Today, the California Public Utilities Commission (CPUC) unanimously approved Commissioner Peterman’s revised Alternative Proposed Decision (APD) to conclude the cost allocation methodology portion of the Power Charge Indifference Adjustment Methodology (PCIA) proceeding. Phase II of the proceeding will address many important issues that still need resolution.
The PCIA determines the cost indifference calculation for how much community choice aggregator (CCA) customers, bundled investor owned utility (IOU) customers, and direct access (DA) customers will pay for generation resources previously procured on their behalf. These costs are allocated to customers who departed or may depart IOU service territories to take service from a CCA or direct access provider (electric service providers (ESPs)).
Per the CPUC’s 10/11/18 press release: “Bill impacts will vary depending on customer class, service provider, energy usage, the energy markets, and a utility’s resources. Evaluating CCA residential customers departing in 2018, there is an estimated 1.68 percent increase in bills of residential CCA customers over 2018 bills as a result of today’s decision in PG&E’s territory; in Edison’s territory, that figure is 2.50 percent; and in SDG&E’s territory, that number is 5.24 percent. Any rate increases for one group of customers will be offset by rate decreases for other sets of customers.”
This post updates a previous post that explained the original proposed alternative decision. This post focuses on explaining the differences between the original PD, APD, and the revised APD adopted today.
The major contested difference between the PD and APD dealt with whether Public Utilities Code Section 366.2(f) allows legacy Utility Owned Generation (UOG) under the PCIA and whether to continue the 10-year limit on cost recovery for post-2002 UOG and certain storage costs under the PCIA. The adopted revised ADP (Decision) found that UOG is PCIA eligible and the 10-year limit is no longer reasonable. The Commissioners reiterated several times that UOG costs were incurred to serve all customers and will be recovered from customers who depart from IOUs.
The adopted Decision maintains the proposed price calculations for the Brown Power Index, the new RPS adder calculation, and the new RA adder calculation. The Brown Power Index calculation remains the same as the original PCIA. The RPS Adder and RA Adder will now use reported prices from purchases and sales from IOUs, CCAs, and ESPs from the previous two years, in the case of the RPS adder, and the previous year, in the case of the RA adder, for delivery in the forecast year. New required transaction reporting requirements are designed to ensure transparency and accuracy as to the market value of these resources to calculate the adders.
The Decision determined that an annual true-up of the PCIA rate for the Brown Power Index that account for actual realized market transactions for each subject year with Portfolio Allocation Balancing Accounts (PABA) and Energy Resource Recovery Account (ERRA) balancing accounts and proceedings will ensure transparency and accurate cost allocation and recovery for Brown Power. In Phase II of the proceeding, a true-up process will be developed under a working group for RA and RPS by the end of 2019 that reflects the complexities of resolving issue regarding untransacted resources and renewable energy credits (RECs).
The Decision amends the proposed PCIA rate cap beginning in 2020. The amendment to the cap level of the PCIA rate sets the cap at .5 cents per kWh more than the prior year’s PCIA and removes the floor for the rate. The Decision makes substantive changes to the trigger mechanism for the PCIA cap (set at 10% of the forecasted PCIA revenue) by amending language for notice timing, type of notice required when revenue exceeds 7% of forecasted revenue, and flexibility where self-correction below 10% is expected (See p. 150-152).
The Decision maintains the option for a CCA or ESP to prepay its PCIA obligation with further proceeding and evidence needed to develop prepayment options. The CPUC iterated that the ability to fund prepayment is not a prerequisite to evaluating prepayment frameworks to determine costs. The Decision expects parties to work together to develop criteria and functional method to determine prepayment using a working group for Phase II of the proceeding. The CPUC retained approval authority over any prepayment agreement.
The Decision also further explained why applying a GHG-free adder proposed by certain parties is unwarranted because of scarce data on GHG-free resource transactions premiums to reliably value the market for a hydro-electric or nuclear resource GHG-free benchmark. Per Commissioner oral comments, this may be addressed in future hearings or proceedings once data exists for the value of these resources.
Many issue remain. In addition to RA and RPS benchmarking true-ups, Phase II will address Prepayment, Portfolio Optimization and Cost Reduction, and Allocation and Auction under a working group process. The Commission hopes to resolve as many Phase II issues before the end of 2019 as possible.
During his comment period, Commissioner Rechtschaffen reserved the right to file a concurrence to the adopted decision. Any additional information from his concurrence will be posted at a later date.
Finally, the possibility that this decision will be appealed in court remains. I will post an update if an appeal is filed.
**This post was updated on 10/12/18 with an estimated bill impact statement from a CPUC press release**