Details for: SCE's Protest Response to Advice 3914-E.pdf


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Gary A. Stern, Ph.D.
Managing Director, State Regulatory Operations

January 8, 2019
Energy Division
Attention: Tariff Unit
California Public Utilities Commission
505 Van Ness Avenue
San Francisco, CA 94102

SUBJECT:

Response of Southern California Edison Company to California
Community Choice Association (CalCCA) Protest to Southern
California Edison Company’s Advice Letter 3914-E

Dear Energy Tariff Division Unit:
The December 31, 2018 CalCCA Protest to Southern California Edison Advice Letter
3914-E (CPA Protest) is without merit and should be afforded no weight.
Background
On October 11, 2018, the Commission approved Decision (D.)18-10-019 (the Decision),
which adopted modifications to the “Indifference” methodology used to set the
Competition Transition Charge (CTC) and Power Charge Indifference Adjustment
(PCIA) rates. On December 10, 2018, in compliance with the Decision, Southern
California Edison Company (SCE) submitted Advice Letter (Advice) 3914-E,
establishing the Portfolio Allocation Balancing Account (PABA) and modifying its Base
Revenue Requirement Balancing Account (BRRBA) and Energy Resource Recovery
Account (ERRA). CalCCA submitted a protest to Advice 3914-E on December 31,
2018. SCE hereby responds to CalCCA’s protest (Protest).
Response to CalCCA Protest
A. The Scope of Advice 3914-E is Appropriate
The purpose of Advice 3914-E is to comply with Ordering Paragraphs (OP) 7 and 8 of
the Decision and establish and modify ratemaking accounts to ensure that all
generation-related costs, revenues, and billed revenues are appropriately recorded.
The Preliminary Statements presented in Advice 3914-E provide the necessary detail to

