Changes to the way a 40-year-old federal law is implemented could significantly benefit vertically-integrated utilities in non-competitive markets, while harming small-scale solar developers, stakeholders told Utility Dive.

“In my view, this recent FERC order is mostly in line with the changes that the electric utilities requested,” Metin Celebi, a principal at Brattle, told Utility Dive.”However, the impact on the renewable developers will really depend on how each particular state will choose among the options provided in the FERC order.”

Critics say states’ ability to set prices paid to small solar at varying levels with no guaranteed long-term contract could allow some to set policies that harm independent power producers.

“This ultimately harms renewable energy generators because they lose [these] long-term fixed price contracts and other benefits they had under the old rules,” Ari Peskoe, director of the Electricity Law Initiative at the Harvard Law School Environmental and Energy Law Program, told Utility Dive.

Critical for solar, opposed by utilities

The Public Utility Regulatory Policies Act (PURPA) was originally passed in 1978, part of a broader effort to diversify the U.S. energy mix and reduce reliance on foreign supply, in part by encouraging the deployment of small, distributed energy generators, such as small solar and hydro facilities. Utilities have long protested the law, which they say overcompensates small power suppliers for capacity not needed by the utilities’ customers, leaving ratepayers on the hook for extra power costs. But solar advocates maintain the law has been critical to the growth of small solar, and remains particularly critical for independent power producers that operate outside a competitive market.

The Federal Energy Regulatory Commission’s July final rule allows states to implement PURPA in a way that eliminates fixed-price contracts, making contract lengths and the price a power supplier is paid uncertain, which experts say could harm the renewables industry and disproportionately benefit vertically integrated utilities in non-competitive markets. Utilities disagree with this characterization.

“FERC’s PURPA regulations were modernized to benefit one key stakeholder group, customers,” Adam Benshoff, executive director for regulatory affairs at investor-owned utility trade group Edison Electric Institute, told Utility Dive in an email. Utilities must still purchase power produced by qualifying facilities, he added. 

“The utilities that benefit most from weakening PURPA are these vertically integrated utilities that are outside of the [regional transmission organization (RTO)] markets and so, therefore, already have the most control over power supply in their regions.”

Ari Peskoe

Director, Electricity Law Initiative, Harvard Law School Environmental and Energy Law Program

But others argue the July rule undermines the very foundation of PURPA, and that those impacts will be most felt in regions without competitive markets.

“The utilities that benefit most from weakening PURPA are these vertically integrated utilities that are outside of the [regional transmission organization (RTO)] markets and so, therefore, already have the most control over power supply in their regions,” said Peskoe. “One reason why Congress enacted PURPA 40 plus years ago … was to neutralize some of the power that these vertically integrated utilities have, to require them to buy energy from these qualifying facilities because otherwise they would not have bought energy from their competitors.”

But while Peskoe sees potential problems with FERC’s updated PURPA regulations, some state regulators say the new rules will bring clarity and certainty to states in how they implement PURPA moving forward.

“I couldn’t have been happier with the outcome,” Idaho Public Utilities Commission President Paul Kjellander told Utility Dive. The change gives “states in general … the flexibility we need to make sure that as we bring on more resources, and we will be bringing on more resources, that customers are held harmless with regards to how those resources are coming on.”

Benefits to Idaho and beyond

Idaho has a “pretty tormented history with PURPA,” Idaho PUC Commissioner Kristine Raper told an audience at the 2019 National Association of Regulatory Utility Commissioners (NARUC) conference last fall. Observers say it’s likely the only state to have been sued by FERC for failing to implement the statute consistent with federal law. Regulators failed to honor a contract between wind developer Murphy Flat Power and the Idaho Power Company, prompting the federal commission to sue in 2012.

“The good news about this rule is that it kind of puts a lot of that back on the bench and makes it easier to forget,” said Kjellander, adding that the dispute was long settled. “But to say that we have had an interesting history with PURPA — we have.” 

PURPA was an “active and useful tool” for bringing renewable energy into the state until the mid-2000s, “but there was a shift … where we saw lot of disaggregation of some larger-scale projects into smaller projects into what we considered to be a gaming of the system,” he said.

The rule was intended to help small developers, but in the Idaho commission’s view was ultimately allowing larger developers to bring resources online before that capacity was needed “at prices that were well beyond really what would have been considered reasonable even at the time,” he said.

“The size of those projects, that does matter. And that [threshold change], I think, is a real plus and some relief … for utilities.”

Paul Kjellander

President, Idaho Public Utilities Commission

One adjustment FERC made that was supported even by the lone “nay” vote on the order finalizing the rule, Commissioner Richard Glick, was to adjust the “one mile rule” to avoid such aggregation. And that change was “key” for Idaho, said Kjellander.

But a more controversial change made by the federal commission was to allow states to set rates paid to QFs at the wholesale avoided cost rate, rather than at a fixed price. That change in particular is “pretty valuable,” Kjellander said as well as the broader “discretion” for regulators in enforcing other aspects of a QF’s legally enforced obligation to get compensated by utilities for the power they provide.

Another important change was lowering the QF threshold from 20 MW to 5 MW — gains in energy efficiency allow megawatts to serve a lot more customers than they used to, he said. “That [adjustment] recognizes that a lot has happened and changed in the marketplace,” said Kjellander. “The size of those projects, that does matter. And that [threshold change], I think, is a real plus and some relief … for utilities.”

