Summary of CPUC’s R. 17-06-026 Proposed Decision on Track 2 Power Charge Indifference Adjustment (PCIA) Proceeding

arrow communication direction display

Photo by Pixabay on Pexels.com

With the increasing number of community choice aggregators (CCA) in California, the California Public Utilities Commission (CPUC) opened proceeding R. 17-06-026 on June 29, 2017 to “Review, Revise, and Consider Alternatives to the Power Charge Indifference Adjustment” (PCIA). The PCIA represents that exit fee that customers pay when they depart from an incumbent utility. The proceeding is divided into different tracks to address the various issues relate to the PCIA. This post will explain the reason for revising the PCIA, briefly address the Track I decision, and focus primarily on the recently noticed Track II proposed decision (PD).

It is important for readers to understand that this PD is exactly that, a proposed decision of Administrative Law Judge (ALJ) Roscow. It has no legal effect until the CPUC hears it as a noticed agenda item and votes to adopt the PD.  The earliest this may occur is September 13, 2018.  Parties must file comments on the PD within 20 days of its service on parties.  It is also possible for assigned Commissioner Peterman and/or for another Commissioner to propose an alternative decision.

To this end, Assigned Commissioner Peterman announced this morning at the August 9, 2018 CPUC Voting Meeting that she will submit an alternative proposed decision in this proceeding based on comments and the oral argument that occurred the day after ALJ Roscow noticed the PD.  Commissioner Peterman stated that this alternative proposed decision will be noticed in the near term and should still allow the Commission to vote on the proposals at the September 13, 2018 Voting Meeting. Once the alternative proposed decision becomes available, we will publish another blog to explain and compare the PD and Commissioner Peterman’s alternative proposed decision.

ALJ Roscow’s PD proposes to:

  • revise the methodology used to calculate the PCIA beginning on January 1, 2019 by changing inputs to some of the market price benchmark (MPB) that calculate the PCIA to equalize cost share between departing load and bundled customers and maintain indifference;
  • adopt a true-up mechanism to ensure equitable cost share and a cap limiting the change in the PCIA rate from one year to the next to provide rate stability and predictability;
  • adopt an option for departed load customers to pre-pay their PCIA obligations; and
  • open a second phase to consider long-term solutions through the development and implementation that will evaluate solutions based on voluntary, market-based redistribution of excess resources in the electric supply portfolios of Pacific Gas & Electric (PG&E), Southern California Edison (SCE), and San Diego Gas & Electric (SDG&E).

The following sections will provide a primer on the PCIA, the track I decision, and what the track 2 PD changes, and concludes with a discussion of Phase 2 of track 2.

 

What is the PCIA and Why Does it Matter?

The PCIA’s genesis takes us back to the energy crisis of 2001 and the legislative response to the crisis under AB 1X.  AB 1X responded to the failure of California’s deregulated energy market, consequent brown outs, and the necessity to buy and deliver electricity. AB 1X authorized the Department of Water Resources (DWR) to purchase electric power for delivery to retail customers and suspended the right of customers to enter into direct access (DA) transactions with non-utility providers, known as electric service providers (ESPs) or DA providers. As a result of the crisis, DA providers returned their customers to incumbent utilities that were receiving purchased electricity from DWR.  The significant demand of electricity caused post-crisis electric costs to skyrocket resulting in many customers who were receiving DWR electricity to return to DA providers for electric service.  When DA customers returned to their providers they left bundled IOU customers with the full cost of the electricity procured by DWR. This required the CPUC to address cost-shifting between DA customers and the remaining customers who continued to receive bundled services (electricity + transmission/distribution) from the IOU.

The CPUC created an exit fee and cost responsibility surcharge—what would later be replaced with the PCIA methodology in 2006—to recover costs from DA customers and ensure that bundled customers remained indifferent.  In 2006, the CPUC reached consensus with IOUs, DA providers, and customer groups to create the PCIA-based methodology that compared each IOU total portfolio costs in cents/kWH to the market benchmark comprised of the posted forward prices for a one-year strip of power for the coming year, plus a capacity adder to the reflect the costs of resources adequacy (RA). The CPUC made two additional major refinements: 1) adopting a revised capacity adder and increased the market price benchmark by adding a renewable procurement standard (RPS) adder; and 2) broadening of cost responsibility from authorized energy storage procurement costs under the PCIA.  The legislature codified the mandate to ensure cost indifference between these customers in SB 790 (Chapter 599, Statutes of 2011) and SB 350 (Chapter 547, Statutes of 2015).

