Details for: SCE's Protest Response to Advice 4182-E.pdf


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

May 19, 2020
Energy Division
Attention: Tariff Unit
California Public Utilities Commission
505 Van Ness Avenue
San Francisco, CA 94102
SUBJECT:

Reply of Southern California Edison Company to Protests of
Public Advocates Office and California Efficiency + Demand
Management Council, CPower, ENEL X North America, Inc., and
OhmConnect, Inc. to Advice 4182-E

Dear Energy Tariff Division Unit:
Pursuant to General Rule 7.4.3 of the California Public Utilities Commission’s
(Commission or CPUC) General Order (GO) 96-B, Southern California Edison
Company (SCE) hereby submits its Reply to Protests of Public Advocates Office (Cal
Advocates) and California Efficiency + Demand Management Council, CPower, Enel X
North America, Inc., and OhmConnect, Inc. (collectively, “the Joint Parties”) to SCE’s
Advice Letter (AL) 4182-E, Southern California Edison Company's Demand Response
2018-2022 Mid-Cycle Status Report Advice Letter Pursuant to Decision 16-09-056.
Background
On September 29, 2016, the CPUC issued Decision (D.)16-09-056, which provided
guidance to SCE, Pacific Gas and Electric Company (PG&E), and San Diego Gas &
Electric Company (SDG&E) (jointly, “IOUs”) for filing their 2018-2022 Demand
Response (DR) Applications, established a DR budget cycle length of five years and
stipulated a mid-cycle review in 2020.1 In response, SCE filed its 2018-2022 DR
Application (A.)17-01-018 on January 17, 2017. On December 21, 2017 and March 27,
2018, the Commission issued D.17-12-003 and D.18-03-041, respectively, adopting,
with changes, SCE’s DR programs and budgets for the 2018-2022 funding years. On
April 1, 2020, SCE submitted its DR 2018-2022 Mid-Cycle Status Report Advice Letter
(MCR AL) 4182-E in compliance with CPUC Decisions D.16-09-056, D.17-12-003,
D.18-06-029, Resolution E-4918, and D.19-07-009. On May 5, 2020, Cal Advocates
and the Joint Parties each filed a protest to SCE’s Advice Letter (AL) 4182-E.