P.O. Box 800

8631 Rush Street

Rosemead, California 91770

(626) 302-9645 FAX (626) 302-6396





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Energy Division Tariff Unit California Public Utilities Commission January 8, 2019 Page 2 implement the Decision’s directives and true-up all elements1 of the CTC and PCIA, with the exception of the true-up of the Resource Adequacy (RA) and Renewable Energy Credit (REC) benchmarks, which is deferred to Phase 2 of R.17-06-026.2 As a general matter, SCE disagrees with CalCCA’s assertion that the directive in OPs 7 and 8 is limited to “setting up the account and subaccount structure,”3 and that it is “premature to seek approval of any element of a PCIA true-up calculation methodology.”4 The Decision clearly: 1. defines the “above-market costs” of resources that must be paid for by both bundled service and departing load customers;5 2. provides a methodology for forecasting those above-market costs on a yearahead basis for purposes of setting the PCIA rates;6 3. orders the utilities to establish the PABA to record the actual above-market costs of those resources and billed revenues received from customers;7 and 4. starting in 2019, authorizes the retrospective “true-up” of the PCIA rates based on the recorded balance in the PABA.8 It is thus inaccurate for CalCCA to claim that the Decision does not “address how the values recorded in the accounts would be used in the calculation of the PCIA.”9 On the contrary, the definition of above-market costs established in the Decision dictates what costs and revenues are to be recorded in the account and recovered from customers. However, consistent with historical Commission precedent and standard ratemaking practice, the Decision deferred the details of the accounting procedures and specific accounting entries to this advice letter process. In other words, this advice letter 1 2 3 4 5 6 7 8 9 Specifically, D.18-10-019 provides for the true-up of generation quantities and energy and ancillary services revenues (commonly referred to as the “brown power” true-up), resource costs, revenues received from bilateral transactions, and billed customer revenues, and defers the true-up of the RA and REC benchmarks to Phase 2 of the Proceeding. Additionally, SCE notes that its preliminary statements are consistent with the structure proposed on pages 4-53 to 4-60 of the Joint Utilities’ direct testimony, but have been modified to reflect that RA and RECs are valued at the Commission-prescribed benchmarks in D.18-10-019 instead of allocated directly to departing load customers’ Load Serving Entities (LSEs). As noted in Advice 3914-E, the Imputed RA and REC revenues and costs entries will be modified upon final resolution of the issue in Phase 2 of R.17-06-026. CalCCA Protest at p. 2. Id. See the Decision at OP 1, page 142, and Appendix 1. See the Decision at OPs 1 and 2. See the Decision at OP 7. See the Decision at page 142, which adopts the Alliance for Retail Energy Markets/Direct Access Customer Coalition’s “limited true-up” of costs, “actual market prices, sales volumes, and PCIA revenue collections,” and defers the determination of the RA and REC benchmark true-up to Phase 2 of R.17-06-026. CalCCA Protest at pp. 2-3.
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Energy Division Tariff Unit California Public Utilities Commission January 8, 2019 Page 3 process, and not Phase 2 of R.17-06-026, is the appropriate venue for describing and defining the specific costs and revenues that are to be recorded in PABA. If CalCCA’s Protest were meritorious, the enormous efforts and resources the Commission and many parties expended over many months in Phase 1 would have accomplished very little. Advice 3914-E is neither over-broad nor beyond the scope of issues that should be considered. B. SCE’s “allocation of billed revenues” does not “allocate costs between ERRA and PABA” CalCCA incorrectly characterizes SCE’s “allocation of billed revenues” to the various ratemaking accounts as an attempt to separate bundled service and departing load “costs.” 10 CalCCA points to Pacific Gas and Electric (PG&E’s) Advice Letter 5440-E as having properly “confin[ed] all PCIA-eligible costs to the PABA sub-accounts” and notes that no “monthly allocation” of billed revenues is necessary under PG&E’s approach. In reality, as discussed in more detail below, SCE’s approach is completely consistent with PG&E’s approach, and thus no modifications to SCE’s Preliminary Statements are necessary. As described on page 3 of Advice 3914-E, all costs, market revenues, and imputed market revenues associated with SCE’s Eligible Resources will be recorded, or “confined,” to PABA. The sum of those entries represent the PABA revenue requirement, or the “above-market” costs of the portfolio as defined by D.18-10-019, that is used to determine the PCIA rates that both departing load and bundled service customers pay. Those PCIA rates, which collect the above-market costs of the historical generation portfolio, are combined with the ERRA and BRRBA generation rates, which collect the costs of meeting the bundled service customers’ generation service requirements, to set the final generation rates that bundled service customers must pay. The process for allocating billed revenues described in Advice 3914-E is simply the means to ensure that the PCIA portion of the generation revenues collected from bundled service customers is recorded to PABA, while the ERRA and BRRBA portions of the generation revenues are recorded to ERRA and BRRBA. An overview of this process is described on page 4-60 and Appendix D of the Joint Utilities’ Direct Testimony in R.17-06-026, was uncontested by parties, and was adopted by the Commission in the Decision.11 Unlike PG&E, whose billing systems are able to allocate billed revenues to various balancing accounts using cent-per-kWh rates,12 SCE must allocate billed revenues to balancing accounts using percentage allocators. With Commission approval, SCE uses this process today to separate and direct bundled service generation billed revenues 10 11 12 CalCCA Protest at p. 2. See the Decision at page 126 and Finding of Fact 17. See page 5 of PG&E’s Advice 5440-E and PG&E’s Preliminary Statement I.
