Finds they exceed Michigan RPS requirements

July 22, 2010 - Weekly Update From Utility Regulatory News #3978: While not discounting the importance of renewable energy in the resource strategies of electric utilities, the Michigan Public Service Commission nevertheless has reduced an electric utility’s jurisdictional renewable power supply cost for rate-making purposes, to reflect the fact that the company had been exceeding the proportion of renewable power needed to meet the state’s renewable portfolio standard (RPS) requirements.

The utility, Wisconsin Electric Power Co. (WEPCO), is headquartered in neighboring Wisconsin but has a multistate presence. It had allocated $5.4 million in renewable power costs to its Michigan services, based in part on Wisconsin’s RPS requirements, which provide that 4.27 percent of retail sales in 2010 and 8.27 percent by 2015 must qualify as renewable energy. However, the commission pointed out that Michigan had adopted a less ambitious RPS program with a lower minimum purchase term, such that the amounts attributed to WEPCO’s Michigan operations were clearly excessive.

According to the commission, WEPCO actually had been acquiring more renewable energy than it needed even for the Wisconsin RPS targets. The commission said it had discovered that for the period 2011 to 2014, WEPCO’s renewable power commitments ranged from 31 percent to 120 percent more than necessary for meeting Wisconsin’s RPS requirements. As a result, the commission reduced WEPCO’s Michigan revenue requirement by more than $4 million to account for the excess purchases. Subscribe to URN for the full story.

Posted: July 22nd, 2010 under energy policy, green energy, regulation, renewable energy credits, renewables.
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Ratepayers to foot most of cost

July 22, 2010 - Weekly Update From Utility Regulatory News #3978: Deeming smart grid technology to be a prudent investment, the Oklahoma Corporation Commission has preapproved up to $366.4 million in program costs for Oklahoma Gas & Electric Co. (OG&E) to construct a smart grid system.

The estimated costs of the program include a $130 million stimulus grant from the federal government. Although ratepayers will be expected to cover $220 million of the costs, OG&E said the smart grid network will save them money at the same time, including more than $20 million in operation and maintenance (O&M) expenses and $8 million in meter reading costs. The utility was authorized to recoup its project costs from customers via a smart grid recovery rider (SGRR) over a 42-month period, the end of which should coincide with the company’s next scheduled rate case in 2013.

To facilitate reconciliation of the SGRR in that 2013 proceeding, the commission ordered that three regulatory assets be established, one as a smart grid O&M account, one as a stranded meter cost account, and one as a Web portal account. Although ratepayers will be funding the program through the SGRR, they also will be credited with any cost savings achieved as a result of consumption reductions, shifts in usage, or other energy efficiencies made in response to information obtained from the new smart meter equipment.

Despite widespread support for smart grid technology, and in spite of assertions that the smart meters to be used have tested 99.98 percent accurate, one commissioner dissented, saying that a more measured approach should have been taken and that any preapproval of costs should have been limited to incremental stages. Subscribe to URN for the full story.

Posted: July 22nd, 2010 under Smart metering, dynamic pricing, efficiency, regulation, smart grid.
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State RPS provisions might violate Commerce Clause.

Weekly update courtesy of URN #3976: Determining that purchases of power from renewable resources are of regional, not just statewide, importance, and citing the possible implications of a recently filed civil lawsuit, the Massachusetts Department of Public Utilities (DPU) has temporarily ceased enforcement efforts of regulations that require electric distribution companies to solicit long-term “green” power supply contracts only from developers within the state.

The DPU explained that Massachusetts law has established through its renewable portfolio standard program a certain minimum threshold amount of energy that electric utilities must procure from renewable resources, such as wind, solar, and biomass. However, the law presently restricts long-term purchases of such to being from renewable power suppliers whose facilities are located within Massachusetts, or at least within state or federal waters. But the DPU acknowledged that a competitive energy services marketer has challenged that limitation in a federal district court, alleging that the law discriminates against out-of-state generators and thus violates the Commerce Clause of the U.S. Constitution.

In light of that pending litigation, and asserting that it was reasonable to facilitate the ongoing development of renewable energy sources throughout the region, the DPU ruled that existing in-state purchase requirements should be lifted, at least for the interim. It therefore authorized electric utilities to reopen their renewable power solicitations so as to consider bids from eligible out-of-state generators in addition to in-state suppliers. Subscribe to Utility Regulatory News for the full story.

Posted: June 30th, 2010 under Uncategorized, energy policy, green energy, regulation, renewable energy credits, renewables.
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Gas LDC’s proposal deemed insufficient incentive for conservation.

Weekly update courtesy of URN #3976: Following the trend seen in several other states recently, the Tennessee Regulatory Authority (TRA) has become the latest governing body to deny a utility’s petition to institute a revenue decoupling mechanism.

In the case before the TRA, a natural gas local distribution company (LDC), Piedmont Natural Gas Co., had requested permission to implement a decoupling program, claiming that absent the ability to break the link between actual sales and revenues, it would have no impetus for promoting conservation, energy efficiency, and other usage reduction measures. According to the LDC, decoupling would provide it with the means for aligning its own financial objectives with the best interests of its customers.

Piedmont’s proposal was premised on a decoupling program with a true-up mechanism that would allow full recovery of the average per-customer margin. However, in looking at the LDC’s earnings statistics that underlie its plan, the TRA observed that such earnings were based on a benchmark from the company’s last rate case, which had been in 2003. Using a reference point from that long ago could translate into a disincentive for customers to lower their consumption levels, the TRA said.

The TRA explained that Piedmont had structured its decoupling mechanism in such a way that a consumer could reduce usage but not see any decrease in the amount billed. To address its concerns that the LDC’s outdated rate-making data could skew customers’ bills, regardless of their conservation efforts, the TRA ruled that it would be imprudent to authorize a decoupling program in a stand-alone proceeding. Instead, it determined that decoupling should be considered within the context of a full-blown rate case. Subscribe to Utility Regulatory News for the full story.

Posted: June 30th, 2010 under efficiency, natural gas, regulation, revenue decoupling.
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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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