Berkshire official says QF companies abusing PURPA rules to sell power to utilities

The Public Utility Regulatory Policies Act needs to be reformed for various reasons, including that it is forcing electric utilities to take power they don’t need at prices that are too high, said Jonathan Weisgall, a vice president at Berkshire Hathaway Energy, at a June 4 hearing in Congress.

Weisgall testified before the Energy and Power Subcommittee of the House Energy and Commerce Committee. It was in regards to legislation related to the accountability and energy efficiency aspects of the committee’s “Architecture of Abundance” energy package being pushed by the panel’s Republican majority.

Berkshire Hathaway Energy (BHE) today owns three regulated U.S. utilities with customers in 11 states – MidAmerican Energy, PacifiCorp and NV Energy – as well as other energy assets in the U.S., Canada, the U.K., and the Philippines.

“A large part of our U.S. business strategy has been to invest in renewable energy and develop competitive transmission projects to meet electric reliability needs and existing and emerging clean energy goals,” Weisgall noted. “When current projects are completed, we will have invested approximately $8.0 billion in our wind energy portfolio among our regulated utilities in Iowa, Wyoming, Oregon, and Washington State. We have also invested an additional $8.1 billion in just the last five years through our unregulated subsidiary, BHE Renewables, in three very large utility-scale solar projects as well as wind projects. And we continue to operate our 10 geothermal plants, some of which date back to the 1980s. In order to encourage the continued development of renewable energy resources at low costs to our customers and protect them from volatility in power costs, we have identified three areas that would benefit from Congressional action.”

One of them is to modernize the Public Utility Regulatory Policies Act of 1978 (PURPA). Thirty-seven years ago, Congress approved PURPA in response to the oil crisis then gripping the country. PURPA’s goal was to promote increased energy conservation and efficiency. Both the Federal Energy Regulatory Commission (FERC) and state regulatory commissions are responsible for enforcing PURPA.

Notable is that BHE has both regulated electric utilities forced to take power from PURPA projects, and a non-regulated side that can develop its own PURPA projects. So Weisgall in some respects represents both sides of this debate. 

Congress also wanted to encourage growth in the renewable energy sector, Weisgall pointed out. Section 210 of PURPA requires all electric utilities (including government-owned utilities and electric cooperatives) to purchase electricity at a government-determined “avoided cost” price from qualifying small power producers or qualifying cogenerators (QFs). Small power producers must generally use renewable or waste materials as fuel and are limited in size to 80 MW of installed capacity. Pursuant to FERC regulations, cogenerators must produce useful thermal energy to be used for industrial, commercial, or similar purposes, as well as electricity.

Generation from renewable energy resources, such as wind and solar, has increased substantially since PURPA was enacted. Renewable energy facilities have benefitted from technological advances, tax incentives, state renewable portfolio standards (RPS), federal and state subsidies, and numerous U.S. Environmental Protection Agency (EPA) regulations that have shifted the electric power industry away from coal-based facilities.

The PURPA mandatory purchase obligation requires QFs to sell to the interconnected local utility at a set price based on the utility’s “avoided cost,” regardless of whether the utility needs the generation or whether it is the most efficient resource choice, Weisgall pointed out. FERC gave state utility commissions the flexibility in determining a utility’s avoided cost, the “incremental cost” to the electric utility of alternative electric energy. Under PURPA, these rates also have to be just and reasonable and nondiscriminatory and the utility must purchase the power from QFs even if they do not need it.”

Weisgall: avoided cost calculations are woefully inaccurate

“PURPA contracts based on administrative determinations of avoided cost are notoriously inaccurate, and often exceed the cost of true utility options,” Weisgall wrote in his prepared testimony. “This unduly increases rates to electric consumers, and, since PURPA contracts frequently run for as long as 20 years, PURPA locks in these high rates for the long term. EPAct 2005 As a result of substantial abuses, particularly with respect to cogeneration facilities, Congress amended PURPA in EPAct 2005.”

