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1(e.g., current cellphone plans that combine data and calling into one monthly rate) in addition to2automated load response for bill management and grid support.Phase 1 of the pilot ran from 2016 to 2019. Through the pilot, SCE learned about the essential34elements needed for the successful deployment of such a technology-based dynamic price platform.5Namely, this pilot illustrated that successful implementation of dynamic prices requires enhanced6technology interfaces between the DSO, the ISO, and the customer’s energy management system that7communicate in real time. In addition, communication protocols for both metered load and price8information must be standardized and designed with sufficiently robust security parameters.17Phase 2 of the RATES pilot is expected to begin in the Summer of 2022 and extend through the910Summer of 2024. This phase of the pilot was proposed by SCE in Phase 2 of the Reliability proceeding,11R.20-11-003, and recently approved in the Commission’s December 6, 2021 decision, D.21-12-015, that12takes several demand-side and supply-side measures to reliably meet load needs in 2022 and 2023.1813While SCE is still in the process of fully scoping out this phase of the pilot, D.21-12-015 orders SCE to14“conduct a mid-term and final evaluation of the pilot to assess the costs and benefits of real-time rates,15including required infrastructure, manufacturer interest, and customer impacts. The mid-term report16shall be released no later than December 31, 2023, and a final evaluation shall be released no later than17March 1, 2025.”19 More specifically, SCE’s evaluation must include the following elements:171819The knowledge gained from SCE’s participation in this TeMIX pilot subsequently helped inform the EnergyDivision’s RTP framework (UNIDE), which Energy Division described in its May 25, 2021 workshop onAdvanced DER and Demand Flexibility Management. See “Forward Looking Vision: Advanced DERs &Demand Flexibility Management,” Aloke Gupta, DR Section, Energy Division, May 25, lexibility-management/slides-unideworkshop gupta.pdf, pp. 38, 39, 45.D.21-12-015, Phase 2 Decision Directing Pacific Gas and Electric Company, Southern California EdisonCompany, and San Diego Gas & Electric Company to Take Actions to Prepare for Potential Extreme Weatherin the Summers of 2022 and 2023, December 6, 2021, pp. 96-99 and Ordering Paragraphs (OPs) 59-63.Id., p. 99.6

11. An evaluation of load responsiveness. SCE should evaluate the efficacy of the pilot tariff2in shifting loads enrolled in the program from peak to off-peak periods and should be3compared to non-participant loads;2. The monthly bill impacts of the pilot dynamic rate in comparison to a customer’s4otherwise applicable tariff; and53. An evaluation of the cost recovery which assess[es] the impact of any under-collection of67revenues associated with the pilot similar to the evaluation required of the [Valley Clean8Energy] dynamic rate pilot.209C.SCE Has Used Customer Surveys to Inform its Approach with RTP RatesSCE has been, and will continue to be, supportive of the Commission’s efforts to develop and1011deploy RTP rate structures as the State transitions into a lower greenhouse gas future. As such, in12addition to the pilot efforts discussed above, in Spring 2021, SCE conducted surveys, in coordination13with the Electric Power Research Institute (EPRI), to gauge residential and small business customer14perception of RTP rates.21 A majority of residential and small business participants in this survey15wanted some form of hedging to protect against price volatility.22 Additionally, 100% of electric vehicle16(EV) fleet small business customers and 75% of small business customers with energy/load management17systems indicated in this survey they would likely enroll in a conceptual RTP rate broadly described as18one with hourly dynamic prices to facilitate load flexibility and one that would be technology enabled.23Insights gained from these surveys are likely to be a focus area for the second phase of the1920RATES pilot which, as noted above, is set to begin in the Summer of 2022.20212223Id., p. 99. See also Id., OPs 59-63 and Attachment 1, pp. 10-12.See Customer Perception of Real-Time Pricing: Survey Findings, EPRI and SCE, April 2021, attached heretoas Appendix A (the survey findings for small business customers start at A-1, while the survey findings forresidential customers start at A-43).Id., pp. A-9 (small business), A-51 (residential).Id., p. A-23.7