1 D.16-09-056,

P.O. Box 800

OP 9.
8631 Rush Street

Rosemead, California 91770

(626) 302-9645

Fax (626) 302-6396





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Energy Division California Public Utilities Commission May 19, 2020 Page 2 Cal Advocates Protest Cal Advocates state the Commission should: 1) require SCE to submit a supplemental AL that reduces the 2020-2021 DR authorized budgets to 2019 actual amounts, 2) approve SCE's proposal to integrate residential customers into its existing Capacity Bidding Program (CBP) provided SCE’s Category 5 budget is reduced by the full amount allocated for the pilot and 3) deny SCE’s proposal to report Energy Efficiency (EE)/DR integration activities in Budget Category 5. Joint Parties Protest The Joint Parties state that IOUs should: 1) exclude PSPS events from DR program baselines, 2) assess the accuracy of a non-residential 5-in-10 baseline with a 40% adjustment cap, 3) have a workshop to develop specific improvements on the technology incentive programs, 4) develop biannual metric reports to disclose key metrics on page views, clicks, and interactions relating to third-party DRP programs, 5) allow customers to sign over their technology incentive payments to DR aggregators and 6) develop pilots to test shift, shimmy, and shape DR products.2 Additionally, the Joint Parties state that SCE should: 1) consider implementing the Base Interruptible Program (BIP) aggregator system enhancements depending on the results of its new enrollment lottery, 2) align its BIP minimum load eligibility to be consistent with PG&E, 3) adopt the $80 summer and a $75 winter price triggers identified in the price trigger analyses instead of a year-round $75 price trigger, 4) offer a CBP Elect product similar to PG&E, and 5) implement improvements to its existing technology incentive claim process for third-party customers.3 In the Joint Parties Protest directed to PG&E, the Joint Parties state, “the Joint Parties strongly recommend that Option B be adopted for PG&E and the other IOUs” because it would assess penalties commensurate with the financial harm incurred by the IOU.4 Option B refers to PG&E Mid-Cycle Review Advice Letter 5799-E, Appendix B where PG&E provides a recap of the common parameters effort (Recap) by the IOUs resulting from D.17-12-003, Ordering Paragraph (OP) 4. In PG&E’s Recap, PG&E included for discussion purposes only, a straw proposal that included an Option A and Option B on “Potential Alignment on BIP Testing and Excess Energy Charges”. 2 3 4 Joint Parties Protest, pp. 1-5. Joint Parties Protest, pp. 9-12. Joint Parties Protest, p. 7.
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Energy Division California Public Utilities Commission May 19, 2020 Page 3 SCE’s Reply to Protests 1. SCE’s 2020 and 2021 Budgets Should Remain at Commission Approved Levels. In its Protest, Cal Advocates states, “Failing to align SCE’s DR program budgets with actual spending levels risks subjecting ratepayers to unnecessary and unreasonable costs,”5 and “SCE’s DR budgets are higher than necessary and are wholly inappropriate.”6 Cal Advocates’ recommendation to reduce SCE’s 2020 and 2021 authorized budget, while laudable in intent “to mitigate ratepayer hardship in the short and long term,” lacks factual support and ignores that SCE’s DR programs and the allocated budgets help mitigate customer hardship by providing bill credits or incentives. While SCE shares an interest in mitigating costs to customers in light of COVID-19 where appropriate, Cal Advocates’ recommendation is misguided for the following three reasons: (1) Cal Advocates provides no factual support why SCE’s budgets are “unnecessary,” “unreasonable,” “higher than necessary,” or “wholly inappropriate”;7 (2) a process already exists to return certain unspent incentive amounts to customers on an annual basis; and (3) adjustments to future budgets could harm customers by removing opportunities for bill relief through participation in DR programs or reducing funds that SCE has reserved for system and technology related improvements that have been designated to be implemented following SCE’s Customer Service Replatform Project (CSRP).8 These funds are efforts to ensure a smooth transition for all DR customers when SCE implements the CSRP. As to the first point, Cal Advocates fails to provide any explanation or facts to support its claims. For example, Cal Advocates surmises that “the economic shutdown will likely reduce electricity demand by the business sector” but provides no support for the level of reduction in SCE’s service territory that would warrant their proposed decrease in SCE’s authorized budget. Since March 2020, SCE has seen a 15 percent decrease in non-residential demand (compared to the same period in 2019), but given that the State is looking to re-open businesses over the coming months, it is premature to seek a reduction in SCE’s authorized budget. As to the second point, Cal Advocates incorrectly states that SCE spent 76 percent of its 2019 authorized budget.9 As shown in SCE’s MCR AL, SCE spent 79 percent of its 5 6 7 8 9 Cal Advocates Protest, pg. 1. Cal Advocates Protest, pg. 1. Cal Advocates Protest, pp. 1-2. See page 3 of the SCE Demand Response 2018-2022 Mid-Cycle Report Advice Letter 4182-E, Customer Service Re-Platform Project section for additional detail on the CSRP project. Cal Advocates Protest, pg. 2.