Under the amended law, the mandatory purchase requirements of Section 210(m) of PURPA end if FERC finds that a QF has nondiscriminatory access to:

  • Independently administered, auction-based, day-ahead and real-time wholesale markets for the sale of electric energy and access to wholesale markets for long-term sales of capacity and electric energy (Day 2 markets); or
  • Transmission and interconnection services provided by a FERC-approved regional transmission entity pursuant to an open-access transmission tariff that affords nondiscriminatory treatment to all customers, and competitive wholesale markets that provide a meaningful opportunity to sell capacity and electric energy to buyers other than the utility to which the qualifying facility is interconnected (Day 1 markets); or
  • Wholesale markets for the sale of capacity and electric energy that are, at a minimum, of comparable competitive quality as the markets described above.

In 2006, FERC issued new rules to implement the new Section 210(m) provision governing removal of the mandatory purchase obligation. In Order No. 688 (and subsequent orders), FERC created a rebuttable presumption that QFs having a capacity greater than 20 MW (large QFs) have nondiscriminatory access in the “Day 2 markets” of the Midcontinent Independent System Operator, PJM Interconnection, ISO New England and the New York ISO; in the “Day 1 markets” of the Southwest Power Pool; and the “comparable markets” of the California ISO and Electric Reliability Council of Texas.

The evidentiary showings FERC established are higher for “Day 1 markets” than for “Day 2 markets” and highest for “comparable markets” due to the presumption that QFs there have fewer off-system sales opportunities respectively in these markets, Weisgall added. FERC also established a rebuttable presumption that QFs having a capacity of 20 MW or less (small QFs) lack nondiscriminatory access to the three 210(m) markets, even if they are located within markets meeting the statute’s tests. This presumption has made it exceedingly difficult for utilities to avoid purchasing from small QFs, which could be as large as 20 MW, without limit, and regardless of whether the power is needed, he said.

“Any utility may file an application with FERC for relief from the mandatory purchase obligation showing how the conditions described above have been met,” said Weisgall. “Absent an order from FERC granting the requested relief, however, a utility remains obligated to purchase power from QFs at a government-determined avoided cost rate.

“There have been several trends occurring in recent years that indicate that PURPA’s original intent to encourage independent generators is no longer necessary or useful. First, current PURPA provisions are imposing significant and unnecessary costs on utility consumers. Second, FERC has made it too difficult for utilities to obtain relief from the mandatory purchase obligation despite Congress’ intent in enacting Section 210(m) in EPAct 2005 to limit that obligation. Third, FERC’s ‘one mile’ QF size calculation rule has resulted in the designation of multiple portions of larger energy projects as individual small QFs contrary to Congress’ intent behind PURPA.

“In many instances, the power produced by QFs is not needed to replace base load generation or meet decreasing levels of demand. Growth of electricity demand has slowed in each decade since the 1950s. Since PURPA’s enactment, electricity markets have developed to allow utilities to purchase replacement power rather than build base load plants. BHE’s PacifiCorp utility is experiencing a significant increase in PURPA contract requests, despite the fact that its long range resource plan shows no need for additional generation resources until 2028. It currently has requests for 3,641 MW of new PURPA contracts, in addition to the 1,732 MW of PURPA contracts that are already executed. The number of PURPA contracts may soon equal PacifiCorp’s average retail load. For example, the 5,373 MW of existing and proposed PURPA contracts at their nameplate capacity would be equal to 79% of PacifiCorp’s average retail load and 108% of PacifiCorp’s minimum retail load.

“As the Subcommittee debates energy legislation, expanding the mandatory purchase obligation is unnecessary given changes to electricity markets that have occurred since the purchase mandate obligation was created 37 years ago. BHE does not support bills that would expand PURPA by requiring utilities to purchase electricity from QFs at prices in excess of avoided cost. With energy efficiency gains throughout the economy and new opportunities for customer generators, growth in customer electricity demand has slowed and many utilities simply do not need more generation. If a utility does need new generation, including renewable energy, competitive solicitations overseen by state regulatory commissions are the best means for acquiring a least-cost supply.

“Avoided cost determinations too often result in higher prices for consumers. Determining an appropriate avoided cost rate has been controversial from the beginning of PURPA. Government formulas (promulgated by the states and subject to FERC review) routinely fail to react to dynamic market conditions and often force utilities to enter into long-term contracts at prices that are substantially above-market, meaning electricity consumers pay more for electricity than they otherwise would. Whereas locational marginal prices are utilized in many markets to set rates for power, prices for PURPA power often bear no relationship to these market-based prices.

