Excludes generational improvements as an eligible resource

Update courtesy of Utility Regulatory News #4057: In conformance with a 2009 energy conservation law enacted by the state legislature, the Hawaii Public Utilities Commission has developed a framework for achieving significant energy savings in the state. The commission embraced an energy efficiency (EE) portfolio standard that sets a statewide goal of reducing electricity consumption by 4,300 gigawatt-hours (GWh) by 2030. The commission explained that the GWh figure was predicated on 30% of the sum of the baseline electricity sales forecasts reflected in the latest integrated resource plans filed by the state’s three investor-owned electric utilities. The EE portfolio process will only recognize savings derived from certain sources, however. Permissible sources include installations of high-efficiency appliances and equipment, customer education and outreach programs promoting conservation, upgraded building codes, and even changes in rate design and advanced metering systems. By contrast though, the commission said that efforts by the utilities to improve the heat rate of their generating plants could not count toward the energy savings goal. It asserted that while improved generational efficiency is always welcome, the state EE law was aimed exclusively at reductions in retail sales, and the metrics for determining heat rates versus electricity sales are quite different. The commission added that incorporation of generational efficiencies into the EE portfolio standard would make its own analytical process that much more complex and could cloud the picture of true EE progress. For the full story, subscribe to URN.

Posted: February 13th, 2012 under efficiency, energy policy, generation.
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Deal deemed more economic than retrofitting existing plant

Update courtesy of Utility Regulatory News #4056: Presented with two options for assuring an electric utility’s compliance with a consent decree entered into with the U.S. Environmental Protection Agency (EPA), the Indiana Utility Regulatory Commission has determined that Plan A, under which the utility would purchase a majority interest in a commercial natural gas-fired generating station, was clearly superior to Plan B, under which the utility would convert two coal-fired generating units to run on natural gas. The two coal plants had been the direct subject of the EPA settlement. After protracted litigation before a series of federal courts, the utility, Duke Energy Indiana, had agreed to terms with the EPA as to the operation of the two coal-fueled units, which were part of the utility’s Gallagher generating site. Under the agreement, Duke Energy was required either to retrofit the units to meet new air emission standards or shut down the units by a certain date. Although the utility had devised both a plan and a proposed budget for converting the Gallagher plants to natural gas, it informed the commission that an opportunity had arisen under which it could instead acquire a 62.5% ownership interest in the Vermillion gas-fired generating project, which had been operated as a merchant power plant by a nonutility affiliate of Duke Energy. Comparing both the bottom-line cost estimates as well as capacity factors for the Vermillion and Gallagher plants, the commission found that not only was the Vermillion purchase plan the less expensive of the two, but it also would provide the utility with greater nameplate capacity. Consequently, the commission ruled that the purchase of the merchant plant was obviously the more cost-effective, and also would allow the utility to satisfy the EPA settlement requirements in a more timely manner. For the full story, subscribe to URN.

Posted: February 6th, 2012 under coal, generation.
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Consider forward-looking policies despite stay of new rule

Update courtesy of Utility Regulatory News #4055: In acknowledgement that at some point new power plant emissions strictures are going to be implemented and enforced, the Indiana Utility Regulatory Commission and the Missouri Public Service Commission have laid the groundwork for compliance with those regulations, even though the new rules have been temporarily stayed by a federal appeals court. The two commissions focused on the Cross-State Air Pollution Rule (CSAPR), released by the U.S. Environmental Protection Agency in July. The CSAPR sets forth a schedule of state-specific limits on emissions of nitrogen oxide (NOx) and sulfur dioxide (SO₂) from electric generation facilities, and also provides an aggressive timeline for achieving the required reductions in NOx and SO₂. Although cognizant that the CSAPR was under appeal, the Indiana commission afforded Northern Indiana Public Service Co. special rate-making treatment for the recovery of costs incurred in planning for and initiating certain associated plant improvements and pollution control construction projects. The Missouri commission likewise addressed preliminary strategies for complying with the CSAPR, granting Ameren Missouri authority to engage in a form of emissions trading. Under that plan, Ameren would be permitted to exchange excess SO₂ allowances for a number of NOx allowances sufficient to satisfy the CSAPR requirements. Both commissions reasoned that regardless of any temporary stay of the regulations, it is inevitable that new emissions limits will eventually become mandatory. For the full story, subscribe to URN.

Posted: January 30th, 2012 under generation, regulation.
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Finds it would amount to an improper rebundling of electric rates

Update courtesy of Utility Regulatory News #4034: In disapproving a request by Public Service Co. of New Hampshire (PSNH) for authority to institute a special generation-related surcharge mechanism applicable to all customers, the New Hampshire Public Utilities Commission has determined that not only would the proffered charge have a repressive effect on customer choice programs, but that it also would be tantamount to repackaged generation and distribution service rates, in contravention of the state’s industry restructuring law which requires that rates for electric generation and distribution services be unbundled.

The utility had asked that it be allowed to recover from all customers a portion of the fixed costs of maintaining its generation assets. According to PSNH, the surcharge should be equally applicable to those customers who now purchase their electric supply from competitive providers, in that there is a possibility that they could return to utility-provided generation at some point. The utility asserted that recouping all its generation costs from other non-shopping customers had produced default energy service rates that were as much as 8 percent higher than they need be. The commission, however, found that the concept of a non-bypassable generation surcharge would violate state law that mandates that generation costs be unbundled from distribution service costs. While nixing the proposed non-bypassable surcharge proffered by PSNH, the commission nevertheless agreed that the utility should be able to impose a fee on customers who migrate elsewhere for supply service and then later return to utility-provided supply. It therefore authorized the utility to submit an associated tariff proposal for just such situations. For the full story, subscribe to URN.

Posted: September 13th, 2011 under generation, ratemaking, retail competition.
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PSC Approves Investment Recovery Bonds

Update courtesy of Utility Regulatory News #4030: The Louisiana Public Service Commission has authorized an electric utility, Entergy Louisiana, LLC (ELL), to use securitization financing as a means of recovering monies it had invested in a now-abandoned generation plant repowering project.

The project involved the Little Gypsy generating station located in St. Charles Parish. Originally constructed as a natural gas-fired unit, ELL had planned to convert the plant from gas to a solid fuel mix of petroleum coke and/or coal. Although the repowering project had an estimated price tag of $1.26 billion, the commission nevertheless deemed it to be a prudent investment at the time initially proposed. Over time, however, as air quality standards and emissions limits became more stringent, ELL revisited its Little Gypsy strategy. It suspended all construction work in March 2008 and formally announced cancellation of the project in October 2009. Because the utility had proceeded with the work with the commission’s blessing, the commission deemed it reasonable for ELL to be able to recoup both monies already sunk into the project and expenses incurred in cancelling the project.

The commission noted that the state legislature had enacted special financing legislation to address just such situations. Under that law, a utility may request authority to issue “investment recovery bonds,” with its ratepayers being required to cover both the principal and interest on the bonds through a non-bypassable investment recovery charge to be added to customer bills. In ELL’s case, the commission approved an issuance of more than $205 million. For the full story, subscribe to URN.

Posted: August 25th, 2011 under finance, generation.
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