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Energy Division California Public Utilities Commission May 19, 2020 Page 4 2019 authorized budget,10 and approximately 84 percent of its 2018-2019 total budget.11 As explained in SCE’s MCR AL, under the existing ratemaking process, SCE will return unspent incentive funds on an annual basis which means customers are only paying for actual incentive costs, and therefore, the ratepayer relief that Cal Advocates recommends is already provided. As such, the proposed decrease in SCE’s authorized budget for 2020-2021 that Cal Advocates is advocating for is unnecessary given the incentives true-up process established in D.17-12-003.12 Specifically, in D.17-12-003, the Commission directed SCE to modify its Demand Response Programs Balancing Account (DRPBA) and the Base Revenue Requirement Balancing Account (BRRBA) such that the difference between the Authorized Incentive Programs Funding Levels and the DR incentives distributed to customers in a given year are returned to, or recovered from, customers the following year.13 Pursuant to this requirement, SCE already returned $20.791 million14 to ratepayers for the 2019 incentives over-collection (i.e., unspent 2019 incentives budget) in its April 13, 2020 consolidated revenue requirement and rate change,15 and has a Commission authorized process in place to return future incentives-related over-collections to customers on an annual basis should those conditions exist. SCE clarifies that while year-end 2019 unspent funds are reflected in SCE’s MCR AL as approximately $33.32 million,16 SCE returned $20.791 million in DR incentives in 2020. SCE has reserved approximately $5.1 million of 2019 unspent funds for costs it expects to incur in 2022 for meter reprogramming due to SCE’s Customer Service Re-platform 10 11 12 13 14 15 16 SCE AL 4182-E, Appendix A, Table A1-1, 2019 Portfolio Expenditures/2019 Portfolio Authorized (79% = $126,781/$160,101). SCE AL 4182-E, A-3. D.17-12-003, Ordering Paragraph (OP) 3, pg. 187. The Incentives sub-account of the DRPBA records the difference between Authorized Incentives and actual incentives distributed. The year-end balance in the DRPBA Incentives sub-account is then transferred to the BRRBA and reflected in the following year’s consolidated revenue requirement and rate change advice letter. The operation of the BRRBA in 2018 and 2019, which includes the incentives balance transferred from the DRPBA, is included for review in SCE’s Energy Resource Recovery Account (ERRA) Review Applications (A.)19-04-001 and A.20-04-002. The amount returned to customers includes interest and excludes Franchise Fees and Uncollectibles embedded in the DR Incentives. See SCE Advice 4172-E, submitted on February 28, 2020 and effective April 13, 2020. The values explicitly listed in Tables 1 and 2 reflect the difference between total DR Incentives distributed and the total DR surcharges collected in 2019 (including Franchise Fees and Uncollectibles) and are thus not directly comparable to the $20.791 million described above. Due to sales forecast variances, the total DR surcharges collected in a year are not exactly equal to the Authorized Incentive Funding Level. This sales-related variance is captured and recovered through the normal operation of the BRRBA. See SCE Demand Response 2018-2022 Mid-Cycle Report Advice Letter 4182-E, p. A-3. 2019 unspent is the difference between SCE’s 2019 budget of $160.101 million and 2019 actual of $126.781 million ($160.101M - $126.781M = $33.32 million)
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Energy Division California Public Utilities Commission May 19, 2020 Page 5 Project (CSRP) delay.17 In addition, as explained in SCE’s MCR AL, SCE has reserved $5.4 million for incentives in the Technology Incentive Program which are expected to be spent on committed AutoDR projects, residential smart thermostat incentives, and a research project to inform incentive structure changes as part of the Auto-DR annual issues process.18 The majority of the remaining unspent is attributed to lower program administrative costs which in part was reserved for a fund shift to the Smart Energy Program (SEP) to address anticipated budget needs due to projected higher enrollments in 2020-2022.19 However, current circumstances related to Covid-19 have created uncertainty with respect to enrollment forecasts between SDP and SEP as the SDP program offers cost-free participation to customers while participation in SEP requires customers to have a smart thermostat and home internet/Wi-Fi subscription service. The Commission adopted a five-year budget cycle “in order to create market stability, sustain momentum and performance.”20 Cal Advocates’ proposal to reduce 2020 and 2021 budgets prematurely and halfway through the budget cycle would cause disruption to program participation due to funding uncertainty, and limit IOUs’ spending flexibility to adapt to changes.21 It is also unclear what reductions could be made to 2020 budgets in the last few months of the year since the timing expected for a Resolution on the MCR AL could leave as little as three months22 to affect the 2020 budget, likely after most of the 2020 summer DR season. The Commission should reject Cal Advocates proposal to reduce 2020 – 2021 DR authorized budgets to 2019 actuals and maintain budgets at the amounts authorized by the Commission in D.17-12-003 and D.18-03-041. 17 18 19 20 21 22 See page 3 of the SCE Demand Response 2018-2022 Mid-Cycle Report Advice Letter 4182-E, Customer Service Re-Platform Project section for additional detail on the CSRP project. See SCE Demand Response 2018-2022 Mid-Cycle Report Advice Letter 4182-E, pp. D-6 to D-11. See SCE Demand Response 2018-2022 Mid-Cycle Report Advice Letter 4182-E, p. B-21. D.16-09-056, p. 56. The Commission reaffirmed the need to allow for budget flexibility to account for unexpected event or changing conditions by creating and refining funding shifting rules by issuing D.2005-009, Decision Granting San Diego Gas and Electric Company’s Petition to Modify Decision 17-12-003 as Modified, issued on May 12, 2020. See also D.09-08-027, pp. 211212, and D.12-04-045. Based on a “no later than September 30, 2020” resolution date. (D.16-09-056, p.59)
