The law has been under fire for much of its 40-year history, but changes proposed in November could be the most significant yet.
A new bill in Congress could take the teeth out of the Public Utility Regulatory Policies Act, delivering a blow to some renewable energy projects.
For utilities, some of which have opposed PURPA since it became law in 1978, it could be a final victory in a decades-old fight that pitted utilities against independent generators.
PURPA has been a key driver in the growth of alternative and renewable energy. It also served as a wedge in opening the door to electric utility deregulation. PURPA’s importance has faded since deregulation, but in the past decade or so, it has found new relevance in states outside of the deregulation sphere.
In states such as Idaho, Montana and North Carolina, PURPA has been key to the growth of renewable energy.
Utilities in those states are still fighting the PURPA battles of the past 40 years and, with the new bill in Congress, they could be poised to win. But their victory could also be a loss for renewable energy project developers in those states, where as many as 14 GW of renewable energy projects have been proposed.
“The underlying goals and intent of PURPA may no longer align with market fundamentals.”
In non-RTO states where PURPA still has the most impact, utilities have complained for years about the high costs the law imposes on them and their ratepayers. The reforms proposed in the PURPA Modernization Act (HR 4476), sponsored by Rep. Tim Walberg (R-Mich.) would address some of those concerns, but it would also water down what most analysts consider the heart of PURPA, the mandatory purchase obligation.
PURPA put exemption
Handicapping Congress is always difficult, but Walberg’s bill could do well in the current political climate. Even if it does not become law, there are regulatory efforts under way that also take aim at PURPA.
It could be that PURPA’s day is done, that it has outlived its usefulness.“The underlying goals and intent of PURPA may no longer align with market fundamentals,” Timothy Fox, a vice president with ClearView Energy Partners, told Utility Dive.
On the other hand, “If it isn’t needed, why are people using it,” Jerry Bloom, senior counsel with Winston & Strawn, told Utility Dive.
The main impact to any changes to PURPA would be in non-RTO states, which haven’t been subject to previous changes to the law’s requirements as with deregulated states. The Energy Policy Act of 2005 revised PURPA by exempting utilities from the law’s mandatory purchase obligation, what is often called “the PURPA put,” if they had access to a competitive wholesale market.
When PURPA was written, there were no competitive power markets. The local utility was the only game in town. In order to introduce competition in the power market, PURPA forced utilities to buy power from “qualifying facilities,” or QFs, that met criteria, such as technology and size thresholds, spelled out in the law.
After the Energy Policy Act of 2005, wide swaths of the country that instituted RTOs and independent system operators, including PJM Interconnection states, New England, New York and California, became exempt from the PURPA put.
But in non-RTO states such as Idaho, Utah, Wyoming and Montana, PURPA remained essential for renewable energy project developers, who were also attracted to PURPA’s rates for QFs, known as avoided costs and set by individual states.
The bill, now before the Energy Subcommittee of the House Energy and Commerce Committee, would allow states to waive the purchase obligation, if a utility can show it has no need for capacity. That exemption could become widespread since electricity demand growth is flat in many states.
Walberg’s bill would lower the threshold for QFs from 20 MW to 2.5 MW, forcing larger QFs to compete in wholesale markets. The bill would also revise the “one mile rule” that is used to determine the boundaries of a single QF.
PURPA critics say the one mile rule was abused by developers who followed the letter of the law but in reality were spreading out projects that were in fact owned by the same entity.
PURPA’s draw for developers was the avoided cost rates paid to QFs. Developers in many states found avoided cost rates to be lucrative because they had not been revised to reflect falling technology costs and the effect of low natural gas prices. The contract terms were also attractive, lasting for up to 20 years in a situation where many utilities were reluctant to lock in long-term rates in a falling cost environment.
In some states, as the number of PURPA projects grew, utilities began to feel the burden of those QF payments, and some developers were able to lock in avoided costs, despite the falling cost of renewable energy.
In that sense, renewable developers “were the victim of their own success,” Ken Rose, senior fellow at the Institute of Public Utilities at Michigan State University, told Utility Dive.
There has been pushback in many states where PURPA is still a factor. In November, Michigan regulators revised the state’s avoided cost, tying it to the cost of generating power from a gas-fired plant, instead of a coal plant. In Montana, environmental advocates are suing the state over the public service commission’s decision to cut avoided costs to $31/MWh from $66/MWh while also cutting the length of contracts to 15 years from 25 years. In 2015, Idaho reduced the term of QF contracts to two years from 20 years.
In January, North Carolina passed a solar bill (HB 589) that revised how the state handles PURPA. Under the law, a utility would have to make capacity payments to a QF when a utility integrated resource plan identifies a need for capacity. The law also reduces to 1 MW, from 5 MW, the size of QFs entitled to standard contracts. Projects larger than 1 MW would have to compete for contracts through a competitive solicitation.
