Provides advice letter protocol for associated cost claims

Update courtesy of Utility Regulatory News #4061: In order to facilitate interconnections with renewable energy resources, the California Public Utilities Commission has developed new advice letter procedures pursuant to which investor-owned electric utilities can recover from ratepayers certain investments in new transmission facilities. The commission observed that the state’s aggressive renewable portfolio standard (RPS) program seeks to assure that an ever-growing percentage of total electric sales come from green sources of power. However, the commission acknowledged, the state’s existing transmission infrastructure is not always adequate for bringing RPS-compliant energy to the locations where it is needed. In recognition thereof, some utilities have expressed a desire to construct new transmission facilities of their own, but they have been hesitant to go forward with such plans because they lacked guarantees of being able to recoup associated costs. Agreeing that additional transmission capacity was vital to achievement of RPS goals and that, in turn, certainty as to recovery of related preconstruction costs was critical to new transmission investments, the commission devised a “backstop” cost recovery mechanism for certain of those investments. The commission said that only those transmission project costs directly related to RPS requirements and not otherwise included in federally approved transmission rates would be eligible for recovery through the new advice letter process. The commission ruled that to qualify for the advice letter mechanism, a utility need only show that it has a reasonable expectation that the subject project will be necessary for it to comport with RPS mandates. For the full story, subscribe to URN.

Posted: March 13th, 2012 under green energy, renewables, transmission.
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Nixes proposal to lower demand charges for solar customers

Update courtesy of Utility Regulatory News #4057: In the course of reviewing rate design options for an electric utility, the California Public Utilities Commission has rejected a recommendation from a solar advocacy group that fundamental changes be made to the schedules applicable to those customers participating in a pilot solar project. The group had urged the commission to raise from 20 megawatts (MW) to 50 MW the maximum solar capacity eligible for participation in the pilot, and to concomitantly reduce associated demand charges and increase volumetric charges. The commission, however, determined that such changes could lead to an even greater revenue deficit than the utility, Pacific Gas & Electric Co. (PG&E), was already experiencing. The commission said that given that the current solar pilot has played a key role in the utility’s existing revenue shortfall, a decrease in the demand charge would only exacerbate the situation. Further, the commission posited that reductions in the demand charge would run counter to the commission’s cost-based rate-making policies and were likely to cause a shift in cost responsibility among PG&E’s various customer classes. In the commission’s view, lower demand charges for solar customers would translate into other customers subsidizing solar facilities, a result that would be patently unfair. The commission concluded that net-metered solar customers are already properly compensated for the power they export to the grid and that relief from demand charges was not necessary to spur continued interest in solar generation installations on customer premises. For the full story, subscribe to URN.

Posted: February 13th, 2012 under ratemaking, renewables.
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Prompts suggestions about shale gas options

Update courtesy of Utility Regulatory News #4054: The California Public Utilities Commission has approved changes to certain of its renewable energy plans, so as to incorporate recent legislative amendments to the state’s renewable portfolio standard (RPS) program, which amendments increase from 20% to 33% the proportion of the state’s retail electricity sales that must come from renewable resources by the end of 2020. The commission said that its program modifications would offer power sellers further guidance for complying with RPS requirements. One commissioner voiced concern that as the overall percentage of renewables in electric supply portfolios continues to rise, so, too, does the associated cost of electricity. He cautioned that while the goals of the RPS initiative are sound, regulatory authorities must work to prevent related implementation costs from becoming so onerous that commercial and industrial customers feel they have little recourse but to exit their present utility systems or leave the state all together in order to assure their economic survival. To that end, he urged the commission to examine the market opportunities represented by the emerging shale gas industry. Because such activities have contributed to substantial reductions in natural gas prices, he deemed developing shale gas markets to be an important consideration. For the full story, subscribe to URN.

Posted: January 27th, 2012 under energy policy, renewables.
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Invokes use of a wind proxy

Update courtesy of Utility Regulatory News #4054: Reviewing the methodology used by Rocky Mountain Power for its purchases of energy and capacity from wind-based qualifying small power production facilities (QFs), the Wyoming Public Service Commission has adopted a permanent avoided-cost pricing method for the utility. Referring to it as a “partial displacement differential revenue requirement” approach, the commission said that the new method involves two primary changes from previous avoided-cost rate formulas. First, capacity deferrals for all wind QFs will be premised on a wind proxy and will no longer be limited to 50 megawatts per year. Second, the timing and amount of such deferrals will depend on the need for and the costs of a wind unit or a combined-cycle combustion turbine, as reflected in the utility’s most recent integrated resource plan. In rejecting a counter-proposal for “front-loaded” capacity payments to wind QFs, the commission said that such treatment would be tantamount to rate basing of the facilities, a measure that is reserved solely for utility-owned generating resources and thus would be inapt for wind QFs. According to the commission, use of a wind proxy should produce QF rates sufficient to promote growth in the wind power industry in the state. For the full story, subscribe to URN.

Posted: January 27th, 2012 under ratemaking, renewables, wind power.
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Addresses frequency, timing, and eligibility requirements

Update courtesy of Utility Regulatory News #4035: Reviewing advice letters submitted by the state’s three largest electric utilities following a California Public Utilities Commission decision in December that had outlined an auction process for the procurement of energy supplies from small renewable facilities, the commission found that certain modifications were needed in order for the associated solicitations to meet the commission’s vision for its renewable auction mechanism (RAM).

The commission noted that the three utilities - Pacific Gas & Electric Co. (PG&E), San Diego Gas & Electric Co. (SDG&E), and Southern California Edison Co. (SCE) - had proffered advice letters that varied from each other as well as from some of the terms set forth in the commission’s December order. For instance, the commission pointed out, PG&E and SCE had proposed holding only one renewable auction per year, whereas the commission had specifically mandated a total of four auctions over the next two years. The commission also noted that although the December decision had explicitly provided for simultaneous auctions, the utilities had not coordinated their RAM schedules, and SCE had actually recommended that their auctions be staggered purposely. The utilities also disagreed as to what facilities could participate in the auctions and what minimum and maximum capacity limits should apply.

The commission nixed PG&E’s approach to eligibility, which would have restricted participation to new facilities only. Instead, the commission determined that SCE’s terms were preferable in that they would allow both new and existing renewable facilities to participate. As to capacity thresholds, the commission found that certain aspects of both PG&E’s and SDG&E’s proposals were apt. It thus ruled that eligibility would be based on a contract minimum of 1 MW and a project size minimum of 500 kW. However, the commission agreed that projects should be allowed to aggregate, so as to meet the 1-MW contract minimum if their capacity was less than that. Aggregation would be capped at 5 MW, however.

The utilities were instructed to file new advice letters showing compliance with the commission’s directives. For the full story, subscribe to URN.

Posted: September 13th, 2011 under energy policy, green energy, renewables.
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