One critical pitfall the solar industry and other stakeholders see in FERC’s changes is the potential death knell for developers and independent power producers in non-competitive markets dominated by a monopoly utility.

“While PURPA was passed into law decades ago, where a state has chosen not to join an Independent System Operator/Regional Transmission Operator (“ISO/RTO”) or where a utility continues to operate as a vertically integrated monopoly and/or … does not offer open access on its distribution system, the landscape for independent power producers remains largely the same as it was forty years ago,” the Solar Energy Industries Association wrote in its comments opposing FERC’s changes. “In these states, millions of electric consumers have largely been denied the benefits of competition and open markets. In these regions, PURPA remains necessary.”

“I don’t have a crystal ball that tells me what the future is going to look like. I mean, the closest thing I have is my rear view mirror.”

Paul Kjellander

President, Idaho Public Utilities Commission

Oregon made a similar argument — while acknowledging the state “has been aware of the need to reform and modernize the implementation of PURPA to fit the law to today’s energy landscape,” the Public Utility Commission noted in comments that “[i]n Oregon and much of the West, resource development generally occurs through” long-term power purchase agreements through utilities. Those procurements are not done based on “as-available energy prices, raising questions about the accuracy of the assumptions supporting the Commission’s proposal in many areas of the West,” the Oregon PUC wrote. 

Oregon commissioners are “carefully reviewing FERC’s rule to determine if it provides new opportunities to encourage a diverse array of sustainable energy sources, maintain just and reasonable rates, facilitate an efficient and consistent regulatory process, and achieve a durable regulatory outcome in our efforts to modernize PURPA,” a PUC spokesperson told Utility Dive in an email.

Potential pitfalls for renewable energy

The passage of the Energy Policy Act in 2005 limits utility obligations to purchase power from QFs in organized regional electricity markets, a change in law that was implemented by FERC with a rulemaking in 2006. But Congress retained such obligations in non-competitive markets, which SEIA argues indicates Congress’ “continued commitment to encouraging the development of” small distributed resources.

Renewable energy “is thriving” and much of today’s renewable energy procurement is done outside PURPA, according to FERC Chair Neil Chatterjee. Kjellander agreed.

“PURPA doesn’t necessarily fit in neatly … like it used to, as one of the only ways in which you brought on renewables,” he said. “That’s just not the case anymore. There [are] so many other options and opportunities to bring on renewable energy resources at costs that make more sense to the customers at the end of the line that end up paying for all of it.”

It’s hard to say how the rule will impact renewable energy markets in states like Idaho, but regulators have options for mitigating that harm, he said. For example, in Washington, regulators are exploring potentially rate-basing a portion of power purchase agreements made between independent power producers and utilities to alleviate some of those concerns. Other programs will likely emerge, said Kjellander.

“I don’t have a crystal ball that tells me what the future is going to look like. I mean, the closest thing I have is my rear view mirror,” he said.

“I think that there [are] some opportunities … for us as regulators to take a fresh look at a few things and see how that will all unfold. But … I think certainly to some of the potential opportunities for solar development, renewable energy development through request for proposals and other opportunities like that are … for the present going to make themselves more available.”

Celebi agreed that programs encouraging competitive procurement could be good for renewable developers in a given state. “But of course, if a state goes the other way, for example, choosing the variable energy rate option or as-available kind of energy rates, depending on how the contracts are formulated, that could be a disadvantage for the developers compared to the status quo,” said Celebi. However, “status quo” has not always been conducive to PURPA developers, he said, as under previous rules states could still set short fixed-price contracts, which can be unattractive for developers.

In Montana, for example, a commissioner was caught on tape in a hearing room in 2017 acknowledging that regulator-approved cuts to compensation rates and contract lengths for QFs would likely kill small solar development in the state. The Montana Public Service Commission did not respond to multiple interview requests, but supported FERC’s changes in its filed comments. 

Much of the tension over pricing has to do with utilities’ reticence to bring on power that is not theirs, and fights over PURPA pricing often have more to do with a utility overbuilding capacity than the uncompetitive nature of PURPA contracts themselves, according to Peskoe. 

Benshoff argues state commissioners in vertically-integrated states monitor capacity obligations “to ensure that there is sufficient capacity to provide all customers with a reliable and secure supply of electricity. The unplanned PURPA builds historically have complicated this process to the detriment of customers who then must pay for all of the commission-approved assets and the higher-cost power from these unplanned facilities.”

But “what the utility objects to is competition … For 40 years, since PURPA was enacted, they said we don’t need this energy,” Peskoe said. “That’s been their refrain for 40 years. And that’s true to a certain extent, but it also highlights sort of poor planning by the utility.”

Utilities may have already overbuilt their systems or put in resources that are more expensive than the PURPA resources coming in, he said. 

“It’s often not a question of whether or not the energy from the QF is really cheaper. It often is. It’s just that … the utility has already overbuilt its system and failed to anticipate the fact that the QF PURPA rates were going to be so attractive to QF developers to come in and it didn’t account for that in its planning.”

The larger issue surrounding the risk to renewable energy is financeability, which remains a a key concern left unaddressed by FERC, according to Peskoe. Although state regulators do have “tools in their toolbox” to promote competition, federal rules no longer require utilities to offer long-term contracts with fixed energy prices, Peskoe said. 

“It’s hard to say that FERC’s rules encourage the development of QFs if they don’t enable financing of QFs,” he said. “And I think this really is a reversal on financeability issue in a way that I think is contrary to the law.”