But excludes higher rate of return on equity

Update courtesy of Utility Regulatory News #4072: The Washington Utilities & Transportation Commission has determined that even though the capacity from a new wind power project is not presently needed to assure service reliability, it would be appropriate for the sponsoring utility, Puget Sound Energy (PSE), to recover project costs from current ratepayers. The commission conceded that the multi-phase wind facility, known as the Lower Snake River Wind Project, is not yet complete and that even the first part of the project that is complete will not be necessary to meet projected demand for at least another four years. Nevertheless, the commission ruled that current customers should be required to pay for the project’s costs up front. It explained that the initial phase of the wind farm offers numerous environmental benefits on a present basis, in the form of reduced carbon dioxide emissions. Moreover, the commission said, the facility will prove crucial to PSE’s ability to satisfy future renewable energy mandates. Consequently, citing the wind project as a major driver, the commission authorized the utility to raise its electric rates by $63.3 million. However, the commission rejected the company’s recommended rate of return on equity (ROE), which PSE had sought to increase from 10.1% to 10.75%. The commission stated that in light of historically low interest rates, reduced yields on U.S. Treasury bonds, and ongoing economic instability, there was no justification for a higher ROE. Indeed, the commission commented, current market conditions had produced lower investor expectations, such that the utility’s ROE should be decreased rather than augmented, leading the commission to find a 9.8% ROE reasonable. For the full story, subscribe to URN.

Posted: May 30th, 2012 under generation, green energy, ratemaking, renewables, wind power.
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Recommends that the program not be expanded

Update courtesy of Utility Regulatory News #4072: A study commissioned by Consolidated Edison Co. of New York (ConEd) has found that the electric utility’s mandatory hourly pricing (MHP) program has failed to reduce or shift electric consumption in the manner or to the extent anticipated during periods of peak demand. The MHP structure was instituted pursuant to state directives in 2006 and was designed to encourage large power users to modify their consumption habits in response to pricing signals tied to the hourly rate posted by the New York Independent System Operator for the zonal day-ahead market for energy. But the outside consultant retained by ConEd to perform the study reported that there had been few instances where the price threshold had triggered a demonstrable change in consumption. In fact, the consultant said, from 2009 to 2011, that threshold price had been met a total of only 10 hours. Moreover, the consultant disclosed, despite lowering from 1,000 kilowatts (kW) to 500 kW the monthly peak demand a customer could have to be eligible for the MHP plan, the number of full service MHP customers had declined precipitously. It noted that ConEd currently has just 272 full service MHP customers remaining, which is only about 15% of the original number of full service MHP customers the utility had. The consultant’s analysis concluded that expanding the offering of the program to include even greater numbers of customers was unlikely to be cost-effective for either ConEd or MHP participants. For the full story, subscribe to URN.

Posted: May 30th, 2012 under dynamic pricing, energy policy.
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But warns that it might produce significant price increases for reserve capacity

Update courtesy of Utility Regulatory News #4071: Although the Federal Energy Commission (FERC) acknowledged the potential for dramatically higher prices during rare occasions of supply-demand imbalance, the commission nevertheless allowed the PJM Interconnection to proceed with plans to establish a new market for non-synchronized capacity reserves. At the same time, FERC narrowed the time interval for market clearing and setting of prices.

Under PJM’s plan, referred to as scarcity pricing, non-synchronized reserves will for the first time be priced in the market on their own, separate from synchronized reserves, although both synchronized and non-synchronized reserves will be subject to their pricing levels being reset every five minutes. The change was intended to account for the anomaly caused by traditional reserves markets clearing and closing one hour ahead of real time, whereas real-time locational marginal prices (LMPs) for wholesale energy would close only 10 minutes ahead. The FERC agreed that the pricing changes, in conjunction with a downward-sloping demand curve, would produce LMPs for the reserves that better reflect actual costs. However, the FERC conceded that the pricing adjustments could lead to real-time wholesale LMPs reaching as high as $2,700 per megawatt-hour (MWh) in PJM’s territory, more than two-and-a-half times the current day-ahead bid cap of $1,000 per MWh.

In justifying the likely increases, the FERC explained that the scarcity pricing approach assures that both real-time energy and reserve markets will close simultaneously, thus giving market participants advance warning of any impending reserve shortages and a guarantee that prices for capacity reserves will reflect the true value of energy at that time. For the full story, subscribe to URN.

Posted: May 22nd, 2012 under dynamic pricing, energy markets.
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Reliability project drives need for increase

Update courtesy of Utility Regulatory News #4071: Citing a proven need for widespread system improvements and/or facility replacements, the New York Public Service Commission has authorized a natural gas local distribution company (LDC) to increase its base rates by a cumulative 9% over a three-year period. The commission found that the LDC, Corning Natural Gas Corp. (CNG), had shown that its aged and deteriorating pipelines, especially those serving the Bath and Hammondsport areas, were in critical need of upgrades and that the company had reached an appropriate cost-sharing arrangement with the village of Bath to co-fund the so-called Bath Reliability Project, which will address and rectify many of those system problems. Under that agreement, Bath will pay an annual reliability charge to CNG, which monies will be used to complete the project, while the company will be liable for penalties should it not attain certain performance milestones in constructing the new facilities. The commission listed certain other service reliability measures for the LDC as well, including requirements that the company undertake a more comprehensive survey of leaks and unaccounted-for gas and work to decrease its leak backlog. Additionally, CNG was ordered to institute a customer service performance incentive (CSPI) mechanism, with the commission pointing out that the LDC had been the only major utility in New York without such a mechanism. The commission said that the company will be subject to “negative incentives” should it fail to comply with either the leak detection or the CSPI standards. For the full story, subscribe to URN.

Posted: May 22nd, 2012 under natural gas, ratemaking, reliability.
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Deems DPL’s planned deployment marginally cost-effective

Update courtesy of Utility Regulatory News #4071: Upon submission of a more thorough cost-benefit analysis of its proposed systemwide installation of smart meters, Delmarva Power & Light Co. (DPL) received authorization from the Maryland Public Service Commission to move forward with its plan.

When the utility first filed its advanced metering infrastructure (AMI) proposal more than a year ago, the commission rejected the plan as overstating the likely benefits of the rollout. According to the commission, DPL’s business case had been flawed because it was based more on assumptions and overly optimistic projections than on cold, hard data. The commission also had been concerned that the utility’s original proposal did not provide for any type of AMI customer education campaign.

Responding to the commission’s criticisms, DPL engaged in further cost studies and amended its AMI strategy to reflect more conservative and realistic cost data, and to incorporate clear plans for promoting customer awareness. Although pronouncing itself pleased that DPL had taken steps to improve its smart meter initiative, the commission related that DPL’s AMI program, while cost-effective, would be so only barely. That is, the commission said, DPL’s smart meter project was unlikely to be as cost-effective as those of the other large electric utilities in the state, in that those utilities had been awarded grants from the U.S. Department of Energy for their respective AMI plans, while DPL had not. The commission observed that the grants will offset the other utilities’ capital investment needs and will help make their plans more cost-effective. Nevertheless, the commission agreed that DPL’s business case for its AMI project, as modified, now warranted approval. For the full story, subscribe to URN.

Posted: May 22nd, 2012 under Smart metering, ratemaking, smart grid.
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