Maryland PSC urges utility to invest more of its own money in program.

Weekly update courtesy of URN #3976: Finding that any ratepayer benefits from an electric and natural gas utility’s proposed “smart meter” rollout would be “largely indirect, highly contingent and a long way off,” the Maryland Public Service Commission (PSC) has disapproved the company’s advanced metering infrastructure (AMI) program.

The utility, Baltimore Gas & Electric Co. (BGE), had submitted a plan under which every meter in its service territory would be replaced with a new AMI module. Although BGE professed that a stimulus grant of $136 million from the U.S. Dept. of Energy would be dedicated to the project, the PSC noted that total plan costs were estimated to be $835 million, with the company seeking to hold its customers liable for the difference via a special surcharge mechanism that would go into effect before the meter installation work even began.

The commission expressed displeasure at the utility’s attempt to saddle its ratepayers with the entire cost of the new metering equipment. Explaining that a utility’s metering network is a backbone component of its service system — i.e., part of its infrastructure — and that utilities traditionally have invested their own funds in such plant, the PSC said that it could not authorize the AMI initiative as proposed.

The commission added that it also strongly objected to another part of the plan that would have made time-of-use (TOU) rates mandatory for residential customers during the summer season. In the commission’s view, whatever benefits a customer might receive as a result of a smart meter being installed at his or her premises likely would be greatly mitigated, if not completely negated, by the combination of the surcharge and the mandatory TOU schedules.

The commission emphasized that its rejection of BGE’s smart meter program as presented should not be taken as an indication of the PSC’s nonsupport of AMI programs in general. To the contrary, the commission stated, it fully endorses the concept of AMI deployment, and it invited BGE to return with a revised AMI business plan that was more equitable in cost sharing and not as “untenable” as the present proposal. Subscribe to URN for the full story.

Posted: June 30th, 2010 under Smart metering, Uncategorized, dynamic pricing, regulation, smart grid.
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Rejects Other Special Rate Mechanism Proposals

Weekly Update Courtesy of URN #3973: In the course of a natural gas base rate proceeding, the Michigan Public Service Commission has authorized the utility, Consumers Energy Co., to institute a revenue decoupling program on a trial basis. However, several other special cost recovery proposals were not greeted with similar favor.

The company had requested the revenue decoupling mechanism (RDM), alleging that ongoing conservation and energy-efficiency initiatives were exerting downward pressure on the utility’s sales, and hence its revenues. To assure that successful usage reduction campaigns would not adversely affect actual revenues even if the company experiences lower sales, Consumers Energy suggested tracking its sales and revenues separately through the RDM. It proposed modeling the decoupling program on the RDM that had already been approved for its electric operations, which was premised on a consumption-per-customer algorithm. Although agreeing that a gas RDM was appropriate, the commission noted that electric and natural gas consumption can have very different characteristics, especially during Michigan’s sometimes harsh winters. The commission therefore ruled that the gas RDM should be based on a straight revenue algorithm rather than a consumption-per-customer algorithm and also should employ a 15-year weather-normalized sales approach. To not incorporate normalization would risk extreme billing volatility for customers if the state had a colder-than-normal winter, the commission said.

Turning to Consumers Energy’s other proposals, the commission denied the utility’s uncollectible expense tracker mechanism (UETM), its pension expense mechanism (PEM), and its other post-employment benefits (OPEB) mechanism. The company had asserted that the UETM, PEM, and OPEB tracker all followed costs that are closely linked with market performance and the economy in general. Citing the fact that Michigan’s economy is in even worse shape than the rest of the country, the utility argued that the separate cost recovery mechanisms were imperative. The commission, however, observed that newly streamlined rate case procedures would prevent much of the regulatory lag that had inhibited timely recovery of such costs in the past.

Given signs that the economy was finally improving as well as its new expedited rate case schedules, the commission deemed the UETM, PEM, and OPEB mechanism unnecessary. -Subscribe to Utility Regulatory News for the full story.

Posted: June 18th, 2010 under Uncategorized, efficiency, natural gas, regulation, revenue decoupling.
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Weekly Update Courtesy of URN #3973: The Minnesota Court of Appeals has affirmed a Minnesota Public Utilities Commission (PUC) decision in which the commission had declined to compel an electric utility, Northern States Power Co. d/b/a Xcel Energy, to enter into a power purchase agreement (PPA) with the sponsor of an integrated gasification combined cycle (IGCC) power plant.

The project developer, Excelsior Energy Inc., had touted its Mesaba Energy Project as a state-of-the-art IGCC facility that would be both environmentally friendly and economically productive. Although it had received certain preliminary permits and local approvals for the project, Excelsior was unable to reach agreement with Xcel Energy for purchasing the unit’s output. Excelsior thereupon petitioned the PUC for an order mandating that Xcel Energy sign the developer’s proffered PPA.

