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California Utilities, Retail Suppliers Offer Proposals On Allocating Utility Supply Costs To Competitive LSEs For Departing Customers

April 4, 2018

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Copyright 2010-17 EnergyChoiceMatters.com
Reporting by Paul Ring • ring@energychoicematters.com

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Stakeholders filed testimony with the California PUC concerning the allocation of supply costs, incurred by utilities to serve bundled service customers, to competitive suppliers when such customers depart the utility for a competitive LSE, via charges or alternatives to the current Power Charge Indifference Adjustment (PCIA)

The joint utilities (PG&E, SCE, and SDG&E) proposed an alternative to their original Portfolio Allocation Methodology (PAM) proposed earlier in the proceeding.

Under the utilities' latest proposal, "Rather than allocating the entirety of the Joint Utilities’ respective portfolio attributes to all LSEs as proposed in PAM, the Joint Utilities now propose to allocate only 'green' resource attributes associated with RPS-eligible resources and large hydro-electric resources, while monetizing other 'brown' resource attributes based on actual market outcomes, subject to a true-up. This modification is intended to be responsive to CCAs’ desire to build 'green' portfolios and to avoid a need to allocate 'brown' resource attributes to them."

"The Joint Utilities propose to replace the Current Methodology with a new cost recovery framework that consists of two parts: The Green Allocation Mechanism (GAM), and the Portfolio Monetization Mechanism (PMM). The GAM, which applies to RPS-eligible and large hydro-electric facilities, retains the concept of a pro rata allocation of net costs and benefits that the Joint Utilities first proposed in their PAM Application. GAM is also methodologically similar to the CAM adopted by the Commission in D.06-07-029,29 whereby the benefits of the generation resources (e.g., enhanced system reliability and capacity that is applied towards each LSE’s RA requirements) are shared equitably by all customers, and the 'net costs,' defined as the total cost of the resource less the energy revenues associated with the dispatch of the resource, are also shared equitably by all customers," the utilities said

"Because RPS-eligible and large hydro-electric resources will be critical resources to meet California’s policy objectives, and calculating separate REC, RA, energy, and ancillary services values over time in an environment of changing market dynamics for such resources cannot be done accurately or without harming California’s market operations, allocating portfolio attributes and net costs of these resources will ensure that all customers equitably benefit and pay for these important resources," the utilities said

"Under the Joint Utilities’ Proposal for GAM, the costs recovered from departing load customers will equal the actual pro rata costs incurred (e.g., contract costs owed to the generators, UOG [utility-owned generation] capital costs, variable Operations & Maintenance costs, and California Independent System Operator generation-related charges), less the actual pro rata revenues received from the markets for those resources (e.g., energy and ancillary services (A/S) revenues)," the utilities said

"The PMM, which applies to nuclear, gas, and energy storage resources, is similar to the Current Methodology in that it does not allocate portfolio attributes but instead only collects the pro rata share of the above-market costs of the PMM resources from departing load customers. However, unlike the Current Methodology, which relies on administratively-set benchmarks to estimate the above-market costs of the portfolio, PMM uses actual market transactions to calculate the cost responsibility of departing load customers. Under PMM, the cost recovered from departing load customers will equal their pro rata share of the above-market costs of the PMM portfolio (i.e., actual incurred costs, less the actual energy and A/S revenues received from the markets for those resources and the actual value of the RA capacity as determined in an annual RA sales process)," the utilities said

"While the initial rates for both the PMM and GAM portions of the portfolio will be set in the Joint Utilities’ respective annual Energy Resource Recovery Account (ERRA) Forecast proceedings based on a forecast of costs and offsetting market revenues (forecast net resource costs), those rates will be trued-up annually based on actual portfolio 1 performance and realized market revenues (actual net resource costs), as well as billed revenues (i.e., sales) received from customers. This method ensures that all customers pay their actual pro rata share of the net resource costs for which they are responsible," the utilities said

