by Emma Foehringer Merchant
October 14, 2019

The Public Utility Regulatory Policies Act is responsible for driving the installation of approximately 15 percent of the 40 gigawatts of utility-scale solar now deployed in the United States. 

Despite the policy's success, energy wonks have long called for a revamp of the 1978 law. Early this month the Federal Energy Regulatory Commission took a step in that direction — filing a notice of proposed rulemaking in the Federal Register that proposes significant changes in PURPA’s implementation.

Congress passed PURPA during an energy crisis. At the time, U.S. oil demand outpaced production, with energy reliability hanging in the balance. Legislatures were looking for a fix. 

Enter PURPA, designed to increase deployment of small renewable generation and combined-heat-and-power facilities, which the law calls co-generation. The legislation was targeted to foster competition by requiring monopoly utilities to purchase electricity from “qualifying facilities,” or QFs, at the avoided cost of getting that power elsewhere. 

FERC now claims the law needs an overhaul, in part because the U.S. electricity system looks radically different than it did at the time of PURPA's passage. That year, fossil fuels accounted for almost 72 quadrillion British thermal units (Btu) of U.S. energy consumption out of a total of about 80 quadrillion Btu. While fossil fuels still made up a significant portion of consumption in 2018, at 81 quadrillion Btu, renewables accounted for 11.5 quadrillion Btu out of a total 101 quadrillion Btu. 

The rise in renewable electricity paired with a dramatic uptick in natural-gas production means PURPA’s qualifying facilities don’t need so much help, according to FERC commissioners that approved the NOPR. 

“The situation with respect to availability of natural gas has changed completely,” the document reads. “Advances in technology and the discovery of significant new natural-gas reserves have resulted in plentiful supplies of relatively inexpensive natural gas. As a result, there no longer is the same need to provide incentives to address shortages of natural gas.”

That sentiment, however, is not universal. In a dissenting opinion, Democratic Commissioner Richard Glick states, “the goals of PURPA — including the need to expand competition and reduce our reliance on fossil fuels — remain relevant now as ever.”

The NOPR comes at a time when an increasing number of states are pursuing ambitious renewables mandates and numerous presidential candidates have made policies on total decarbonization central to their campaigns.   

Glick contends that the NOPR “would effectively gut” the law, which over four decades has provided significant benefit to solar deployment, especially in states with favorable implementation policies. 

The solar industry isn’t thrilled. 

The changes 

In its 137-page proposal, FERC lays out a range of suggestions that would reshape implementation of the law.

The commission proposes decreasing the size of the renewable QFs from which utilities must purchase power to 1 megawatt from 20 megawatts, arguing that larger projects can now bid into competitive wholesale markets.

FERC also wants to loosen PURPA’s “one-mile rule,” which currently counts generators as separate facilities if they’re more than one mile apart from each other. As it stands, the rule may allow owners to game the system, separating projects by just over one mile to qualify them as separate facilities. Under FERC’s proposal, utilities, regulators and “other interested parties” would be able to argue that facilities between one and 10 miles apart should be considered the same facility. 

Perhaps most notably, the NOPR lays out a number of ways to change the calculation of “avoided costs” that utilities pay QFs. The law currently allows facilities to get paid in two ways: using long-term, set-price contracts or compensation based on energy prices at the time of delivery.

Most PURPA projects have favored the long contract model because it provides certainty to developers for financing. But because current market prices for solar undercut those at the beginning of many decades-long PURPA contracts, utilities aren’t thrilled with current mechanisms for calculating avoided costs. 

FERC said it wants to build in flexibility for utilities to determine more “appropriate” energy rates. 

“In particular, consideration of transparent, competitive market prices in appropriate circumstances would help to identify an electric utility’s avoided costs in a simpler, more transparent and more predictable manner,” writes the commission in its NOPR. 

The commission suggests allowing energy rates to be calculated through competitive solicitation, varying energy rates alongside a utility’s avoided costs when energy is delivered and basing rates on projected energy prices throughout a QF's contract. 

Taken together, the suggestions align with many of the “mechanisms by which utilities have usually limited PURPA development,” according to Colin Smith, a senior solar analyst at Wood Mackenzie Power & Renewables. 

