Trump’s energy reform winds could blow over PURPA

Published on July 05, 2017 by Kim Riley


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Glenn Benson

Utilities in Montana, North Carolina, Oregon and Utah, among others across the United States, want the Public Utilities Regulatory Policies Act (PURPA) reformed and are harnessing their powers to get it done.

The main vehicles to change PURPA would be the Federal Energy Regulatory Commission (FERC), Congress or state public service commissions, said Glenn Benson, a partner with Davis Wright Tremaine LLP’s renewable energy practice.

“Regarding Congress, I think it is difficult to predict what will happen in this Trump administration, which is likely to go after a PURPA repeal if they do get to an energy focus. It’s seen as a subsidy and so they may go after it aggressively, but it’s hard to see how it will play out on Capitol Hill. But I’d be nervous about it,” Benson said during last week’s AEE-sponsored webinar on the topic.

Benson added that while federal legislators have been “very quiet under the Trump administration thus far” on PURPA and there is currently no bill in sight, “I wouldn’t be surprised if the administration tries in the years ahead to get PURPA reformed or repealed,” he said.

And that would be fine with the utilities.

PURPA, passed in 1978 in response to the nation’s energy crisis, was designed to promote energy conservation and increased use of domestic energy resources. PURPA got amended significantly by the 2005 Energy Policy Act during the Carter administration, Benson said.

Most notably, the law created a new class of power producers referred to as qualifying facilities (QFs), which receive special rates and regulatory treatment under PURPA, he said.

Specifically, QFs include small power production facilities of 80 MW or less fueled by solar, wind, biomass, geothermal, waste or hydro. They also include cogeneration facilities installed at manufacturing sites, refineries, paper mills and other industrial facilities that produce both electric and thermal energy used for industrial, commercial or cooling purposes—“in which the surplus is sold into the marketplace,” said Benson.

There are several advantages for having QF status, Benson said, the primary one being that a QF has a ‘put’ right giving it the right to sell power to any electric utility of its choice: municipals, rural coops, water districts and federal agencies selling electric energy, for example.

“This is a big deal,” Benson said. “It’s a given right to sell power to an electric utility no matter who it is and they couldn’t say no.”

Another QF status advantage is that QFs receive a utility’s avoided cost for capacity and/or energy. From the utilities’ perspective, they are required to buy the QF-produced energy (regardless of need) if it’s developed at a cost equal or below what a utility would pay for a traditional power plant—a.k.a. a utility’s avoided cost.

Today, PURPA—via FERC regs—has allowed QFs to enter into legally enforceable obligations (LEOs) at the avoided-cost calculated, at the QFs election, at the time entered into or at the time of delivery, Benson explained. Fixed avoided-cost rates end up exceeding market prices, Benson said, yet the long-term LEOs have allowed QF projects to obtain financing.

That’s largely why PURPA is seen by various industry observers as the catalyst in the development boon of utility-scale solar projects as utility solar developers use the law to leverage favorable contract lengths, rates and other changes they say are needed to finance their projects.

Meanwhile, the utilities think they’re getting shafted by an outdated law.

PURPA pushback
The utilities’ arguments against QFs mostly come down to cost and reliability, Benson said.

PURPA contracts can cause operating inefficiencies and reliability issues for the host utility, which has no control over where the QFs are sited or integrated into its system, for example. And they can increase the cost of power for consumers, he said.

Additionally, many QFs are “undispatchable” and might lead to over-generation conditions or inefficient use of baseload units that are forced to cut back operations to accommodate unscheduled QF purchases, Benson added.

Other arguments include the fact that PURPA contracts were not intended to supplant incumbent generation and long-term fixed prices turn out to be too high, he said.

Going forward, utilities and state commissions argue that there should be no minimum term for LEOs, however if there is such a term length, “the avoided cost rate should, at a minimum, be re-determined annually,” Benson said.

The minimum contract length issue includes proposals that range from zero to at least 25 years, he said, and are important because of the issue’s possible impact on financeability of a project and whether PURPA is intended to promote financeability.

For instance, a developer isn’t likely to get financing if he’s only got an LEO for a year, Benson said.
Reforms at the state level show there’s been a tendency lately toward shortening LEO terms: Idaho went from 20 years to two years and Utah dropped from 20 years to 15 years, for example. Wyoming, however, rejected PacifiCorp’s proposal to go from 20 years to three years, although Benson expects the utility to come back soon and give it another try.

FERC, too, is considering whether to adopt a minimum term and/or maximum term for LEOs, among other issues, Benson said.

Overall, he added, the industry is likely to see some FERC action, though he’s unsure how broad it will be and any PURPA reform will likely fall to Congress.

“FERC may provide more guidance to states on avoided costs. They sense maybe they need to put the brakes on QFs in states where there’s been a lot of growth,” Benson said.