COM/CAP/avs ALTERNATE PROPOSED DECISION Agenda ID #16774 Alternate to Agenda ID #16734 ( REV. 2) Ratesetting 10/11/18 Item 37a Decision ALTERNATE PROPOSED DECISION OF COMMISSIONER PETERMAN (Mailed 8/14/2018) BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA Order Instituting Rulemaking to Review, Revise, and Consider Alternatives to the Rulemaking 17-06-026 Power Charge Indifference Adjustment. ALTERNATE PROPOSED DECISION MODIFYING THE POWER CHARGE INDIFFERENCE ADJUSTMENT METHODOLOGY 232140817 - 1 - R.17-06-026 COM/CAP/avs ALTERNATE PROPOSED DECISION (REV. 2) TABLE OF CONTENTS Title Page ALTERNATE PROPOSED DECISION MODIFYING THE POWER CHARGE INDIFFERENCE ADJUSTMENT METHODOLOGY ......................... 1 Summary ..................................................................................................................... 2 1. Background .......................................................................................................... 4 1.1. Procedural Background ............................................................................ 10 2. Issues Before the Commission .......................................................................... 12 2.1. Proposals ..................................................................................................... 16 2.1.1. Joint Utilities: Green Allocation Methodology and Portfolio Monetization Mechanism .................................... 16 2.1.2. AReM/DACC ................................................................................ 17 2.1.3. CalCCA ........................................................................................... 18 2.1.4. Commercial Energy ...................................................................... 20 2.1.5. TURN .............................................................................................. 23 3. Framework for Preparing this Decision .......................................................... 25 3.1. Statutory Framework ................................................................................ 26 3.2. Evidentiary Standards, the Burden of Proof, and the Burden of Production.................................................................. 30 4. Cost Shifts Under the Current Methodology ................................................. 32 4.1. “Brown Power” Market Price Benchmark ............................................. 34 4.2. RA Capacity Value .................................................................................... 36 4.3. Renewable Resources ................................................................................ 38 4.4. The Costs at Issue in this Proceeding...................................................... 39 5 Scope of PCIA-Eligible Resources and Costs ................................................. 44 5.1. Legacy Utility-Owned Generation .......................................................... 45 5.2. 10-Year Limitation on Recovery of Post-2002 UOG Costs ................... 54 5.3. 10-Year Limitation on Recovery of Energy Storage Resource Costs ............................................................... 60 6. Adopted Portfolio Valuation and Allocation Methodologies ..................... 61 6.1. Positions of the Parties .............................................................................. 62 6.2. Discussion ................................................................................................... 72 6.2.1. Revised Methodology for Calculating the Market Price Benchmark ....................................................... 73 6.2.1.1. New Reporting Requirements ........................................ 74 6.2.2. Annual True-up ............................................................................. 79 6.2.3. Caps, Floors, Collars and Sunsets ............................................... 80 - i - R.17-06-026 COM/CAP/avs ALTERNATE PROPOSED DECISION (REV. 2) TABLE OF CONTENTS Con’t. Title Page 6.2.3.1. Sunset of the Obligation to Pay the PCIA .................... 80 6.2.3.2. Should the Commission “Cap” the PCIA rate? .......... 82 6.2.4. Prepayment .................................................................................... 88 6.2.5. Review of Other Proposals .......................................................... 92 6.2.5.1. Joint Utilities ..................................................................... 92 6.2.5.2. CalCCA ............................................................................. 96 7. Phase 2 of this Proceeding: Portfolio Optimization and Cost Reduction ................................................................................................. 96 7.1. General observations ................................................................................. 97 7.2. Forecasting ................................................................................................ 104 7.3. Optimization ............................................................................................. 106 7.4. Securitization ............................................................................................ 107 7.5. Buydown/buyout .................................................................................... 110 7.6. Discussion ................................................................................................. 111 8. Other Issues ....................................................................................................... 117 8.1. Tariffs and Bill Presentation ................................................................... 117 8.2. Remaining Issues ..................................................................................... 119 9. Implementation ................................................................................................. 120 9.1. Calculation of the Revised PCIA ........................................................... 120 9.2. Rate Design ............................................................................................... 122 9.3. Annual True-up........................................................................................ 124 10. Conclusion: The Guiding Principles ........................................................... 127 11. Comments on Proposed Decision ................................................................ 130 12. Assignment of Proceeding ............................................................................ 