 

The PCIA methodology calculates the above market costs caused by the procurement of electricity on behalf of customers who subsequently leave IOU electric service for a CCA to ensure indifference between customers who remain with the IOU and those who leave for a CCA or DA provider. This is expressed as Total Portfolio Costs—Market Value of Portfolio = Indifference, where the costs and value are calculated as follows[1]:

PCIA Method

The above equation for Market Value of Portfolio is often explained as “Brown Power” + “RPS adder” + Resource Adequacy (RA) adder.” The method of calculating the total portfolio costs and market value of portfolio help to determine the above market costs that the PCIA recovers to ensure indifference between customers who leave IOU territory and those that remain.

The relatively recent dramatic increase of customers departing IOU territory for CCA electric service authorized under AB 117 (Chapter 838, Statutes of 2002) brought into question whether the existing PCIA methodology that is designed for cost-shifting indifference for a small and static number of DA customers can adequately provide indifference with the large number of departed load from IOU service. For example, PG&E has seen the most departed load with 17% of its load base departing as of March 2018 for CCAs and, under its own forecast reported to the Energy Commission, as much as 42% departing by 2019.  Below is a chart that PG&E presented to the Energy Commission on July 10, 2018 during the Integrated Energy Policy Report proceeding update on Energy Demand Forecast Update (18-IEPR-04):

PG&EDeparted Load

PG&E, SCE, and the Energy Commission are working to better forecast long-term load departure but current limits on data collection and CCA variability from start date changes and phased in enrollment by customer class make long-term forecasting difficult while near-term forecasting is becoming more accurate.  In total, the trade group CalCCA reports that approximately 2.5 million customers are now served by CCAs statewide.  All parties to this proceeding agree that the PCIA methodology does not maintain indifference between customers but disagree on solutions.  Parties proposed various solutions that made various changes to the methodology and addressed what to do with IOU portfolios that are over procured as a result of departed load.

The next section will discuss the Track I decision and Track II PD.

 

Track 1 Decision Eliminating California Alternative Rates for Energy (CARE) and Medical Baseline (MB) Customers’ Exemption from the PCIA in SCE and SDG&E

On Track 1, the CPUC issued Decision 18-07-009 addressing current exemptions from paying the PCIA for departing load customers in two IOU territories (SDG&E and SCE).   The decision eliminated the exemptions for CARE and MB programs in SDG&E and SCE service territory.  The CPUC ordered that SDG&E and SCE ensure that no CARE or MEB customers of a CCA receive any exemption from paying the PCIA as of January 1, 2019.

The Decision found that the energy-crisis related liabilities that served as the cause for the exemption were eliminated from SCE’s portfolio in 2011 and SDG&E’s portfolio in 2013, that the current exemption results in an additional discount for CARE and MB customers, and that an exemption for departing CARE and MB is inequitable. The CPUC ordered each IOU to create and implement outreach to provide notice and education to impacted customers.  This Decision requires CARE and MB to pay for their share of the PCIA.

 

Proposed Decision for Track 2 Phase I

The PD addresses the cost shift under the existing methodology, the scope of PCIA-eligible resources and costs, and adopted portfolio valuation and allocation methods.  Parties submitted proposals on these issues and the ALJ PD takes from these proposals in formulating its proposed decision to the full commission.

Cost Shift Changes

The identified cost shift issues focus on calculation of the market value of the portfolio (see above) with issues raised around how the MPB for renewable energy and resources adequacy are calculated. This discussion focuses on the first two issues listed in the scoping memo (see p. 20) addressing whether the PCIA prevents cost increases to bundled customers resulting from customer departure to other providers or implementation of CCA programs and whether the PCIA prevents cost increases for CCA customers and DA customers as a result of allocation of costs that were not incurred on behalf of the departed load. The proposed methodology can be found in Appendix 1 at the end of the PD.

First, the PD does not change the MPB for the Brown Power maintaining the existing calculation of the Brown Power Index that is determined at the end of October each year.  Parties did not object to the current calculation for the Brown Power market price benchmark.