"Under GAM, the costs and benefits of clean energy resources are directly allocated to LSEs, thereby avoiding the use of inaccurate and imprecise benchmarks and ensuring the use of these policy-preferred resources in meeting all customers’ needs," the utilities said

"The Joint Utilities’ Proposal efficiently and rationally allocates existing IOU RPS commitments to all LSEs on a load-share basis, ensuring that all customers continue to benefit from their IOU’s RPS commitments and pay their equitable share of such resources. This proposal optimizes existing RPS resource commitments already approved by the CPUC, while still allowing CCAs an opportunity to add new RPS resources to their portfolios. Importantly, the GAM avoids the potential for unnecessary double-procurement of long-term RPS resources to meet SB 350 requirements," the utilities said

"In contrast to GAM, PMM provides a means to quantify the actual above market costs of resources with attributes that are transacted in relatively-liquid markets, thereby completely eliminating the need to allocate and/or benchmark the benefits of gas, nuclear, and energy storage resources," the utilities said

"The Joint Utilities’ Proposal results in both departing load customers and remaining bundled service customers paying the same above-market and net costs, on a per-kilowatt-hour basis, for each PMM and GAM resource, respectively, for which they are collectively responsible, thus ensuring customer indifference as required by law," the utilities said

A witness for the Alliance for Retail Energy Markets (AReM) and the Direct Access Customer Coalition (DACC) offered the following recommendations.

AReM and DACC's witness first recommended that IOUs should be directed to liquidate, sell forward, or take other appropriate steps to address the above-market (stranded) costs associated with their current out-of-market resources that are in excess to the resources needed to serve their bundled load.

For resources in the IOUs portfolios that cannot be liquidated per the first recommendation, AReM and DACC's witness recommended that some elements of the Market Price Benchmark, (MPB) be modified as follows:

• The use of forward market quotes for the energy component ("brown energy") of the MPB is reasonable and should be continued.

• With respect to the Capacity Adder, the witness noted that establishing the appropriate metric for the Capacity Adder in the MPB is difficult, especially with the current significant load migration. AReM and DACC's witness suggested an approach that ties the Capacity Adder to Commission determination of capacity need. If the Commission determines that new capacity resources are needed within the next three years, then the full annualized fixed cost of a combustion turbine (CT), including capital and operating costs, could be used. This value would be taken from the California Energy Commission’s most recent Cost of New Generation Report. If the need for new capacity is projected to be four years or more in the future, then the going forward (operating) cost of a new CT could be used (e.g., the status quo).

• The current Renewable Portfolio Standard (RPS) Adder element of the MPB is unreasonable and should be replaced to reflect a price index for a Portfolio Content Category (PCC) Renewable Energy Credit (REC) from Platts or other industry standard publication.

AReM and DACC's witness further recommended that the Commission allow a DA customer to choose to pre-pay its PCIA obligation under the following terms.

• Pre-payment would be based on a mutually acceptable forecast of that customer’s future PCIA obligation.

• Pre-payment could be either (a) one-time, or (b) a series of levelized payments over 2 to five years.

• Pre-payment would not be trued-up.

• Once the pre-payment has been made, the customer would not receive any refunds if it returns to bundled service.

• Once paid, the customer could switch among competitive retail sellers without incurring any new PCIA obligation.

AReM and DACC's witness further recommended that the Commission institute a cap on the PCIA, similar to the 2.7¢/kWh Cost Responsibility Surcharge (CRS) Cap that was in place during the mid-2000’s as follows:

• The cap should be initially set at a 2.2¢/kWh.

• If a DA or CCA customer returns to bundled service while an under-collection balance exists, that customer would continue to pay a 'PCIA under-collection amount' until its vintage’s PCIA under-collection is fully remitted.

• If the calculated PCIA exceeds the cap for 3 successive years, the IOU may request an increase in the level of the cap to up to an amount such that the under-collection would be projected to be paid down in 3 years.