153 Findings of Fact ...................................................................................................... 153 Conclusions of Law ............................................................................................... 156 ORDER ...................................................................................................................... 159 Appendix 1 Revised Formula for the Power Cost Indifference Adjustment (PCIA) Market Price Benchmark (MPB) - ii - R.17-06-026 COM/CAP/avs ALTERNATE PROPOSED DECISION (REV. 2) ALTERNATE PROPOSED DECISION MODIFYING THE POWER CHARGE INDIFFERENCE ADJUSTMENT METHODOLOGY Summary Communities throughout California are evaluating and launching Community Choice Aggregation (CCA) programs at a growing rate. CCA programs allow communities to provide electricity to customers within their boundaries, replacing the regulated electric utilities as their provider. In light of the growing trend toward formation of CCAs, the electric utilities subject to the jurisdiction of this Commission are experiencing a widening disparity between the level of resources in their portfolios and what is required to serve the reduced load after customers depart for CCA service. This customer movement has also led to corresponding changes in California’s electric procurement market as CCAs expand their portfolios, compounding the challenges of ensuring that customer departure from utility service is facilitated consistently with the statutory framework supporting CCA formation. That framework requires the Commission to ensure that departing customers remain responsible for certain costs incurred on their behalf by their utility, without being subject to costs that were not incurred on their behalf. Similar requirements govern other programs that allow some utility customers to engage in ‘direct access’ transactions for their electricity supply, again replacing utility supplies. This proceeding was initiated to respond to widespread concerns that the Commission’s existing cost allocation and recovery mechanism is not preventing cost shifting between different groups of customers, as required by law, and is therefore not in compliance with the statutory frameworks that (1) authorized customers to engage in direct access transactions for electricity and (2) provided for formation of CCAs. This decision refers to these customer groups collectively - 2 - R.17-06-026 COM/CAP/avs ALTERNATE PROPOSED DECISION (REV. 2) as ‘departing load customers’ and to the customers who continue to take service from their electric utilities as ‘bundled load customers.’ 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. In addition to the revised MPB inputs, this decision also adopts an annual true-up mechanism, as recommended by a number of parties, as well as a cap that will limit the change of the PCIA rate from one year to the next. The true-up will ensure that bundled and departing load customers pay equally for the above-market costs of PCIA-eligible resources. The cap will provide a degree of the rate stability and predictability sought by parties representing departing load interests. Finally, we take an additional step toward the simplicity and predictability requested by departing load customers by adopting an option for these customers to pre-pay their PCIA obligation. A second phase of this Rulemaking shall be initiated to enable parties to continue working together to develop longer-term solutions. This proceeding remains open. - 3 - R.17-06-026 COM/CAP/avs ALTERNATE PROPOSED DECISION (REV. 2) 1. Background The Commission opened this Order Instituting Rulemaking (OIR or Rulemaking) to review the current Power Charge Indifference Adjustment (PCIA). The PCIA that is in place today originated in statute enacted during the 2001 California energy crisis when the California Legislature passed Assembly Bill (AB) 1X. After finding that “a number of factors have resulted in a rapid, unforeseen shortage of electric power and energy available in the state and rapid and substantial increases in wholesale energy costs and retail energy rates, with statewide impact, to such a degree that it constitutes an immediate peril to the health, safety, life and property of the inhabitants of the state,” the Legislature declared that “the public interest, welfare, convenience and necessity require the state to participate in markets for the purchase and sale of power and energy.”1 AB 1X authorized the state Department of Water Resources (DWR) to enter into contracts for the purchase of electric power for delivery to retail customers of Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), and San Diego Gas & Electric Company (SDG&E). In the same legislation, the Legislature directed the Commission to suspend the right of customers to enter into direct access (DA) transactions with non-utility providers of electricity. It soon emerged that the new DWR contracts were extremely expensive relative to post-crisis electricity costs. This prompted many customers that had been returned to bundled service by their DA providers during the crisis to reverse course and resume DA service. The Commission noted that DWR had made purchases on behalf of these DA customers as well as those bundled 1 AB 1X ((Stats. 2001 (1st Extraordinary Sess.)), ch. 4.); codified at Water Code section 80000. - 4 - R.17-06-026 COM/CAP/avs ALTERNATE PROPOSED DECISION (REV. 2) service customers who later entered into DA contracts or arrangements.2 For this reason, the Commission determined that there would be a significant magnitude of cost-shifting if energy crisis costs were borne solely by bundled service customers but DA customers were not required to pay a portion of these costs.3 For these reasons, the Commission ordered that “direct access surcharges or exit fees shall be developed […] so that there is an equitable allocation of the DWR costs and other costs that may be considered, and that direct access customers pay their fair share of DWR costs and non-DWR costs and bundled service customers are indifferent.”4 The Commission then adopted a “cost responsibility surcharge” (CRS) intended to recover the relevant costs covered by its directive. As initially adopted by the Commission, the CRS incorporated (1) a DWR power charge to collect ongoing contract costs, (2) a DWR Bond Charge to pay for significant costs incurred during the height of the crisis, and (3) an ongoing competition transition charge (CTC) whose purpose was to recover statutorily-authorized costs related to the restructuring of California’s electric industry that occurred prior to the energy crisis.5 Also, in 2002 the Legislature passed, and the Governor signed into law AB 117, which authorized the creation of Community Choice Aggregators (CCAs). CCAs are governmental entities formed by cities, counties, or a 2 Decision (D.) 02-03-055 at 9-10. The Commission noted that direct access share of total utility load dropped to about 2% by June 2001, then reversed such that between July 1, 001 and September 20, 2001, approximately 11% of the total electric load of the utilities had shifted from bundled service to direct access service. 