1III.2JARP AND SBUA’S PROPOSALS SHOULD NOT BE ADOPTED3A.Adopting JARP and SBUA’s Proposals Would Undermine SCE’s Existing RTP Efforts4Which Are Aligned with the Commission’s Framework for Dynamic Pricing Options5As shown above, SCE is aware of the need to update its existing RTP rate and has taken6significant steps since 2017 to methodically develop and implement a transactive dynamic rate structure.7SCE’s approach recognizes RTP structures do not exist in isolation but rather are reliant on (1)8correlating real time localized or system load data into prices that help real time grid management, (2)9infrastructure and technology platforms to enable the seamless transfer of prices to participants, (3)10coordination with device manufacturers or energy management systems for truly flexible load control,11and (4) customer acceptance of a new type of service that can be significantly more volatile than12traditional rate options. As these necessary considerations show, successful implementation of a13revolutionary design that conveys real time dynamic prices takes careful planning to get right.14Moreover, a material transition from predictable and stable time-of-use (TOU) rates to dynamic prices15that vary and change on an hourly basis every day requires a solid foundation of testing, analysis, and16performance measurement.24 Thus, the best way to realize the full potential of dynamic prices is17through structured and deliberate execution of pilots that incrementally test the impact such prices can18have on grid and/or load management, consumption behavior, consumer bills, and the utility’s revenue19recovery potential. SCE’s ongoing methodical approach through its survey efforts and the first phase of20the RATES pilot has enabled SCE to learn much about such considerations. SCE will learn even more21through the second phase of that pilot.SCE’s methodical approach is also consistent with the efforts underway at the Commission.2223The Commission’s July 23, 2021 Draft Distributed Energy Resources Action Plan Aligning Vision and24Action (Draft CPUC DER Action Plan 2.0) establishes an organized, step-by-step framework so that24While generally correlated, SCE views the pricing architecture of dynamic prices somewhat differently fromstandard TOU rates that are intended to convey long-run equilibrium prices that help consumers moderateconsumption behavior and investment decisions over time.8

1“CPUC staff and stakeholders can strive to work efficiently and coherently towards a clean energy2future with a large participation of DERs.”25 While SCE has concerns with some of the timing aspects3in the Draft CPUC DER Action Plan 2.0, SCE strongly supports the Commission’s methodological4approach that considers key aspects of electric service under an RTP rate structure. In contrast to SCE’s5approach and the Draft CPUC DER Action Plan 2.0 framework, however, JARP’s proposals for a rapid6implementation across customer classes of what amounts to an early conceptual rate design framework7does not seriously consider any of the interim steps required to make a market-based RTP rate a viable,8successful option.26Moreover, if JARP or SBUA’s proposals are adopted, SCE would essentially have to start over910in its RTP rate development efforts rather than continuing the promising start in developing both a11platform and a rate structure through the RATES pilot. This is unreasonable considering that SCE’s12existing efforts are aligned with, and have informed, the CPUC and CEC framework regarding dynamic13pricing options, and would also create additional unnecessary costs for customers. For those reasons,14the Commission should not order SCE to develop new RTP rate options or to submit a new pilot15proposal in this proceeding.16B.JARP’s Proposed Widespread Rollout of Untested RTP Rate Options Would be Bad for17Customers, Take Significant Time, and Require a Significant Amount of Funding18The biggest problem with JARP’s proposed RTP rates is that they are supported by an early19conceptual framework that has not been adequately vetted through either a stakeholder process or20structured pilots.27 Thus, they are far from ready to be rolled out to customers. As indicated above, the21design for an effective dynamic rate is complex and requires accounting for numerous complicated252627Draft CPUC DER Action Plan 2.0, ic.pdf, p. 5 (VisionElement 1).See, e.g., JARP Direct Testimony, p. 19 (“The JARP also have not developed a cost estimate for theimplementation activities.”); id. (“Regarding ME&O to customers, JARP do[es] not advocate for an extensivecampaign.”).See, e.g., id. (“The JARP do not have the resources or expertise required to develop the actual rate.”).9

1considerations, such as ensuring the required infrastructure and technologies are in place, that customers2will broadly accept the rate, and equitable treatment of non-participating customers.3Working out these considerations requires testing, analysis, and performance measurement, like4what SCE intends to do with the different phases of the RATES pilot. But JARP proposes to skip all of5that. Instead, JARP proposes that its proposed dynamic rate options immediately be made available6across all customers classes on a permanent basis without a cap on enrollment.28 JARP would then7leave considerations such as whether the dynamic rate options are actually revenue neutral and whether8they avoid cost shifts to non-participating customers to be worked out after-the-fact through an annual9Tier 3 Advice Letter process that reviews customer, developer, and ratepayer outcomes.29 This is10entirely backwards and would likely lead to chaotic annual rate adjustments in which customers are11removed from participation or lose benefits they have come to enjoy on the rate, or in which structural12revisions to the rate are made causing customer confusion. That is bad ratemaking and bad for13customers.Moreover, JARP’s proposal is unfunded. JARP recognizes that making RTP rate options widely1415available to customers will require millions of dollars in foundational investments and implementation16efforts, including billing system upgrades, an RTP pricing engine, customer notifications, and ME&O.3017As such, JARP submits that SCE should be ordered to submit supplemental testimony to estimate these18implementation costs.31 But when considering the proposed hasty widespread implementation, the lack19of detailed rate design, and the proposed annual review and adjustment process, the scope of JARP’s20proposal is so broad that a realistic budget cannot be developed.21C.In addition to the significant flaws with JARP’s proposed implementation plan, JARP’s proposed2223JARP’s Proposed Rate Design for RTP Rate Options Is Flawedrate design for RTP rate options is flawed. While many of the rate elements JARP proposes are already28293031Id., p. 16.Id.Id., p. 19.Id., p. 20.10