AReM and DACC's witness further recommended that DA customers in the current pre-2009 vintage tranche that have paid their stranded cost obligations should be permanently exempted from any PCIA or successor tariff going forward.

Commercial Energy separately offered a strawman proposal for determining the PCIA called the Voluntary Allocation & Auction Clearinghouse or VAAC.

The VAAC allocation process would be quarterly for energy and RPS, and annual for RA, consistent with the PAM proposal. The fundamental difference is the VAAC proposal would allow LSEs to voluntarily assume assets and benefits that make sense for their portfolio, customers, and business needs.

Under the Commercial Energy VAAC proposal, 45 days before the beginning of each quarter, the IOU will issue an allocation percentage to each LSE based on forecast customer load in that quarter. The IOU will have sorted its generation assets into the same 'pools' addressed in a Modified NDA to permit disclosure to market participants of aggregated generation resource data in this proceeding: five resource categories (fixed solar, tracking solar, wind, natural gas, and other) with no fewer than five contracts per pool. Ideally, the IOUs will also be able to add the additional RPS, RA, and ancillary benefits to the generation pools, Commercial Energy said

The five resource types and three categories of benefits would yield eight pools of resources to be allocated and auctioned through the VAAC. The pools will ensure the IOUs’ contracts retain anonymity. The Allocation process will require the participation of the LSEs’ market-participant members, including the marketing arm of the IOUs, which will automatically be allocated 100% of the IOUs’ proportionate share of the contracts each quarter. The allocation percentage for each LSE and the IOU is the entity’s current market share.

Under the Commercial Energy VAAC proposal, after the pools with the aggregated information are produced by the IOU, each LSE would then select up to 100% of the volume of generation allocated to it for the upcoming quarter at the utilities’ cost. The un-used balance of each LSE’s allocation volume would go back into the general pool for the subsequent Auction process. If the LSEs agreed to take 100% of the pool contents, there would be no PCIA costs for those assets for that period and therefore no PCIA charges to that LSE’s customers.

The Allocation portion of the VAAC methodology has three main components. The first is the percentage of the proportional allocation from each of the five resource pools that the LSE chooses to accept. The total available allocation is the total PCIA contracts multiplied by the LSE’s market share. The second component is the price paid by the LSE for the percentage of the allocation that it has agreed to take. The third component is the dollar amount credited to the LSE’s customers to offset the PCIA they would have been responsible for through the ERRA forecast

Under the Commercial Energy VAAC proposal, after each LSE has exercised its option to assume its proportionate share of the allocated contracts, as described above, the balance of the resources will be put into an Auction.

The Auction portion of the VAAC proposal has four major components. First is the weighted average auction price. The second component is the percent of the remaining energy that each LSE successfully bids on. This produces the third component, which is the MWh sold at auction. The final component is the Auction Results. The aggregated Auction Results will yield the market value for the PCIA assets for the quarter.

Unlike the Allocation process, where the LSE can only accept up to the maximum resources that were proportionally allocated to its account, in the Auction process each market participant with customers in the IOU’s service territory can bid on as much of any bucket as they choose. This would include the IOUs.

It is important to note that Commercial Energy proposes that the energy produced by and all the valuable assets belonging to a particular generation resource will be allocated (or auctioned) to the LSE, but this will not be a formal assignment of the Power Purchase Agreement (PPA).

As such, none of the winning bidders will have any effect on the dispatch stack managed by the CAISO, so there is no risk of market manipulation by the owners of the resources (unlike the ill-fated Power Exchange during the Energy Crisis of 2000- 2001), Commercial Energy said. As the IOUs would still hold the contracts and still manage dispatch pursuant to the Commission’s Standard of Conduct 4 (SOC 4) Least Cost Dispatch requirements, market manipulation would not be a concern, Commercial Energy said

Rulemaking 17-06-026

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