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| Utilities continue to sound the alarm about
the proliferation of must-run contracts in New England, this time focusing
on a recent application by the 160-MW Pittsfield Generating plant. The Massachusetts Municipal Wholesale Electric Company and NSTAR have called on federal regulators to deny the project's request for Reliability Must-Run (RMR) status, saying such contracts are driving up electricity costs. The debate over must-run contracts stems from a confluence of problems plaguing the industry in New England. Aging plants say it is no longer profitable to stay in business, but few new power plants are in development and load pocket constraints leave the grid vulnerable to reliability problems. The Federal Energy Regulatory Commission has been approving the must-run payments to keep plants that are needed for reliability from deactivating or retiring. About 7,000 MW of generation is either operating as must-run or seeking regulatory approval to do so. MMWEC said the Pittsfield application presents an opportunity for FERC to "draw a line in the sand" when it comes to must-run approvals. The joint action agency, which serves more than half of the state's municipal utilities, takes issue with Pittsfield's application, in particular, because the plant already received $244 million in contract buyout payments from NSTAR and U.S. Generating, plus $37 million in connection with the sale of a gas contract. Pittsfield, owned by U.S. Bank National Assn., now seeks approval before the Federal Energy Regulatory Commission for $36.5 million/year in must-run payments. Pittsfield has not demonstrated that it needs additional financial support to stay in business, according to MMWEC. In its own filing to FERC, NSTAR echoed MMWEC's concerns, saying that suppliers are "backsliding on their competitive commitments" by seeking cost-of-service rates. The result is upward pressure on prices the utility pays for power in the deregulated state. However, Don Scholl, president of PurEnergy, which is general partner, O&M operator and asset manager of Pittsfield, said in an interview that the plant cannot recover its costs in the New England wholesale market. Built in 1990, before the state restructured the industry, the plant was designed to operate in a market where its entire capacity would be committed to a limited number of utility customers under long-term contracts. The facility does not have characteristics valued in the current deregulated market, such as quick-start capability and a low heat rate. As a result, the plant is not called to operate often in the spot market. Pittsfield had a rate expert recreate how the plant would have been dispatched in the ISO spot market if it had not held the power purchase agreements with NSTAR and U.S. Generating. The analysis concluded that the plant would have "suffered overwhelming losses" without the long-term contracts, according to a filing Pittsfield made before FERC. Going forward after the contract buyouts, Pittsfield reported losses for the year ending Sept. 30, 2005. Revenue generated by Pittsfield net of fuel and other variable costs was $4.315 million, versus on-going costs of $44.08 million, yielding a net loss before extraordinary items of $39.77 million. "Based on actual data, Pittsfield clearly recovers less than its cost of service," Scholl said. He also said that the buyout and fuel contracts do not represent a double recovery from ratepayers, as alleged by MMWEC. The NSTAR buyouts, for example, were approved by state regulators as a cost-saving measure for ratepayers. The buyout took away a future revenue stream from the plant. MMWEC also opposes must-run requests for Boston Generating's Mystic Units 8 and 9 in Boston ($238 million/year), Berkshire Power's Agawam plant ($30 million/year) and Consolidated Edison's West Springfield Unit 4 ($8 million/year). The agency argues must-run agreements are a last resort, not "permanent life support" or "supplemental funding options" for generators unable to make money in competitive markets. When a generator seeks must-run status, ISO New England conducts a technical analysis to determine if the plant is necessary for reliability purposes. If it finds the unit is needed, FERC then approves or disapproves the payment sought by the generator. "ISO must do more than fiddle while Rome burns at a rate of tens of millions of dollars per year," MMWEC said. "On the contrary, requests for RMR agreements should trigger a prompt and diligent effort to identify less expensive interim solutions that will maintain reliability until an 'optimum solution' is identified and implemented." Erin O'Brien, an ISO spokeswoman, said that if the grid operator finds a unit necessary for reliability, it means no alternative exists that is less expensive. "Our role in the reliability must-run agreement process is to determine if a unit is needed for reliability under current system conditions," she said. "We conduct each of these assessments based on the real operating conditions of the system." A developer may propose a transmission, generation, demand-response or other solution to a reliability must-run contract. But until that solution is in place, it cannot be considered an alternative to a reliability must-run agreement. "If the solution were to move forward, at that point in time, we would reassess the need and could find that the (must-run) plant is no longer needed for reliability," she said. The ISO has proposed a locational installed capacity plan to encourage development of new capacity in congested areas, and reduce need for must-run contracts. However, several stakeholders oppose the plan because of its cost. LICAP is now under review by the Federal Energy Regulatory Commission. 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