3 Id., Finding of Fact 3. 4 Id., Ordering Paragraph 3, as modified by D.02-04-067. 5 D.02-11-022 at 3-4. - 5 - R.17-06-026 COM/CAP/avs ALTERNATE PROPOSED DECISION (REV. 2) combination of cities and counties, to serve the energy requirements of their local residents and businesses. AB 117 clarified Legislative intent regarding cost recovery and cost shifting by adding Section 366.2(d)(1) to the Public Utilities Code, describing it as “declaratory of existing law:” It is the intent of the Legislature that each retail end-use customer that has purchased power from an electrical corporation on or after February 1, 2001, should bear a fair share of the [DWR’s] electricity purchase costs, as well as electricity purchase contract obligations incurred as of the effective date of the act adding this section, that are recoverable from electrical corporation customers in commission-approved rates. It is further the intent of the Legislature to prevent any shifting of recoverable costs between customers. The Commission acknowledged this legislative intent in its decisions implementing AB 117, but also articulated a counterbalancing precept that continues to guide Commission policy-making: The objective of AB 117 in requiring CCAs to pay a CRS is to protect the utilities and their bundled utility customers from paying for the liabilities incurred on behalf of CCA customers. Our complementary objective is to minimize the CRS (and all utility liabilities that are not required) and promote good resource planning by the utilities.6 These basic principles regarding overall cost minimization and prevention of cost shifts between customers have remained in place since the beginning of legislative and Commission efforts to equitably address the cost responsibility issues regarding departing load. However, more recent legislative direction reemphasizes that the Commission must ensure equity on both sides of the 6 D.04-12-046 at 29. - 6 - R.17-06-026 COM/CAP/avs ALTERNATE PROPOSED DECISION (REV. 2) departing load transaction, that is, for departing load as well as remaining bundled investor-owned utility (IOU) load. In 2011, Senate Bill (SB) 790 added the requirement that the cost responsibility of CCA customers shall be reduced by the value of any benefits that remain with bundled service customers, unless the CCA customers are allocated a fair and equitable share of those benefits.7 Most recently, in 2015, SB 350 added Sections 365.28 and 366.39 to the Public Utilities Code, which make explicit the dual requirements that (1) bundled service IOU customers do not experience any cost increases when other retail customers elect to receive service from other providers, or due to the implementation of a CCA program, and (2) customers who depart for another provider or due to formation of a CCA do not experience any cost increases due to an allocation of costs that were not incurred on behalf of the departing load:10 7 Stats. 2011, ch. 599 (amending Pub. Util. Code § 366.2). 8 Section 365.2 provides that: The commission shall ensure that bundled retail customers of an electrical corporation do not experience any cost increases as a result of retail customers of an electrical corporation electing to receive service from other providers. The commission shall also ensure that departing load does not experience any cost increases as a result of an allocation of costs that were not incurred on behalf of the departing load. 9 Section 366.3 provides that: Bundled retail customers of an electrical corporation shall not experience any cost increase as a result of the implementation of a community choice aggregator program. The commission shall also ensure that departing load does not experience any cost increases as a result of an allocation of costs that were not incurred on behalf of the departing load. 10 Stats. 2015, ch. 547. - 7 - R.17-06-026 COM/CAP/avs ALTERNATE PROPOSED DECISION (REV. 2) These statutory developments have been paralleled by increased interest in PCIA matters by parties participating in Commission proceedings. The Commission’s efforts to implement legislative intent reached an initial period of stability in 2006, when the Commission replaced the original CRS with the current PCIA-based methodology.11 As the Commission explained, The PCIA is intended to preserve the indifference concept adopted in D.02-11-022 for DA customers who pay the DWR power charge component of CRS. To accomplish this intent, the cost responsibility for ongoing CTC and the PCIA charge for DA customers who pay the DWR power charge would equal their responsibility under the indifference rate concept [plus recovery of franchise fees].12 The PCIA-based methodology reflected a consensus recommendation of IOU, direct access and customer-group parties active at that time. Its central feature was a revised calculation of the required ‘indifference amount’ that compared each utility’s total power portfolio costs, expressed in cents/kWh, to a market benchmark comprised of the posted forward prices for a one-year strip of power for the coming year, plus a capacity adder to reflect the cost of resource adequacy (RA). In this manner, the RA benefits of generation resources acquired to meet system or local area reliability needs were reflected in the value allocated among customers. The Commission subsequently adopted two additional refinements to the PCIA methodology, resulting in the current version that we review in this decision. First, D.11-12-018 adopted a revised capacity adder and increased the market price benchmark by adding a renewable procurement standard (RPS) 11 See, D.06-07-030. 12 Id. at 25. - 8 -