Calif. Adopts Changes To Power Cost Indifference Adjustment (PCIA), Exit Fee Applicable To Direct Access
PUC Mandates Retail Suppliers File Confidential Contractual Info To Assist In Developing Benchmark Prices
Cap Adopted For PCIA, But Starts in 2020
PUC Orders Development Of PCIA Prepayment Option, Adopts "Framework", Implementation Subject To Further Proceeding
October 12, 2018 Email This Story Copyright 2010-17 EnergyChoiceMatters.com
Reporting by Paul Ring • email@example.com
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The California PUC has adopted changes to the Power Cost Indifference Adjustment (PCIA), a charge applicable to load not taking utility bundled service, such as direct access and municipal aggregation, with the rate, as described by the PUC, intended to equalize cost sharing between departing load and bundled load.
"In this decision the Commission adopts revised inputs to the market price benchmark (MPB) that is used to calculate the Power Charge Indifference Adjustment (PCIA), the rate intended to equalize cost sharing between departing load and bundled load. The revised methodology will be used to calculate the PCIA that takes effect as of January 1, 2019. We also open a second phase of this proceeding to consider the development and implementation of a comprehensive solution to the issue of excess resources in utility portfolios. We expect that solution to be based on a voluntary, market-based redistribution of excess resources in the electric supply portfolios of Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company," the PUC said
The revised PCIA methodology will take effect as of January 1, 2019. The PCIA methodology will be as follows:
a. The Brown Power Index shall continue to be calculated using the methodology adopted in Decision (D.) 06-07-030.
b. The RPS Adder shall be calculated using reported prices from purchases and sales of renewable energy by the investor-owned utilities (IOUs), Community Choice Aggregators (CCAs) and ESPs during the year two years prior to the forecast year (year n-2) for delivery in the forecast year (year n). For the 2019 RPS Adder forecast only, the Energy Division shall use the most recently published Platts Portfolio Content Category (PCC) 1 REC index mid value ('California Bundled REC (Bucket 1)') as of November 1, 2018. The RPS Adder for each utility will be the sum of the Platts PCC 1 REC index value and its brown power index.
c. The RA Adder shall be calculated using reported purchase and sales prices from IOU, CCA, and Electric Service Provider (ESP) transactions made during (year n-1) for deliveries in (year n). A zero or de minimis price shall be assigned for capacity expected to remain unsold. The RA Adder shall be calculated in a manner that reflects the three types of RA capacity: system, local, and flexible. For the 2019 RA Adder only, the Energy Division shall use the weighted average system and local RA prices in the most recent annual RA report.
The PUC will include the costs of pre-2002 Legacy utility-owned generation (UOG) within the PCIA, which the PUC said is consistent with AB 117 and SB 350.
The PUC will remove the 10-year limit on recovering costs for post-2002 UOG from departing load
The PUC adopted an annual true-up mechanism and cap as part of the PCIA.
The annual true-up will initially be limited to the Brown Power Index, to reflect actual values realized in market transactions for the subject year for the Brown Power Index.
The PUC did not adopt a true-up for the RPS and RA PCIA components, but directed that true-ups of these components should be addressed in Phase 2 of the proceeding.
Starting with forecast year 2020, the cap level of the PCIA rate should be set at 0.5 cents/kWh more than the prior year’s PCIA, differentiated by vintage.
A "trigger" mechanism for the PCIA cap was adopted and shall function as follows:
a. The PCIA trigger threshold is 10% of the forecast PCIA revenues.
b. If PG&E, SDG&E, or SCE reach 7%, and forecast that the balance will reach 10%, they shall, within 60 days, file expedited applications for approval in 60 days from the filing date when the balance reaches 7%.
c. The application shall include a projected account balance as of 60 days or more from the date of filing depending on when the balance will reach the 10% threshold.
d. The application shall propose a revised PCIA rate that will bring the projected account balance below 7% and maintain the balance below that level until January 1 of the following year, when the PCIA rate adopted in that utility’s ERRA forecast proceeding will take effect.
e. The IOUs are authorized to notify the Commission through advice letter filing, instead of expedited application, when the PCIA balance exceeds its trigger point and the IOU does not seek a change in rates, if the IOU reasonably believes the balance will self-correct below the trigger point within 120 days of filing. The advice letter filing shall include necessary documentation to support the IOU’s conclusion that the PCIA balance will self-correct below the trigger point within 120 days and that a rate change is not needed.