Second, the PD adopts The Utility Reform Network’s (TURN) proposal to estimate the RPS adder. The basis of TURN’s proposal is to more accurately reflect the actual benefit an IOU would receive for selling a renewable energy resource in the market.  Presently, the PCIA’s method for calculating the market value of an IOU’s renewable generation or Green Power is estimated by adding two components to the CPUC’s original Brown Power Index: 1) the IOUs’ renewable costs (“URGreen”) and 2) a renewable premium (“DOEadder”). The total market value is equal to the sum of 68% of the URGreen value plus 32% of the DOEadder value plus the value of the Brown Power Index. TURN clarified in its filings that the current DOEadder is an estimate of the total value of renewable power and not an independent renewable premium or renewable energy credit (REC) price.

TURN argued that the URGreen is a measure of a subset of the IOUs’ embedded costs for renewable energy and not the market price of resource separating any sale of renewable power in a given year because the MPB presumes this sale would be at the embedded price. Additionally, TURN notes that the Department of Energy stopped publishing the index used to calculate the DOEadder and argued that relying on the assumption that renewable energy is equal to the cost of brown power plus a renewable energy adder is probably outdated, given that renewable power will not necessarily trade at a positive premium to brown power.

Based on TURN’s and other parties’ explanations of the current PCIA, the PD determined that the methodology cannot prevent costs shifts and is in violation of Public Utilities Code Section 365.2 and 366.3.  TURN’s proposal adopted by the PD calls for a modification that reconciles forecasted values with actual market transactions through a true-up process.  The PD consequently would modify the benchmark’s renewable power value to reflect the pricing reported by all LSEs for purchases and sales or renewable energy in prior years. The PD proposed changing the data requirement for this calculation by requiring a more realistic timeframe for when data becomes available.  This would use reported prices of purchases and sales of renewable energy by the IOUs, CCAs, and ESPs during the year two years prior to the forecast year (“year n-2”) for delivery in the forecast year (“year n”). The RPS adder for 2020 would thus use purchases and sales data from 2018 to calculate the RPS adder. The PD determined that for the 2019 RPS adder only, the Energy Division would use the LSE cost information submitted on August 20, 2018 in their 2019 RPS Procurement Plans. The PD determined that this offers a credible approach to the difficulty of limited sources of transparent price data.

Third, the RA adder would be calculated using reported purchase and sales prices from IOU, CCA, and ESP transactions made during year n-1 for deliveries in year n. Unsold capacity or capacity expected to remain unsold would be assigned a zero or de minimis price. The PD adopts the California Large Energy Consumers Association’s (CLECA) proposal to the RA adder that it be changed to reflect the types of Resource Adequacy (RA): system, local, and flexible. This would require the Energy Division in the CPUC to separate confidential data by type of RA where:

  • RA that provides both system and flexible capacity would be counted as flexible capacity;
  • RA that provides both system and local capacity would be counted as local RA capacity; and
  • If the RA provides all three types of RA capacity, it would be treated as local capacity.

The proposal would differentiate local capacity values by Transmission Access Charge (TAC) areas. For the 2019 RA adder only, the Energy Division would use the weighted average system and local RA prices in the most recent annual RA report.

The PCIA rate would take effect January 1 or each year using the values for the Brown Power Index, RPS Adder, and RA adder.

Finally, the PD made these legal findings related to cost recovery:

  • AB 117 did not include the costs of pre-2002 Legacy UOG within the scope of costs that can be allocated to CCA departing load customers.
  • The ten-year limit on cost-recovery of post-2002 UOG costs adopted in D.03-12-059 and affirmed in D.04-12-048 and D.08-09-012 is not a violation of Public Utilities Code Sections 365.2, 366.2, and 366.3 and should not be changed.
  • The ten-year limitation on recovery of energy storage resource cost adopted in D.14-10-045 is not a violation of Public Utilities Code Sections 365.2, 366.2, and 366.3 and should not be changed in this proceeding because the proceeding has not addressed or resolved complex issues identified in D.14-10-045.

Reporting Requirements:

The PD would also require new reporting requirements for the RPS adder for CCA and ESPs.  This would include:

  • Contract information shall be collected for all LSE contracts executed in year n-2, with year n being the year from which the PCIA calculation is being done.
  • Contract information shall include: seller name, execution date, contract price ($/MWh), term length of contract, capacity (MW), associated New Quantifying Capacity (NQC), annual expected generation (MWh/year), expected generation for year n.
    • If a contract includes the Time of Delivery (TOD) adjustment, then the contract’s price shall be TOD-adjusted.
  • Energy Division shall collect this information in a common data template from each LSE by January 31, of year n-1 and calculate a weighted average RPS contract price ($/MWh) for RPS energy to be delivered in year n from contracts executed in year n-2.
  • This figure would be made available at the end of October of year n-1, like the brown [power] benchmark.