1reflected in the RATES pilot RTP structure (such as hourly CAISO energy pricing, hourly generation2peak capacity cost, pricing-based triggers rather than temperature-based triggers, and a hedging3mechanism to limit the impact of a potentially volatile RTP pricing structure), there are two major flaws.1.4JARP’s Proposed “Kill Switch” Improperly Allows Participants to Reap the5Benefits of Dynamic Prices While Largely Avoiding the Risks6First, JARP’s proposed “kill switch” is inappropriate. According to JARP, the function7of this “kill switch” is to automatically revert to the customer’s otherwise applicable tariff “in the case of8a severe natural disaster, such as a large earthquake, that results in a multi-day grid outage or emergency9that keeps prices high.”32 JARP proposes that the “kill switch” be triggered if total day-ahead Marginal10Generation Costs are forecasted at or above a specified price threshold for a specified number of11consecutive hours or if the grid remains in a state of real-time Transmission Emergency or Energy12Emergency Alert at any stage for more than the same specified number of hours.33 The kill switch13would continue to apply to intervals after the threshold is reached until the underlying price or14emergency conditions subside.34 JARP defends this structure as ensuring beneficial customer outcomes15from taking service on an RTP rate.SCE agrees a hedging mechanism is critical to the broader acceptance of an RTP rate1617structure. Our years of experience with RTP and the direct feedback from the EPRI/SCE RTP customer18perception survey results confirm that the potential of exposure to extreme price volatility is a major19deterrent to RTP participation.35 There also may be circumstances in which exceptions to dynamic20pricing should be considered for vulnerable customer groups in the event of earthquakes or other natural21disasters. However, JARP’s proposed “kill switch” goes too far by potentially allowing participants to22receive the upside benefit from dynamic price differentials over the course of normal operating23conditions while largely avoiding the downside risk from prices increasing during significant reliability32333435Id., p. 16.Id., p. 16.Id., pp., 16-17.See Appendix A, pp. A-9 (small business), A-53 (residential).11

1or residency events. In other words, this design would allow participants to take full advantage of low2market prices while limiting their exposure to high market prices during some peak grid conditions.3SCE recognizes that the complete details of JARP’s proposed “kill switch” were not4provided in JARP’s direct testimony. However, the brief description that was provided by JARP implies5that the price threshold triggering of the kill switch could be established below the current market price6caps set by the CAISO and that operation of the kill switch could continue to apply over a multi-day7period, removing dynamic rates as a demand management tool when the program is needed the most.8The result would be dynamic prices becoming a subsidized and discounted rate with limited benefits to9non-participants.A more effective hedging mechanism is being explored through the RATES pilot. There,1011SCE is exploring the use of a subscription rate structure where participants can set their level of12exposure to dynamic pricing based on an amount of load that is “fixed” with the balance exposed to13hourly dynamic pricing. The subscription price model has the benefit of retaining these individual14hedging positions through dynamic pricing events, thus maintaining a level of risk protection for those15customers who prefer more stable bills while offering higher price volatility exposure for those16customers who can provide a response during these events.For these reasons, the Commission should reject JARP’s “kill switch” proposal and allow1718SCE to continue exploring a potentially viable subscription-based hedging mechanism through phase 219of its RATES pilot.202.JARP’s Proposed Capacity Price Signal Does Not Reflect Events Driven by Flex-21Capacity or Distribution System Events22Second, the component driving price differentials embedded in JARP’s proposal is23primarily capacity costs and not hourly energy prices. This is also the case with SCE’s existing RTP24rate structures. SCE’s design of standard TOU rates currently includes a generation capacity price25signal that is based on the long-run marginal cost of providing such capacity at the time of reliability26need. SCE appropriately uses long-run marginal costs in the design of standard rates for various27reasons, including that (i) rates are designed to reflect the appropriate blend of short-run and long-run12

1marginal costs as a price signal, and (ii) investments in capacity have long lead times to service,2extended useful lives, and are lumpy in nature. When designing dynamic prices, it is important that3sufficient consideration be given to the design of such capacity costs. JARP’s current proposal of4establishing a capacity signal, however, does not appropriately represent the design of dynamic prices5by:61. Only considering the peak load system constraint and ignoring the evolving ramp7system constraint driven by the proliferation of intermittent supply side resources and8DERs;92. Permitting an arbitrage opportunity by concentrating the recovery of long-run10capacity marginal costs to a few hours of the year that are based on a predictable11and/or pre-determined load threshold;123. Ignoring the importance of short-run capacity planning, and, by extension, the13recovery of such costs in non-peak months of the year under normal operating14conditions; and1516174. Ignoring the need for an RTP rate to encourage load shedding or shifting duringperiods of distribution system peak events.In sum, any proposal on dynamic price rates that includes a capacity price signa

3 1 II. 2 SCE HAS A LONG HISTORY WITH RTP AND IS ALREADY DEVELOPING A MARKET- 3 BASED RTP RATE STRUCTURE 4 A. SCE Has Offered an RTP Rate Option for More Than 30 Years 5 Although not based on CAISO energy market prices, SCE's existing RTP schedules offer menus 6 of hourly prices to general service customers who choose to participate in the RTP program.