The Federal Energy Regulatory Commission has proposed big changes to the rules of the Public Utilities Regulatory Policies Act (PURPA), a move that could further erode the declining, state-by-state market opportunities for renewable energy projects developed under the 1978 federal law.
FERC’s new notice of proposed rulemaking, or NOPR, would constitute the biggest changes to PURPA implementation since the 2005 Energy Policy Act. It was passed at FERC's meeting last Thursday, the first since Democrat Cheryl LaFleur left the agency, leaving it with a two-to-one Republican majority.
Republican Chairman Neil Chatterjee and Commissioner Bernard McNamee voted for the measure, overcoming the objections of Democrat Richard Glick, who said at Thursday’s meeting that the NOPR would “effectively gut” PURPA. Glick’s dissent vote came with a lengthy and strongly worded statement, highlighting the changes he said could threaten renewable energy’s growth.
Those include doing away with a requirement for utilities to offer long-term fixed prices for qualifying facilities (QFs). These fixed-price contracts have “played an essential role in encouraging QF development,” and doing away with them “will make it more difficult — or in some cases impossible — for QFs to obtain financing,” Glick wrote.
Under PURPA, utilities in states without wholesale energy markets must contract with QFs, if they can produce electricity at less than the utility’s avoided cost of generation. Solar power’s dramatic cost declines over the past decade have put more and more of these intermountain West and Southeast U.S. states in the money for this type of calculation, if they can qualify under the law’s state-by-state implementations.
This led to a boom in PURPA-driven solar development over the past decade, peaking in 2016 when it represented nearly one-third of U.S. utility-scale solar projects, according to Colin Smith, senior solar analyst at Wood Mackenzie Power & Renewables. That included Utah, where more than a gigawatt of solar came online, and North Carolina, which took the top ranking in state solar scoreboards for some time due to PURPA-related development.
But PURPA also led to overcrowding of interconnection queues, as well as a consistent set of legal challenges to the state-by-state regulations created to implement the 41-year-old law. For example, the term “avoided cost” has been determined in a different way by different states, even though it’s a fundamental concept contained in a federal law.
“Consequently, we’ve seen varying interpretations of the law and variations in the challenges of how PURPA is being implemented,” Smith said.
Utilities and developers have struggled on how to clear the backlog of projects, in terms of choosing the most cost-effective and scheduling new projects against grid interconnection constraints.
“Typically the developers and utilities have to find some out-of-court settlement — they have to pick a rate or something, to determine how they’re going to bring these projects online," Smith said.
In some cases, that’s led to a mutually acceptable solution. Last week, Michigan utility Consumers Energy reached a settlement with state solar industry groups to use PURPA to develop hundreds of megawatts of new solar.
But in most cases, it has been a more contentious process. In that light, FERC’s NOPR last week “appears to be the first real attempt to overhaul how PURPA is being used across the country,” Smith said.
Muted impact on overall market
While Commissioner Glick’s concerns over the effect of FERC’s proposed changes to PURPA have been echoed by industry analysts, Smith noted that state-by-state actions have already significantly reduced PURPA’s attractiveness as an avenue for U.S. solar developers.
PURPA is driving less than 5 percent of solar development today, Smith said, as states have placed restrictions on eligible projects.
Many states have changed the methods by which avoided-cost rates are calculated to reduce the difference between current solar rates, leading to lower payments, he said. They’ve also shortened the length of contracts and reduced the maximum size of projects eligible under PURPA, reducing the bankability of solar projects.
North Carolina is the prime case for these changes. PURPA helped drive North Carolina to become the nation’s second-largest solar market earlier this decade. But in 2017, the state legislature passed a bill that lowered the size of projects eligible for PURPA from 5 megawatts to 1 megawatt and shortened their contracts from 15 to 10 years, while state regulators lowered the avoided cost rates.
Solar advocates warned these changes would have a “suppressing effect” on the market, a prediction that has since come to pass for PURPA-driven projects. One of the largest casualties of this market shift was California-based Cypress Creek, which “built its empire on 5-megawatt projects in North Carolina,” but has since laid off about 20 percent of its workforce and restructured its portfolio away from PURPA markets.
Related research: 'U.S. Solar Market Insight' (Wood Mackenzie)