U.S. power industry stakeholders were sharply divided on the Federal Energy Regulatory Commission's proposal to relax its rules implementing the Public Utility Regulatory Policies Act, a more than 40-year-old law that requires electric utilities to buy power from cogeneration and small renewable energy plants.
On one hand, the proposal received high praise from investor-owned utilities that said the regulations were badly in need of modernization. On the other, though, it was largely panned by renewable power and environmental groups, which claimed it would gut the act's, or PURPA's, statutory mandate to encourage electric output from small independent renewable energy producers.
After mulling changes to PURPA for several years, a divided FERC on Sept. 19 issued a notice of proposed rulemaking that would revise key pieces of its implementing rules for the statute.
The NOPR would significantly revise the existing rebuttable presumption that QFs with a net capacity of 20 MW or less do not have nondiscriminatory access to wholesale markets and therefore still merit PURPA mandatory power purchase protections. Under the proposal, that threshold would be lowered to 1 MW.
FERC also proposed to alter its "one-mile rule" for determining a plant's eligibility for classification as a qualifying facility, or QF, under PURPA. The NOPR would maintain an existing irrebuttable presumption that affiliated facilities located one mile or less apart and using the same energy resource are considered a single facility. But the NOPR would give parties the opportunity to show that affiliated plants located more than one mile but less than 10 miles apart still may represent a single facility for the purpose of determining whether they exceed the 80 MW threshold for renewable generators to be designated as QFs.
And in one of the most controversial pieces of the proposal, states would be allowed to introduce more market-based pricing into PURPA power contracts.
Under FERC's implementing regulations, utilities are required to buy power from QFs in their service territories at rates reflecting what they would have to pay to buy that same power from other generators or produce it themselves, referred to as avoided-cost rates. FERC's September NOPR would allow states to eliminate a QF's existing ability to have the avoided-cost rate fixed for the term of the contract or other "legally enforceable obligation" and instead vary the rate based on a purchasing utility's avoided costs at the time of power delivery. Among other things, the NOPR also would let states base energy and capacity rates for QFs on competitive solicitations.
New approach to energy rates at center of debate
The Edison Electric Institute, or EEI, which represents U.S. investor-owned utilities, applauded FERC's proposal. Citing increased competition among generators in organized and bilateral wholesale markets as well as the growth of renewable generation due to state and federal policies and cost declines for wind and solar power, EEI said the U.S. energy landscape is "far different" than when FERC drafted its original PURPA rules in 1980.
As a result, FERC's existing PURPA regulations "are no longer just and reasonable," EEI asserted.
FERC's NOPR would give states "clarity," the group said, by providing tools and guidance for using market-based rates and competitive methods to determine avoided costs. "The proposals in the NOPR are consistent with the requirements of PURPA and provide certainty and opportunities to QFs, while at the same time better ensuring that states have the flexibility to meet PURPA's consumer protection mandates," EEI concluded.
Duke Energy Corp., which holds the most PURPA contracts out of all U.S. investor-owned utilities, said its North Carolina subsidiaries' payment obligations under the statute have "far exceeded" their actual avoided costs due to a fall in the price of natural gas.
Estimating the PURPA-related financial obligation on Duke Energy Carolinas LLC's and Duke Energy Progress LLC's wholesale and retail customers at approximately $4.66 billion over the next 15 years, Duke Energy said the price for QF energy in nearly all of those contracts "is now substantially in excess of the utilities' actual current avoided costs." If the same contracts were allowed to reflect those costs, they would be valued at $2.4 billion, Duke Energy said.
'More market power, not less'
However, the Electric Power Supply Association, a trade group that represents independent power producers including QFs, argued that eliminating the option for QFs to obtain long-term contracts with fixed energy prices will make securing financing in regions with vertically integrated utilities "materially more difficult."
While acknowledging that some QF contracts are substantially above prevailing market prices, the group also said that observation alone does not justify the proposed changes because utilities' revenue requirements approved by commissions in regulated states are similarly based on imperfect forecasts. "Changing market conditions or imperfections in price forecasts do not affect utilities' ability to recover their investment and the return on it over the life of their generation assets," the group noted, suggesting that the NOPR would actually discriminate against QFs.
Echoing the association's comments, the Solar Energy Industries Association, or SEIA, similarly blasted the proposal to eliminate QFs' option to sign long-term commitments for power at a forecast energy rate. "PURPA was designed to allow competitive market entrants to drive change where monopolies refused to do so, yet certain of the changes proposed in the NOPR will give monopoly utilities more market power, not less," SEIA said.
The solar group also opposed both lowering the 20-MW rebuttable presumption threshold for determining nondiscriminatory access to wholesale markets and altering the one-mile rule in the way proposed by FERC. Both of those changes were "arbitrary and capricious" and would discourage QF development, SEIA argued.
SEIA also protested requiring QFs to demonstrate commercial viability before securing a legally enforceable obligation with a purchasing utility.
Some suggested that the proposed PURPA overhaul could be particularly damaging to the solar industry. Solar projects make up the vast majority of planned qualifying PURPA facilities, and the law is an important part of SEIA's strategy to make solar account for 20% of all U.S. electricity generation by 2030.
FERC has said it does not expect the proposed revisions to materially harm the ability of QFs to obtain financing and may, in fact, make working around two- and three-year caps imposed on fixed-price contracts in some states easier for facilities.
In justifying the NOPR, FERC noted that wholesale electricity rates have fallen due to a sharp decline in natural gas prices while vertically integrated utilities no longer "dominate" wholesale electricity markets. The commission also observed that significant renewable resources have been developed without qualifying as QFs under PURPA.
However, none of those points meet the statutory standard for justifying changes to the law, a coalition of environmental groups, including the Sierra Club and Natural Resources Defense Council, argued. Contrary to the law's goal of encouraging the growth of cogeneration and small power producers, the commission's effort to justify its NOPR instead suggests it believes the revisions will reduce the incentives for QF development, the groups said.
Meanwhile, comments submitted by Harvard University's Electricity Law Initiative argued that the NOPR "pays lip service" to PURPA's requirement that the commission issue rules it "determines necessary to encourage" the development of QFs. "The commission suggests that in response to industry changes it may divorce the statute from its plain meaning and issue rules that will restrain QF growth," Harvard said. "But Congress's mandate to the commission is not contingent on industry conditions and does not expire." (FERC docket RM19-15)