The California Public Utilities Commission’s proposed agenda for its final meeting this year is unusually light. The last meeting in December traditionally is packed with big ticket items. Currently, there are only six energy items on the Dec. 15 regular agenda none of which involve major policies in contrast to previous years. At last year’s final meeting, for example, regulators voted on key issues, including a major Southern California transmission project, a rate increase, millions of dollars for controversial utility energy efficiency bonuses, developing a major fossil power plant, a renewable bidding scheme, and a qualifying facilities settlement. The reason for the relatively small number of energy items on next week’s meeting is attributed by some to a statute impacting how the agency does business. An enacted bill--to which the CPUC and California Energy Commission paid scant attention while in the Legislature--added public meeting scrutiny to state agency dealings. The legislation revised the state’s Bagley-Keene Act with the aim of prohibiting closed-door vote counting prior to official public meetings. “A majority of the members of a state body shall not, outside authorized by this chapter, use a series of communications of any kind, directly or through intermediaries, to discuss, deliberate, or take action on any item of business that is within the subject matter of the state body, “ states SB 1494 passed in 2009. Commission legal staff interpreted the statute as prohibiting regulators from meeting with more than one other regulator at a time to discuss business matters. Meetings between regulators’ staffs are also limited. Some commissioners have griped that the restriction impedes their ability to vote on items in an efficient and timely manner. Neither the CPUC nor Energy Commission responded to requests for comments before press time, however. The most noteworthy item slated to be taken up by regulators next week deals with a policy that aims to shave the peak off electricity use at times of high demand. The commission proposes to allow investor-owned utilities to recover $463 million in rates for demand-response programs. If approved at the Dec. 15 meeting, over the next two years $208 million would be allowed for Pacific Gas & Electric, $185 million for Southern California Edison, and $70 million for San Diego Gas & Electric. Demand-response aims to reward customers for dropping electricity use on demand or agreeing to do so via utility remote control. The goal is to keep inefficient, polluting peaker plants from being fired during hot weather or when there are other stresses on the transmission system. Demand-response could ultimately be used to head off rolling blackouts in the case of a grid crisis. The planned program is a result of a historic look at the grid, harkening back to the 2000-01 energy crises when the only way to drop load to avoid cascading blackouts was to create mini-blackouts on a neighborhood level. The demand-response plan formally does that by enrolling big consumers, or consumer aggregators like EnerNoc, to require power drop offs on request. In exchange, those consumers get breaks on their utility bills. With the state requirement for a 15-17 percent cushion of extra electricity sources since the energy crisis, only on rare occasion has there been a call for avoiding rolling blackouts on the California Independent System Operator grid. The commission’s proposed decision calls for heavy monitoring. That includes figuring the consumer’s “baseline” use from which it may conserve electricity. It also requires utilities to impose four cost-effectiveness tests for their spending. Utilities maintain they can, in aggregate, shed about 2,600 MW of demand through various programs that involve both voluntary and involuntary switch offs. According to the commission, PG&E’s program could account for a negative 631 MW next year; SDG&E (n)146 MW; and Edison (n)1,824 MW by 2014. Another year-end matter on the commission’s regular agenda is approving the investor-owned utility bundled procurement plans. These plans cover purchases of short- and medium-term power to meet customer needs from operators of existing generation facilities. Construction of new generating plants is covered separately under utility long-term procurement plans. Key issues include whether to authorize Edison to purchase short-term renewable power, which the ruling would deny, and whether to allow PG&E to enter into a nuclear fuel purchase contract that extends beyond the licensing term of its Diablo Canyon nuclear plant. The decision would deny PG&E’s request. It also would change utility hedging practices aimed at limiting volatility in customer bills. “Our currently authorized hedging appears to have resulted in ratepayers purchasing hedging to protect against relatively minor rate increases,” the decision states. To lower the cost of hedging, which may average about $3 for a customer paying a monthly bill of $96, the decision would allow greater bill increases. It would tolerate the chance of hikes of as much as 10 percent in monthly power bills instead of the current 6.5 percent. This would cut the hedging premium cost while still keeping bill increases to a manageable level for customers, according to the decision. Another provision in the decision would carve out goals for buying power produced by co-generation units per the final settlement agreement on combined heat and power earlier this month (Current, Dec. 2, 2011). Also pending before the CPUC is an item addressing PG&E’s proposed rate adjustments. The proposal would increase residential rates overall by 0.6 percent and agricultural rates by 1.5 percent, but drop rates in other categories, including medium and large energy uses by 0.9 percent, which includes solar rooftop generators.