But while individual states have the ability to make PURPA’s provisions more restrictive, a federal law would have much wider effect by reducing the number of facilities that could claim QF status and exempting many utilities from the PURPA put.
How much is at stake?
There are about 90,000 MW of operating QFs, according to a presentation prepared by Robert Mudge, a principal at The Brattle Group. Most of that existing capacity, about 70,000 MW, is thermal, in RTO regions and plateaued as states began deregulating. The growth in QFs since deregulation — the remaining 20,000 MW of existing QF capacity — has mostly been in wind and solar projects in non-RTO states.
There are another 24,000 MW of QFs under development, most of which is renewable energy — about 75% solar power. Somewhat more than 14,000 MW of that total is in non-RTO states. Without the backing of the PURPA put, many of the developers of those projects might not be able to the secure power purchase contracts at the rates they deem necessary to move their projects forward.
“If PURPA’s mandatory purchase obligation was repealed, [the Solar Energy Industries Association] believes that the regulatory environment would then allow a reversion to the monopolistic and oligopolistic practices that governed a non-competitive market for wholesale electricity – just as they did before 1978.”
North Carolina leads in solar QF projects, with just over 6,000 MW under development, followed by South Carolina, Utah and Oregon, with more than 2,300 MW under development each, and then Colorado and Montana with 1,400 MW and 1,300 MW under development, respectively, according to Brattle.
For many QFs, competitive markets do not provide a viable option, Bloom said. And for smaller QFs, it can be too expensive to participate in an RTO.
“For relatively large renewable power sources, losing the PURPA put wouldn’t mean a lot since they could still possibly be competitive in the wholesale market, but some of those lucrative rates for QFs might go away,” Rose said.
It is a different story for smaller QFs, though. “It is difficult for them to deal directly with an RTO, and now with low wholesale prices, they would likely just shut down,” if they were forced into the wholesale market Rose said. “In non-RTO areas, they would have no one to sell to unless the utility agrees to deal with them; basically, [it would be] the pre-PURPA days.” That, said Rose, could result in the loss of small hydro power units and other small renewable operators.
But it’s not just new projects that would be affected. As contracts with existing QFs expire, they might not be able to enter into new contracts at viable rates, Bloom noted.
That happened with cogeneration plants in California. “The market collapsed,” as utilities forced cogeneration QFs with expiring contracts into the wholesale market. Cogeneration facilities could be the biggest loser of PURPA reform, Bloom said, because “there is no market for those electrons.”
“If PURPA’s mandatory purchase obligation was repealed, [the Solar Energy Industries Association] believes that the regulatory environment would then allow a reversion to the monopolistic and oligopolistic practices that governed a non-competitive market for wholesale electricity – just as they did before 1978,” Todd Glass, an attorney with Wilson Sonsini Goodrich & Rosati, wrote to the Energy Subcommittee in November as a follow-up to testimony he gave at a Sept. 6 hearing on behalf of the Solar Energy Industries Association.
Weighing the prospects
If Walberg’s bill passes, it could cut at the heart of PURPA, but other important aspects of PURPA would still be intact, Rose said. For instance, PURPA requires utilities to sell QFs backup power at non-discriminatory rates. It also requires utilities to interconnect with QFs. But the bill still has a long way to go before becoming law.
“We expect the House Energy and Commerce Subcommittee on Energy to approve the bill largely along party lines, and send it to the House,” Clearview’s Fox said.
Fox said the House could approve the bill this spring, but “the Senate would be unlikely to vote on the standalone bill.” The Senate might be willing to consider PURPA reform within a broader energy package, but “efforts to move such a bill have failed to garner sufficient interest to secure scarce floor time for consideration,” Fox said, adding, “time on the legislative calendar gets incrementally dearer as the November midterms approach.”
The House is not the only venue in which PURPA is being challenged. In late December, the National Association of Regulatory Utility Commissioners sent a letter to the Federal Energy Regulatory Commission calling for a move away from administratively determined avoided costs and encouraging the use of competitive solicitations for PURPA compliance.
In an address to the Energy Bar Association last year, FERC Commissioner Neil Chatterjee listed PURPA as one of the items on the commission’s agenda. Today’s energy landscape is “fundamentally different” than the landscape when PURPA was passed, Chatterjee said. “As we all know, none of those things are true today,” he said, referring to the the threat of oil embargoes, rising oil prices, dwindling oil reserves and rising electricity prices in the 1970s that gave rise to PURPA. That is “why PURPA so often feels like it’s out of sync with our modern energy landscape.”