The PUC endorsed the framework for a prepayment option for the PCIA, to be available to ESPs and CCAs, but ordered that implementation of such an option shall be addressed in Phase 2 of the case.
The PUC set forth the following framework for PCIA prepayment
a. The prepayment shall be based on a "mutually acceptable" forecast of that customer's future PCIA obligation;
b. The prepayment may shall take the form of either (1) a one-time payment; or (2) a series of levelized payments over 2-5 years;
c. The prepayment shall not be trued-up;
d. Once the prepayment has been made, the customer shall not receive any refunds if it returns to bundled service; and
e. After prepayment is finalized, the customer may switch among competitive retail sellers without incurring any new PCIA obligation.
The Commission declined to adopt a sunset of the obligation to pay the PCIA.
The PUC said that it is not practical to attempt to implement voluntary allocation and auction mechanisms for utility supply assets associated with departing load by January 2019. Specifically, the PUC said that Commercial Energy's Voluntary Allocation & Auction Clearinghouse proposal should be further developed in a second phase of this proceeding
As noted above, several of the PCIA components will rely on prices from retail supplier (ESP) and CCA contracts, in addition to utility prices.
To implement such order, the PUC established new transaction reporting requirements for all Load Serving Entities, including Community Choice Aggregators and Energy Service Providers, "to ensure that the Renewables Portfolio Standard Adder is as accurate as possible."
Beginning in 2019, all Load Serving Entities shall submit the following information to the Commission’s Energy Division on an annual basis by January 31:
• Contract information shall be collected for all Load Serving Entity contracts executed in year n-2, with year n being the forecast year for which the Power Charge Indifference Adjustment calculation is being done.
• Contract information shall include: seller name, execution date, contract price ($/MWh), term length of contract, capacity (MW), associated Net Quantifying Capacity, annual expected generation (MWh/year), expected generation for year n. If a contract includes Time of Delivery (TOD) adjustments, then the contract’s price shall be TOD-adjusted.
The PUC set a second phase of the case to address issues related to departing load on a longer time horizon
The PUC established work groups to address:
1. Benchmark true-up, including for RA and RPS
3. Portfolio Optimization and Cost Reduction
4. Allocation and Auction
The PUC said, "we find that a second phase should be opened in this
proceeding. The second phase’s purpose is to develop structures, processes, and
rules governing portfolio optimization going forward. Portfolio optimization
proposals should include voluntary auction frameworks. Although we decline
to endorse any one voluntary auction proposal at this time, we remind parties
that any proposals should be consistent with the guiding principles in this decision. We anticipate the use of a working group process to develop these optimization proposals further. Some of the proposals offered by parties thus far in this proceeding would, if adopted, require coordination with other Commission proceedings, including the Integrated Resource Planning (IRP), Resource Adequacy (RA), and Renewable Portfolio Standard (RPS) proceedings. The second focus of phase two will be to minimize further accumulation of uneconomic costs. The Commission will consider further guidance and standards for more active management of the utilities’ portfolios in response to departing load in the future, and improvements in forecasting of departing load by all LSEs. Phase two will also consider shareholder responsibility for future portfolio mismanagement, if any, so that neither bundled nor departing customers bear full cost responsibility if utilities do not meet established portfolio management standards. Utilities are of course required to manage their portfolios prudently. Imprudent management would justify disallowing recovery of portfolio costs, and could be considered in ERRA or General Rate Case (GRC) proceedings."