Concerns and questions of relevance

Unsurprisingly, then, the solar industry isn’t enthusiastic about the proposal. While the industry has for years offered suggestions on ways to reform PURPA, Katherine Gensler, vice president of regulatory affairs at the Solar Energy Industries Association, cited apprehension about FERC’s most recent spate of ideas.   

“We have a lot of concerns that this package of reforms fails to meet that underlying standard of focusing on competition and of actually promoting QF and co-generation development,” Gensler told Greentech Media. 

Over the years, Gensler said SEIA has filed “hundreds of pages of suggestions with FERC” on possible PURPA changes.   

“Overall, our emphasis has been on ensuring greater competition, greater transparency and greater enforcement of PURPA regimes across the country.”

Federal PURPA guidance could have a big impact. Despite repeated attempts to change PURPA, federal lawmakers have done little to update the law since it was enacted — adding just one significant amendment, in 2005. Instead, states have had wide latitude in determining PURPA’S success or failure. 

That’s meant wide variation in where PURPA projects have thrived. North Carolina, the country’s largest PURPA market, is home to 4.6 gigawatts of functioning or in-development PURPA-related solar capacity. Indiana and Montana have just 100 megawatts. Some states have even less.

And when regulatory changes mean a strong state market bottoms out — North Carolina cut avoided-cost rates in 2017 and lowered the size of projects eligible for QF contracts, hitting big PURPA developers such as Cypress Creek Renewables — it can have an outsize impact. 

“There are pockets where it’s good, but there are many, many ways in which states and utilities are failing to meet their full obligations under the statute,” said Gensler. “That intent to thwart QF development by making PURPA harder [to qualify for] works. That certainly is not an outcome that we view as favorable.” 

But there are also questions of PURPA’s current relevance in the overall solar market. As FERC correctly points out in its NOPR, most renewable resources operating today don’t rely on PURPA.

The portion of utility-scale capacity additions tied to PURPA has fluctuated, from 24 percent in 2017 and 16 percent in 2016 to 12 percent in 2018. At the same time, WoodMac's Smith says many developers view PURPA as the “go-to mechanism” to secure project payments after a power-purchase agreement expires.

The politics 

The NOPR entered this world amid unusual dynamics at FERC. Though the commission traditionally maintains a balance of bipartisan members, it’s currently lopsided, with two Republicans and one Democrat. That number still builds to the three-member quorum needed to make decisions, but it grants conservative commissioners an edge in voting. 

Glick’s dissent indicates that the Democratic commissioner not only disagrees with his colleagues' suggestions for reform, but he also disputes the fundamental idea that FERC has the jurisdictional power to change PURPA’s implementation. 

“A policy debate about the continuing relevance of PURPA — which, make no mistake, is what this NOPR is really about — is an issue for Congress to resolve,” Glick writes. “Resolving these sorts of questions by regulatory edict rather than congressional legislation is neither a durable nor desirable approach for developing energy policy.” 

Going further, Glick argues that the proposal fails to fulfill the commission’s “basic responsibilities under the law.” 

Glick’s rebuke doesn’t encompass the entirety of the NOPR, though. He agrees that PURPA needs revision. But Glick argues those changes should foster more competition, not less. 

WoodMac’s Smith, who analyzes dynamics in the utility-scale solar market, agrees that “overall, absolutely PURPA needs to be updated.” Though Smith says there’s disagreement on what PURPA’s purpose should be in a modern electricity system, he contends FERC should play a role in outlining it.   

“If it’s Congress’ role to make the decision on what [PURPA’s] purpose should be,” he said, “it should be FERC’s goal to guide Congress.”

In his dissent, Glick made his perspective on that purpose clear: “Our basic responsibilities under PURPA are threefold: 1) to encourage the development of qualifying facilities; 2) to prevent discrimination against QFs by incumbent utilities; and 3) to ensure that the resulting rates paid by electricity customers remain just and reasonable and in the public interest.” 

Glick also highlights the continued need to reduce reliance on fossil fuels. 

In a political environment devoid of federal climate leadership, SEIA’s Gensler said PURPA remains an important mechanism to meet state-level climate and energy goals.

“In the march toward decarbonization, resource decisions for electricity continue to be made at the state level. PURPA remains a tool or a pathway in order to meet those goals,” said Gensler. “It continues to be an important part of the puzzle, recognizing that there are other puzzle pieces here that drive resource decisions both for utilities and for purchasing customers.” 

Comments on the NOPR are due December 3.