By Robert Mullin

Nearly four decades after its passage, the Public Utility Regulatory Policies Act still generates controversy.

PURPA’s supporters and critics sounded off at a June 29 FERC technical conference exploring the ongoing challenges of implementing the law, which Congress enacted in 1978 to diversify the country’s energy supply, increase efficiency and develop a market for independent power producers. The session focused on PURPA’s mandatory purchase obligation and the determination of avoided costs for those purchases (AD16-16).

“In my view, PURPA has held up reasonably well,” Ken Rose, an economist representing the Independent Power Producers Coalition of Michigan (IPPC), told the conference. “It’s hard to believe [that] 40 years on, we’re still working on implementation.”

FERC Commissioner Tony Clark said the law provided a “foot in the door” for the renewable resources now roiling the power industry and its markets.

He also pointed out the commission’s motivation for revisiting the law, saying, “We’re hearing anecdotally about some of the concerns, especially from the West.”

‘Gaming’ the System

Paul Kjellander, president of the Idaho Public Utilities Commission, said his state’s biggest concern is developers disaggregating large wind projects into smaller units in order to obtain the most favorable avoided cost rates for qualifying facilities.

Kjellander referred to the practice as “gaming” the system.

PURPA requires utilities to pay QFs the cost a utility would incur for supplying the power itself or by obtaining supplies from another source. The law leaves it to each state’s utility commission to formulate those rates, depending on project size.

At one time, Idaho’s rules allowed for projects of 10 MW or below to qualify for the state’s most favorable avoided cost — or standard — rate. As in all other states, projects were subject to FERC’s “1-mile rule,” which requires developers to maintain a 1-mile buffer between projects in order to qualify them as separate QFs. The commission implemented the provision to prevent disaggregation.

In 2010, the Idaho PUC received applications for 500 MW of PURPA projects. The minimum system load for the state’s largest utility, Idaho Power, is about 1,100 MW.

Each project submitted that year came under the 10-MW threshold, and most met the 1-mile standard. Kjellander pointed to an instance in which a developer divided the 151-MW Cedar Creek Wind Farm into five projects, each spaced 1 mile apart.

The Idaho PUC reduced the eligibility cap for the QF standard rate to 100 kW later that year in response to requests from the state’s three investor-owned utilities. The regulator last year reduced contract terms from 20 to two years.

Still, Kjellander said his agency observed what it considered another type of gaming when a PURPA developer moved a proposed project across the state line to Idaho Power’s territory in neighboring Oregon, where avoided cost rates were higher. The Oregon Public Utility Commission approved the project, which had also been broken into five units. Despite the project’s location, Idaho customers will foot nearly all the costs for that project, he said.

“We’re looking at an ugly border war with the state of Oregon,” Kjellander said.

‘Manageable Issue’

“This is a manageable issue — it’s not something that can’t be resolved,” countered Robert Kahn, executive director of the Northwest and Intermountain Power Producers Coalition. “To say [PURPA] is easily gamed is to understate the capacity of [state] commissions.”

Kahn called PURPA a “keystone” in facilitating competition. He said that in Oregon — which he said was “a model for PURPA” — small power producers have built just 5% of the resources used to serve the state’s electricity customers.

Without PURPA’s mandatory purchase obligation, he said, small producers in the Northwest are unable to interconnect with the regional market.

“We advocate for organized markets,” Kahn said. “We are not there yet.”

“The argument that the [Western Energy Imbalance Market] negates PURPA is nonsense,” he added.

Organized Markets not Enough

Varnum attorney Laura Chapelle, who represented Michigan’s IPPC, said that even a fully organized market is insufficient to support the financial viability of most QFs in the state, most of which is located within MISO. She contended that the RTO fails to provide a long-term market for smaller generating resources, given that most states in the footprint retain regulated markets.

“Utilities [receive a state-regulated] rate of return to pay for their resources but want to require that QFs use MISO to get compensated,” Chapelle said.

The power purchase agreement is “the single most important component for a project not owned by a utility,” said Todd Glass, an energy attorney with Wilson Sonsini Goodrich & Rosati, who represented the Solar Energy Industries Association at the conference.

Wind projects are becoming more challenging to finance and develop, according to Glass. He also contended that “the utilities are becoming harder to deal with” with respect to negotiating contracts, and that interconnection processes are “very difficult and discriminatory.”

“You should do no harm to the mandatory purchase obligation,” Glass advised FERC commissioners.

Jeff Burleson, vice president of system planning for Southern Co., countered that “QF contracts that are based on long-term avoided costs pose a risk to our customers.”

Burleson said resources acquired through requests for proposals can be dispatched — or not — depending on power prices. “We fix the capacity price, so we can dispatch around it,” he said.

QF resources, on the other hand, cannot be curtailed, even when their costs exceed market prices, Burleson said.

Michael Wise, senior vice president with Golden Spread Electric Cooperative, noted that his members operate in both SPP and ERCOT and said those markets are “best positioned” to set avoided cost rates for their utility market participants. He suggested that FERC narrow the purchase obligation to cover projects of just 1 MW or less in order to prevent “unfair advantages.”

At the very least, Wise said, the commission should reduce the terms of PURPA contracts.

“QFs of all sizes have what we believe are unfettered access to these markets,” Wise said.

John Hughes, CEO of the Electricity Consumers Resource Council, said forcing QFs to become experts in RTO market design violates the spirit of PURPA. He also contended that the industry is trending toward the elimination of long-term contracts.

“We already have that in the organized markets and now we’re attempting that in the unorganized,” Hughes said. “This is a very serious situation that we’re going to have to look at.”