Annual True-Up

The PD would order the IOUs to file a Tier 2 advice letter to establish a Portfolio Allocation Balancing Account (PABA) with three subaccounts for the costs and revenues associated with the Brown Power Index, RPS adder, and RA adder and to modify it ERRA balancing account and any other account to be consistent with the PABA structure.  Any year end under collection or over collection would be incorporated into the PCIA rate calculation in the following year, as part of each IOU’s ERRA forecast proceeding, and accuracy will be reviewed during each IOU’s annual ERRA compliance proceeding.

Caps, Floors, Collars, and Sunsets

The PD declined to adopt a sunset on the obligations to pay the PCIA finding that Public Utilities Code Section 266.2(f)(2) bars the use of a sunset for CCA customer obligations vis a vis the “expiration of all then existing electricity purchase contracts.”  The PD also found that use of a sunset would reduce incentives for parties to actively participate in any allocation or auction that may take place in the second phase of Track II.

The PD would adopt a collar with a floor and cap.  The structure would be specified as follows:

  • Floor: Permanently set at zero.
  • Cap Level: Initial level set at 2.2 cents per kWh.
  • Collar: Annual change of the PCIA would be limited to 0.5 cents/kWh for any PCIA chage above 1.5 cents/kWh. If annual increase in the PCIA rate remains below that level, no caps shall be applied.

The IOUs would be required to file a Tier 2 advice letter to establish an interest bearing account that would be used if the cap is reached.  This would track any obligations that accrues for departing load customers.  Any balance would earn interest at the same rate earned by balances in the ERRA balancing account.

Pre-Payment of PCIA Obligations

The PD would allow DA customers and CCAs—on behalf of their customers—to pre-pay their PCIA obligations.  The PD determined that any pre-payment follow the framework that:

  • Pre-payment be based on a mutually acceptable forecast of that customer’s future PCIA obligation;
  • Pre-payment take the form of either 1) a one-time payment; or 2) a series of levelized payments over 2-5 years;
  • The Pre-payment would not be trued-up at a later date;
  • A customer who returns to bundled service would not receive any refund once pre-payment has been made; and
  • After pre-payment is finalized, the customer may switch between competitive retail sellers without incurring any new PCIA obligation.

The PD would require CPUC approval of any pre-payment agreement reached between counterparties submitted by the IOU counter party as a Tier 3 advice letter.  Each IOU would also be responsible for filing a Tier 2 advice letter to establish a balancing account to record all prepayments of PCIA obligations.

 

Future proceeding for Track 2 Phase II

The PD would order the opening of a Phase II to address allocation of excess resources through a working group process.  This would open hearings on CLECA’s voluntary allocation and auction clearing house proposal for further development. This would also continue work on forecasting, portfolio optimization, securitization, and the use of buy-down/buyouts.  A scoping memo on this would be forthcoming dependent on the disposition of this proposed decision by the Commission.

[1] CPUC R.17-06-026, Proposed Decision Modifying the PCIA Methodology, 8/1/18, p. 37.

Advertisements

About Joe Kaatz

Staff Attorney at the Energy Policy Initiatives Center, University of San Diego School of Law.
This entry was posted in Energy and tagged , , , , , , , , , , . Bookmark the permalink.

One Response to Summary of CPUC’s R. 17-06-026 Proposed Decision on Track 2 Power Charge Indifference Adjustment (PCIA) Proceeding

  1. Pingback: Update: Commissioner Peterman’s Alternative Proposed Decision on the PCIA | The EPIC Energy Blog

Leave a Reply

Fill in your details below or click an icon to log in:

WordPress.com Logo

You are commenting using your WordPress.com account. Log Out /  Change )

Google+ photo

You are commenting using your Google+ account. Log Out /  Change )

Twitter picture

You are commenting using your Twitter account. Log Out /  Change )

Facebook photo

You are commenting using your Facebook account. Log Out /  Change )

Connecting to %s