore of Massachusetts ("Vineyard Project"). While Europe has been leading the offshore wind charge with more than 105 wind farms (with capacity sizes ranging up to 650 megawatts) and a total of about 18,500 megawatts online, the offshore wind industry in the United States is a nascent industry, with only one 30-megawatt operational offshore wind farm, the Block Island Wind Farm. The sheer magnitude of the Vineyard Project, which is more than 26 times the capacity of the Block Island Wind Farm, makes it a monumental and groundbreaking project in the United States.

The permitting and approval process for offshore wind in the United States is a multistep, multiagency process that spans over 30 different agencies at the federal, state, and local levels. At the federal level, approval must be obtained by the U.S. Department of the Interior's Bureau of Ocean Energy Management ("BOEM"), which is tasked with managing the development of offshore renewable energy in federal waters. The BOEM's project approval process requires an environmental review with an opportunity for public comment. Although the BOEM was initially expected to issue an environmental impact study for the Vineyard Project in July 2019, that timeline has been extended to late 2019 or early 2020 in response to demands from stakeholders and other federal agencies for a more comprehensive supplemental environmental impact study. The driving concern behind the supplemental environmental impact study is the cumulative effect the Vineyard Project and five adjacent wind farms would have on the nearby commercial fishing industry.

This delayed timeline, however, has not dissuaded the developers of the Vineyard Project from moving forward with the development of the $2.8 billion dollar project. Although they initially planned to start construction by the end of 2019 to take advantage of production tax credits, after the BOEM's determination that a supplemental environmental impact study was necessary, they determined simply to revise the project's timeline. In addition, they doubled down on their offshore wind gamble by submitting proposals to Massachusetts' electric distribution companies for Vineyard Wind 2, an offshore wind farm with a minimum capacity of 400 megawatts.

Because many states have recently issued commercial-scale offshore wind solicitations in an effort to meet aggressive clean energy goals (see "All Eyes on Offshore Wind—Will It Become a Reality in the United States?," The Climate Report, Summer 2018), they are also invested in the outcome of the BOEM's determination with respect to the Vineyard Project. Accordingly, governors of numerous coastal states including Massachusetts, Connecticut, Maine, New Hampshire, and Virginia have urged the BOEM to render its decision on the Vineyard Project approval by no later than March 2020, as further delay will have a negative impact not only on the Vineyard Project itself, but also on offshore wind development in the United States generally.

Thus, the federal, state, and local approval and permitting process for offshore wind here in the United States is proving to be not only lengthy, but also unpredictable. The Vineyard Project's approval process and unprecedented scale are laying the groundwork for numerous projects that will come after it. Now, developers, state representatives, and stakeholders must stand by to see if commercial-scale offshore wind can surpass these regulatory hurdles and become a thriving industry in the United States.