The California Public Utilities Commission (CPUC) has directed the state's electric and gas utilities to implement a two-year pilot allowing applicants such as residential real estate developers...
California PUC Issues Final Rate Unbundling Order
The California Public Utilities Commission issued its final order on unbundling rates for generation, transmission and distribution functions performed by the state's three largest investor-owned utilities on Aug. 1.
The commission also determined how to calculate transition costs and addressed customer billing and education issues. (Decision 97-08-056, Docket A. 96-12-009 et al.)
The utilities affected are Pacific Gas and Electric, San Diego Gas & Electric, and Southern California Edison.
Rates by Function. The PUC identified separate revenue requirements for distribution and allocated costs of those functions to the various customer classes. It also addressed corresponding rate design principles. The distribution revenue requirements are: $1.95 billion for PG&E; $501.6 million for SDG&E; and $1.67 million for SoCalEd.
The PUC still must review performance-based ratemaking plans of SDG&E and SoCalEd. PG&E must file a general rate case later this year, so the PUC deferred final adjustments to total revenues until those cases have been decided.
The PUC rejected the allocation of generation costs to distribution customers, finding that to do so would subject monopoly customers to competitive products costs.
The PUC said that its most recently adopted revenue-allocation method determines marginal costs for each customer class. It then reaches the adopted revenue requirement by adjusting the rate by an equal percent of marginal cost for each class.
SoCalEd proposed applying the "equal percentage of marginal cost" method, based on total revenues instead of by function. The PUC agreed.
Transition Charges. The PUC rejected the utilities' suggestion for calculating the competitive transition charge. The proposal would have calculated the CTC as the residual cost after calculating all other costs, including the PX price. The charge would have been the difference of the rate at rate-freeze levels and the combination of all other costs: the PX price, the distribution rate, the transmission rate, the public-purpose program surcharge and the nuclear decommissioning surcharge.
Since the CTC can't be known in advance, the utilities would have used real-time pricing and would have "trued-up" the difference after finishing the ISO settlements process.
PUC President P. Gregory Conlon had disagreed with this method of CTC calculation in an alternative proposed order. He said it would mask or distort price signals, create inefficiencies, especially among customers who can shift loads, and reduce peak system demand. Conlon argued in favor of an averaged CTC.
The PUC agreed with Conlon. It implemented an averaged, ex post energy cost for utility service customers. That in turn, through residual calculation, provides an averaged CTC rate for all customers.
Calculations of the average energy costs and the derived average CTC charges will be made for each rate class. The PUC explained that averaging is done weekly, then a rolling average of usually four weeks is calculated to cover the monthly billing cycles for different customers. The series of about one-month averages of PX energy costs is used to calculate residually the averaged CTC on a billing-cycle basis. The PUC said one month was the minimal period for calculating averaged CTC. It's open to proposals for longer averaging periods and for proposals using forecasted PX energy costs.