On August 1, 2018 the California Public Utilities Commission (“CPUC”) issued a proposed decision that would adopt tweaks to the methodology used to calculate the Power Charge Indifference Adjustment (“PCIA”) — the “exit fee” charged by California’s large investor-owned utilities (“IOUs”) on customers who begin taking electric service from community choice aggregation programs (“CCAs”). While the proposed decision would adopt short-term changes to make the PCIA calculation more accurate and equitable, it would defer developing long-term solutions to the growing mismatch between IOU portfolio resources and bundled load resulting from growing retail energy choice.

Background

The PCIA is designed to cover above-market IOU portfolio costs from legacy energy contracts that the utilities entered into but no longer need and cannot sell in the market for the price they paid. The purpose of the PCIA is to make bundled utility customers financially indifferent to the fact that customers have left the utility. The current PCIA methodology calculates an “indifference amount” by starting with the forecast costs of the IOU generation portfolio (e.g., contract payments, utility-owned generation (“UOG”) revenue requirements), and subtracting a proxy of the revenue those resources could garner in the market using forecasts of energy prices and administratively-determined benchmarks that collectively comprise what’s called the “Market Price Benchmark.”

The Commission opened the PCIA rulemaking to address growing dissatisfaction among IOUs and departing load parties that the current PCIA methodology does not achieve “indifference” between customer groups. The Commission recognized that the PCIA must be designed to prevent cost shifting both from departing load to bundled customers and from bundled to departing load customers.

The CPUC’s Proposed Decision

On August 1, after more than a year of deliberations, the CPUC issued a proposed decision which determines that the current PCIA methodology does not prevent cost-shifting between customer groups and proposes to address problems in the short-term with a revised methodology to calculate the PCIA beginning January 1, 2019.

The proposal involves three main short-term solutions:

  • Adopting revised inputs to the Market Price Benchmark to improve the initial accuracy of the PCIA that will be in effect each year.
  • Adopting an annual true-up mechanism to ensure that bundled and departing load customers pay equally for PCIA-eligible resources.
  • Adopting a cap to limit the change in the PCIA rate from year to year, in an attempt to provide the rate stability and predictability sought by departing load interests.

Corrected Market Price Benchmark

The Proposed Decision would tweak the methodologies for calculating the value of capacity and renewable energy credits provided by PCIA-eligible resources using components of the Market Price Benchmark referred to, respectively, as the resource adequacy adder (“RA Adder”) and renewable procurement standard adder (“RPS Adder”). It would also require electric service providers (“ESPs”) and CCAs to report detailed information about their contracts to ensure the accuracy of the RPS Adder. The CPUC believes its proposed changes will result in utilization of the best available transactions data to approximate a realistic PCIA obligation.

Annual True-up

The Proposed Decision would implement an annual true-up process that would require IOUs to create balancing accounts to track costs related to Market Price Benchmark components and pass any year-end under- or over- collection to the subsequent year’s PCIA calculation.

PCIA Cap

To mitigate major fluctuations in the PCIA from one year to the next, the Proposed Decision would also include a 2.2 cent/kWh cap on the PCIA and require that the annual change to the PCIA charge be capped at 0.5 cents/kWh for any PCIA charge above 1.5 cents/kWh.

Other Changes

In response to requests for simplicity and predictability, the Proposed Decision would include an option for departing load customers to pre-pay their PCIA obligation through agreements requiring Commission approval on a case-by-case basis.

The Proposed Decision would also side with CCA stakeholders on two important issues: (1) exclusion from the PCIA calculation of the costs of legacy utility owned generation projects (“UOG”) installed prior to 2002, and (2) preservation of a 10-year limit on cost recovery of UOG installed post-2002. The Proposed Decision explains that removing the 10-year limitation on recovery “would also remove any incentive for the IOUs to manage their portfolios more aggressively to eliminate their long positions in non-RPS-eligible UOG.” It further notes that “the imperative from this point onward will be to work toward portfolio optimization and cost reduction, and leave behind static portfolio management and the associated cost recovery of above-market costs for utility-held resources that are no longer needed by the bundled customers that they serve.”

Development of Comprehensive Solution Kicked to Second Phase

The Proposed Decision would open a second phase of the proceeding to consider the development and implementation of a longer-term, comprehensive solution to address the costs of excess resources in utility portfolios. The Proposed Decision notes that the Commission expects the solution “to be based on a voluntary, market-based redistribution of excess resources” in the IOUs’ electric supply portfolios. Phase 2 would establish a “working group” process to enable parties to further develop a number of proposals regarding portfolio optimization and cost reduction.

 

Next Steps

Interested parties may file comments on the Proposed Decision by August 21. Reply comments are then due by August 27. The Proposed Decision is currently on calendar to be considered at the CPUC’s September 13 Business Meeting, although the vote may be delayed.

 

For more information, contact members of the DWT Energy Team.

Vidhya Prabhakaran at 415-276-6568 or VidhyaPrabhakaran@dwt.com.
Patrick Ferguson at 415-276-6563 or PatrickFerguson@dwt.com.
Emily Sangi at 415-276-6582 or EmilySangi@dwt.com.