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Energy Division Tariff Unit California Public Utilities Commission January 8, 2019 Page 4 into the ERRA and BRRBA, and is described in the definition sections of those Preliminary Statements. Advice 3914-E’s explanation of how billed revenues will be directed into the various sub-accounts of PABA, ERRA, and BRRBA is simply an extension of that existing process. Additionally, SCE’s method of using percentage allocators, calculated using the average cent-per-kWh rate of each account, to determine how much billed revenue is recorded to each account, is mathematically the same as using cent-per-kWh rates to total kWh usage.13 Most importantly, SCE’s allocation of billed revenues methodology ensures that both bundled service and departing load customers contribute the same rate towards the recovery of the abovemarket costs for which they are all responsible, as can be seen in Appendix B of Advice 3914-E. C. Advice 3914-E does not pre-judge the mechanics of the RA and REC benchmark true-up CalCCA incorrectly claims that SCE’s Imputed RA revenues definition pre-judges the result of the RA and REC benchmark true-up process in Phase 2 of the PCIA OIR. Specifically, CalCCA takes issue with SCE’s use of the terms “untransacted” and “buffer,” and notes that PG&E did not incorporate those terms in its Advice 5440-E. As described in Advice 3914-E, the “untransacted” RA, i.e., any unsold RA in SCE’s portfolio, will be multiplied by the Commission-adopted RA benchmark to calculate the Imputed RA revenues that will be recorded in PABA. This definition of the volume of RA to multiply by the benchmark is wholly consistent with the Commission’s use of the term on pages 141 and 142 of the Decision. Moreover, as clarified in a data request response to CalCCA, the RA compliance requirement and buffer are irrelevant to the Advice Letter’s definition of “untransacted.”14 Finally, SCE’s and PG&E’s Imputed RA revenues definitions are the same – i.e., the benchmark price established by the 13 14 For example, assume the PCIA rate is 4¢/kWh, the ERRA rate is 6¢/kWh, and the BRRBA rate is 0 ¢/kWh, and a customer uses 500 kWh. The total generation rate is 10¢/kWh, and the total generation bill for this customer is $50. Using SCE’s “percentages approach,” 40% (4¢ / 10¢) of the $50, or $20, is allocated to PABA, while 60% (6¢ / 10¢) of the $50, or $30, is allocated to ERRA. This is mathematically the same as multiplying 4¢/kWh by 500 kWh to determine the billed revenues that should be recorded to PABA, and 6¢/kWh by 500 kWh to determine the billed revenues that should be recorded to ERRA. SCE’s response to CalCCA’s data request on this issue was provided on December 26, 2018 (a copy of which is included in this response in Attachment A), and provided the following example: Assume the PABA portfolio in a given month has 10,000 MW of RA, and that 500 MW has been sold to a counterparty through a bilateral transaction. Additionally, assume SCE’s RA compliance requirement for that month is 7,000 MW, and SCE retains another 200 MW as a buffer. The entire “untransacted” 9,500 MW (i.e., irrespective of SCE’s compliance requirement of 7,000 MW or the buffer of 200 MW) will be multiplied by the CPUC-approved RA benchmark to set the PCIA rate.
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Energy Division Tariff Unit California Public Utilities Commission January 8, 2019 Page 5 Commission multiplied by the RA that remains in the portfolio.15 CalCCA’s concerns are thus unfounded and should be rejected. D. It is appropriate to record a share of indirect costs in PABA CalCCA protests SCE’s treatment of indirect costs by suggesting that it goes “beyond the boundaries of the Commission’s directives” and proposes that the issue be resolved in Phase 2 of R.17-06-026. SCE disagrees and believes that the matter of indirect costs can and should be fully resolved now. CalCCA does not deny that any of the indirect costs listed in Advice 3914-E are necessary for the operation of the Eligible Resources. As noted in Advice 3914-E, those indirect costs are incurred on a portfolio basis for the operation of SCE’s entire generation portfolio, but will be exclusively borne by bundled service customers if they continue to be recorded solely in ERRA. For example, certain indirect gas delivery costs (e.g., pipeline charges and imbalance penalties) are necessary for the operation of the gas-fired Eligible Resources, and thus are logically no different from the actual cost of the gas commodity burned by the unit to generate electricity. However, because these costs are incurred on a portfolio basis (i.e., to support all gas-fired resources in SCE’s portfolio, including those in SCE’s Cost Allocation Mechanism portfolio), only an allocated portion of those costs is attributable to the gas-fired resources in the PCIA portfolio. Advice 3914-E provides a simple and straightforward methodology for allocating such indirect portfolio costs to Eligible Resources. As demonstrated at the December 19, 2018 Pre-Hearing Conference, the Commission and parties have a lot of ground to cover in Phase 2 of R.17-06-026. SCE does not recommend further expanding the scope of Phase 2 to review these miscellaneous indirect costs. These indirect costs, which are listed in SCE’s existing ERRA Preliminary Statement ZZ, are authorized for