CPUC Denies Retroactive Power (Un)Payments

By Published On: April 17, 2009

In what could have amounted to at least a $50 million loss for independent energy providers, regulators declined to allow utilities to change payment structures retroactively for small, non-utility supplied electricity. Southern California Edison requested that the California Public Utilities Commission’s newer, market index formula be applied to “qualifying facilities.” If Edison’s request had been approved, it would have pulled a net of $50 million out of the third-party generator industry, according to Steven Kelly, Independent Energy Producers policy director. Other utilities did not tally what the back prices would be, he added. “Prices shouldn’t be subject to after-the-fact changes,” Mike Peevey, CPUC president, said during an April 16 commission meeting. The regulators, however, agreed to hold a hearing if utilities can find “persistent and systematic evidence” that payments to third-party generators exceeded “avoided costs.” In the last 30 years, the commission based payments on “avoided cost.” Now it is supposed to be on a market index formula--except the index has yet to be finalized The concept of avoided costs is to have utility ratepayers pass on payments to non-utility generators at a price that would otherwise be owed to utilities themselves if they provided the electricity--thus the “avoided” part of avoided cost. Short-run avoided cost payments are a relic of the late 1970s. The federal Public Utility Regulatory Policies Act that mandated utilities to buy power from third-party producers was modified by the 2005 federal Energy Act. Now, it includes details requiring plant efficiency and removes the restriction on utility ownership of qualifying facilities. California’s current market index formula is supposed to “better approximate” the old avoided cost, according to the commission. The payments are applied to “qualifying facilities”--small generators, such as cogeneration (combined heat and power) plants. In a related decision, the California Cogeneration Council requested that Pacific Gas & Electric implement a different pricing structure for plants under an “interim standard offer” contract. Regulators disagreed with cogenerators over the type of contract. The interim contracts “were never intended to replace firm capacity contracts,” they concluded. Commissioners say the two different pricing structures reflect “different circumstances and [are] reasonable.” The commission also approved amendments to PG&E’s contract with the proposed 600 MW Russell City power plant. “It’s much-needed for local reliability,” Peevey said. He added that the plant would help address electricity shortfalls due to weather and intermittent resources, like renewable power. The fossil fueled plant set for development in Hayward was delayed in part following the bankruptcy reorganization of Calpine, the original owner. During bankruptcy, Calpine sold a part of the potential facility to GE Energy Financial Services. According to the commission, the plant could come on line next year. While regulators did not reveal the terms of the contract, they did note it would be a “comparable price to the current market for power purchase agreements.”

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