“Although avoided cost rates are theoretically intended to reflect actual costs to build or replace necessary generation to protect customers from paying other costs, in practice state ‘administrative’ determinations, particularly for the long-term power purchase contracts that their vertically integrated utilities have typically been required to enter into to facilitate QF construction, have tended to over-estimate future market prices. These contracts, with up to 20-year terms, often assumed electric rates would continue to rise, an error that has required utility ratepayers to pay substantially above-market rates for power, even in instances where a utility’s integrated or long-term planning process demonstrates that no new resources are needed for the foreseeable future. Left unchecked, the resulting subsidies will continue to unfairly shift these rising power costs to customers and undermine competitive markets.”

Weisgall gives examples of wind/solar projects being split up to meet QF standards

Weisgall said that BHE’s PacifiCorp utility has seen many developers across its six-state service area disaggregate large projects into smaller ones in order to qualify as a QF and take advantage of the PURPA mandatory purchase obligation as well as higher standard offer prices (awarded for smaller projects).

  • In one example, he said that prior to applying for a QF contract, one developer, Cedar Creek Wind LLC, a company jointly owned by Western Energy and Summit Power Group, had submitted a bid into PacifiCorp’s 2008/2009 renewable RFP process as a single 151-MW wind project to be located in Bingham County, Idaho. PacifiCorp did not select the project through its RFP process because the offered price was too high and not competitive with other alternatives. In March 2010, the same developer requested QF pricing for two 78-MW projects, but the avoided cost rate offered at the time was too low. In May 2010, in an attempt to secure a more favorable standard rate, the developer reconfigured the project again, this time as five distinct projects, totaling 133 MW.
  • In another example, the Oregon Windfarm QF project located in eastern Oregon is a large 64.5-MW wind project that was disaggregated by the developer, John Deere Renewables, into nine QF projects ranging in size from 1.65 MW to 10 MW and constructed in 2008. The projects were not independent family or community-based projects and clearly were a disaggregation of a large single wind project, Weisgall said. The nine wind projects are operated today as a single wind project, delivering electricity to a single interconnection point on PacifiCorp’s system, and are currently owned and managed by Exelon Generation, which acquired John Deere Renewables in 2010.
  • As of May 1, 2015, PacifiCorp has executed several large (50 MW to 80 MW) solar PV QF contracts in Utah where the developer secured a large generator interconnection agreement over 80 MW and then developed multiple adjacent large QF projects that feed into that interconnection agreement. For example, SunEdison has three 80-MW projects called Escalante I, II and III all adjacent to each other, technically meeting FERC’s one-mile separation rule, but they are managed as a single project, Weisgall said.
  • In an earlier example of disaggregation, SunEdison and First Wind (later acquired by SunEdison) executed seventeen 3-MW standard offer solar PV QF contracts in 2013 and 2014. Several of these projects are built on a single land parcel, use a common interconnection point of delivery, and are constructed to meet the one-mile PURPA rule.
  • Currently, EverPower Wind Holdings is developing the Mud Springs Wind Ranch Project and requesting three 80-MW QF contracts for projects that are all adjacent to each other in Montana, again meeting FERC’s one-mile rule, but sharing a common 230-kV transmission line they are building into PacifiCorp’s service area near Frannie, Wyoming, in order to secure Wyoming avoided cost prices. The three phases/projects will each be owned by a separate company, but operated as a single large wind farm. These are the: Mud Springs Wind Ranch Pryor Caves Wind Project (80 MW); Mud Springs Wind Ranch Mud Springs Wind Project (80 MW); and Mud Springs Wind Ranch Horse Thief Wind Project (80 MW).

FERC has not attempted to address “gaming” of its one-mile rule, Weisgall wrote. “FERC enforces its one-mile rule literally and has stated it will not examine whether larger projects have been divided into smaller projects in order to obtain QF status, so long as the projects comply with the one-mile rule. In particular, FERC has stated the one-mile rule does not contain a ‘rebuttable presumption’ that may be used by a utility to contest the QF status of a given project.

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.