recovery today16 and enable the operation of Eligible Resources. They should thus be treated just like direct costs and recorded in PABA. E. CalCCA’s request that Utility Owned Generation (UOG) resources be tracked separately from contracted resources is unnecessary and should be denied CalCCA requests that SCE segregate the costs of its UOG from its other Eligible Resources. Segregation is unnecessary, as D.18-10-019 unequivocally found that departing load customers’ responsibility for utility-owned resources is no different from their responsibility for contracted resources. Additionally, because cost and market 15 16 See PG&E Advice 5440-E at p. 5 and SCE Advice 3914-E at pp. 5-6 SCE’s response to CalCCA’s data request on the indirect costs that have historically been included in the PCIA was provided on December 26, 2018 (a copy of which is included in this response in Attachment A).
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Energy Division Tariff Unit California Public Utilities Commission January 8, 2019 Page 6 revenues accounting entries are made at the resource level, UOG above-market costs can be identified without having to segregate them into a separate sub-account. Thus, there is no basis for CalCCA’s request, and it should be denied. Conclusion For the foregoing reasons, SCE respectfully requests the Commission approve Advice Letter 3914-E and disregard CalCCA’s Protest. Sincerely, /s/ Gary A. Stern, Ph.D. Gary A. Stern, Ph.D. GAS:dw:jm Enclosure cc: Edward Randolph, Director, CPUC Energy Division Dorothy Duda, CPUC Energy Division Evelyn Kahl, CalCCA Service List R.17-06-026
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Attachment A
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Southern California Edison Power Charge Indifference Adjustment OIR R.17-06-026 DATA REQUEST SET R.17-06-026 CalCCA-SCE-007 To: CALCCA Prepared by: Desiree Wong Title: Sr. Advisor Dated: 12/14/2018 Question 1-15: The Advice Letter refers on page 5-6 to “untransacted” RECs and RA and specifies that they include “any RA capacity that is in excess of SCE’s compliance requirements plus a buffer.” Are you proposing through this Advice Letter that the Commission approve a calculation methodology related to untransacted RECs and RA? Or will these calculation methodologies be determined in Phase 2? a. b. c. If you are proposing a calculation methodology, please explain the nature of a REC or RA buffer. Please explain how a REC or RA buffer will be calculated. Please explain whether bundled or departing load customer will bear the cost of the buffer as insurance against compliance shortfalls, and will the costs of the buffer be recorded in the ERRA or PABA? Response to Question 1-15: Untransacted RECs and RA refer to any PABA RECs and RA that have not already been bilaterally transacted with another party. As described in SCE’s Advice Letter, the actual quantity of untransacted RECs and RA will be multiplied by the CPUC-approved RA and REC benchmarks to determine the Imputed RA and REC Revenues entries in PABA and Imputed RA and REC Costs entries in ERRA. For example, assume the PABA portfolio in a given month has 10,000 MW of RA, and that 500 MW has been sold to a counterparty through a bilateral transaction. Additionally, assume SCE’s RA compliance requirement for that month is 7,000 MW, and SCE retains another 200 MW as a buffer. The entire “untransacted” 9,500 MW (i.e., irrespective of SCE’s compliance requirement of 7,000 MW or the buffer of 200 MW) will be multiplied by the CPUC-approved RA benchmark. In other words, the compliance requirement and buffer are irrelevant to the Advice Letter’s definition of “untransacted.” a. N/A b. N/A.
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c. N/A.
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Southern California Edison Power Charge Indifference Adjustment OIR R.17-06-026 DATA REQUEST SET R.17-06-026 CalCCA-SCE-007 Supplemental To: CALCCA Prepared by: Desiree Wong Title: Sr. Advisor Dated: 12/27/2018 Question 1-5: CalCCA 1-5. Please specify whether the following cost categories have historically been recovered through the PCIA rate and, if so, identify the Commission decision, including page-specific citations, authorizing such recovery: a. Gas-related costs, including but not limited to, pipeline charges, imbalance penalties, and gains or losses related to the sale of unallocated gas. b. Credit and collateral interest costs c. Western Renewable Energy Generation Information System Costs d. Independent Evaluator costs Response to Question 1-5: An allocated share of the forecast gas transportation (a) and credit and collateral interest (b) costs have historically been recovered through the PCIA (the allocated share included in PCIA on a forecast basis was approximately $2M per year in 2018 and 2019). Those costs are necessary for the operation of the generation portfolio, and are authorized for recovery in ERRA in Preliminary Statement ZZ. SCE has included these forecast costs (and source data tying to its ERRA Chapter 4 tables) in the “Common” category of its workpapers. The Commission has approved those calculations as being compliant. Imbalance penalties and gains or losses related to the sale of unallocated gas (a), WREGIS (c), and Independent Evaluator (d) costs are not forecast in the ERRA Forecast proceeding, but are simply recorded as they are incurred in the ERRA balancing account. They have not been historically been recovered through the PCIA because they were not forecast in the ERRA Forecast proceeding. For reference, SCE notes that these costs totaled less than $1.2M in 2017. As described in SCE’s advice letter, only an allocated share of these costs will be recorded in PABA and recovered through the PCIA.
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