In considering the terms of the proposed PPA, the commission undertook a two-part analysis, the first part of which looked at whether the plant qualified as an innovative energy project (IEP) under state law. The commission said that if that first part were answered in the affirmative, then it needed to determine if the associated PPA would be in the public interest. Despite various parties’ claims to the contrary, the PUC declared that the Mesaba project did indeed fit within the definition of an IEP under state law. The commission explained that the IGCC technology was clearly innovative, would use coal as a primary fuel, and would significantly reduce four noxious emissions enumerated in the controlling statute. The commission thus concluded that the project met the basic criteria for IEP status established in the legislation. However, the commission ultimately disapproved the PPA, deeming it to involve an excessive and unrealistic cost structure that could jeopardize Xcel Energy’s financial health if it were forced to enter the agreement. Although the project developer argued that the PUC’s public interest analysis had exceeded its PPA review authority, the court held that the commission was clearly within its rights to conduct such a review, given its obligation to protect the overall public interest and the broad discretion conferred upon it to interpret those laws and regulations which it has been charged with enforcing, such as the IEP statute.

Accordingly, the court refused to substitute its judgment for that of the commission.-Subscribe to Utility Regulatory News for the full story.

Posted: June 18th, 2010 under IGCC, Uncategorized, carbon regulation, climate change, coal, green energy.
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Weekly Update Courtesy of Utility Regulatory News #3973: Finding that they would present a good opportunity to evaluate “advanced demand response scenarios,” the Colorado Public Service Commission has approved three rate options for residential customers taking part in the Smart Grid City demonstration project, sponsored by Xcel subsidiary Public Service Co. of Colorado’s (PSCC).

The project, located near Boulder, is designed to examine large-scale applications of advanced metering infrastructure (AMI) and other smart technologies. Involving the installation of 24,000 smart meters, Smart Grid City is expected to measure customer acceptance of and adaptation to new in-home, two-way communication devices that allow customers to better track their consumption habits vis-à-vis real-time costs of their usage.

According to PSCC, the pilot smart grid project will be more effective if the AMI offerings are paired with various rate options. To that end, it proposed three specific new rate tariffs: a time-of-use (TOU) rate, a critical peak pricing (CPP) rate, and a peak time rebate (PTR) rate. The TOU schedule is a basic rate that reflects the different costs of service depending on the time of day consumption occurs. The CPP schedule expands on TOU rates by designating certain days and periods as critical and subject to higher prices, usually because of weather-related conditions that strain resources. The PTR offering takes rates one step further by making participants eligible for a rebate if they are able to keep usage below a certain baseline threshold during critical peak times. The commission approved the utility’s plan to seek 2,000 volunteers to test the three rate options. Participants would be allowed to select which of the three options they want to try on a first-come, first-served basis. In agreeing to the TOU, CPP, and PTR proposals, however, the commission emphasized that its action should not be interpreted as a predisposition to approval on a permanent basis. The commission remarked that it is simply too soon to rule on whether the three rate options represent optimal rate design measures.-Subscribe to URN for the full story.

Posted: June 18th, 2010 under Uncategorized, dynamic pricing, efficiency, regulation, smart grid.
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Vermont PSB continues alternative regulation plan

Weekly Update Courtesy of Utility Regulatory News #3969: Endorsing the price cap form of regulation for an electric utility, the Vermont Public Service Board has determined that the utility had been able to strengthen its financial position as a result of its alternative regulation plan (ARP).

The board found that the utility, Green Mountain Power Corp., had instituted an ARP that was in the best interests of its ratepayers and that the ARP, as compared to traditional cost-of-service rate making, allows the utility to respond more quickly and effectively to changes in operating costs. Nevertheless, the board agreed that some updating was needed. To that end, the board authorized both the retention of the salient features of the utility’s existing ARP and the addition of certain new provisions. One of the terms kept from the current plan is an annual adjustment to the utility’s rate of return on equity (ROE) based on yields from 10-year Treasury notes. However, the new plan offers a revised performance-based adjustment for ROE, under which Green Mountain Power’s efficiency and productivity will be measured against a benchmark group of utilities. The updated ARP also includes an inflation-adjusted capping mechanism for non-power costs, whereas the existing plan relied on a fixed dollar ceiling for such costs.

The board deemed the ARP changes appropriate given the collective experience of electric utilities operating under ARPs in the state. In the board’s view, the modified plan will facilitate more accurate capture of the impacts of inflation over time.

Observing the continued volatility in both energy and financial markets, the board ruled that such inflation adjustments marked a significant improvement in the utility’s ARP. For the full story, Subscribe to URN.

Posted: June 9th, 2010 under Uncategorized, efficiency, finance, green energy, regulation, renewables.
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