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Energy Division California Public Utilities Commission May 19, 2020 Page 6 2. The Joint Parties Protest Overreaches the Grounds for a Protest Under General Order 96-B, Rule 7.4.2 and Recommends Changes for SCE that are Outside this Proceeding or Should be Considered in Future Workshops. Pursuant to General Order (G.O.) 96-B, Rule 7.4.2, an advice letter may be protested on one or more grounds.23 In the Joint Parties protest, they recommend several proposals for SCE that were not raised or included in SCE’s MCR AL or raised in PG&E or SDG&E’s MCR ALs and pursuant to G.O. 96-B, Rule 7.4.2 (5) “requires consideration in a formal hearing, or is otherwise inappropriate for the advice letter process.” The following six recommendations made by the Joint Parties’ require further discussion; therefore, SCE recommends the Commission reject the Joint Parties’ proposals until they have been discussed further due to the complexity of these proposals as SCE notes below: i. The IOUs should revise their respective Capacity Bidding Program (“CBP”) and Base Interruptible Program (“BIP”) tariffs to exclude Public Safety Power Shutoff (“PSPS”) events when calculating performance during a DR event.24 The Joint Parties proposal of bill credit calculation adjustments for PSPS events has never been an issue for SCE programs and SCE is unaware of any complaints from its BIP customers regarding the current bill credit calculation method. Moreover, the Joint Parties proposal to require SCE to update its tariffs to mirror PG&E’s revised BIP tariff is improper, because PSPS events, when they are called and the frequency in which they are called may vary significantly among IOU service territories. SCE should be provided an opportunity, in a forum outside the constrained process of protest and reply to protest of a midcycle budget update advice letter submission, to evaluate and provide feedback on whether the Joint Parties proposal would have similar impacts for SCE customers or warrant a revision to SCE’s tariffs.25 Furthermore, this is an inappropriate request to mandate across all IOUs. PSPS events are not DR events and should not be treated as such. Doing so could imply that any service interruption, whether for scheduled maintenance, emergency repairs, or any other reason, also be treated as a DR event for purposes of BIP bill credit calculations. 23 24 25 G.O. 96-B, Rule 7.4.2 identifies the following for grounds of a protest: (1) The utility did not properly serve or give notice of the advice letter; (2) The relief requested in the advice letter would violate statute or Commission order, or is not authorized by statute or Commission order on which the utility relies; (3) The analysis, calculations, or data in the advice letter contain material errors or omissions; (4) The relief requested in the advice letter is pending before the Commission in a formal proceeding; (5) The relief requested in the advice letter requires consideration in a formal hearing, or is otherwise inappropriate for the advice letter process; or (6) The relief requested in the advice letter is unjust, unreasonable, or discriminatory, provided that such a protest may not be made where it would require relitigating a prior order of the Commission. Joint Parties Protest, p. 1. PG&E Advice Letter 5702-E, p. 2.
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Energy Division California Public Utilities Commission May 19, 2020 Page 7 The Joint Parties rely on a statement in the Energy Division’s Demand Response Auction Mechanism (DRAM) Disposition Letter, dated March 30, 2020, that the IOUs have been excluding PSPS events from their DR programs’ baseline calculations in their most recent Annual Load Impact Reports. This statement was incorrectly applied to SCE. Specifically, load impact calculations in SCE’s PY2019 Load Impacts Reports did not “exclude” PSPS events. Theoretically, PSPS events have the potential to effect load impact calculations, depending on program evaluated, evaluation type (individual regressions vs. control group analysis) and coincidence with PSPS event days/hours. However, in 2019, SCE did not have any DR events that coincided with PSPS events, and, SCE did not "exclude" any SCE PSPS events from its PY2019 load impact baseline calculations. SCE is open to participating in a workshop or other stakeholder forum to discuss the application of PSPS to baselines and the tradeoffs involved in proposals for possibly changes. The Joint Parties also propose SCE should exclude PSPS events from its CBP tariff. This is not applicable to SCE, because SCE’s CBP Tariff, Special Condition 12.a., already excludes “interruptions” from CBP baseline calculations. ii. The Commission should direct all three IOUs to assess the accuracy of a non-residential 5-in-10 baseline with a 40% adjustment cap.26 The Joint Parties’ proposal is not appropriate for the MCR AL and should be addressed in the Retail Baselines Working Group (RBWG) established in D.19-07-009 to address several baseline issues.27 The Joint Parties’ proposal could be raised in the RBWG as part of Issue #3 or Issue #528 or the Joint Parties can perform their own study. iii. The IOUs should develop pilots to test shift, shimmy, and shape DR products.29 While SCE appreciates the Joint Parties’ interest in leveraging the DR potential studies in the new models of DR proceeding and specifically the shift, shimmy, and shape DR products,30 the decision providing guidance on the IOUs’ 2018-2022 DR Applications, directed IOUs to only focus on existing DR program models;31 therefore, this MCR AL focuses on existing programs authorized in D.17-12-003. The Joint Parties’ 26 27 28 29 30 31 Joint Parties Protest, p. 2. D.19-07-009, OP 9. D.19-07-009, Table 9 (p. 86) identified five issues to be addressed by the Demand Response Retail Baseline Working Group. Joint Parties Protest, p. 4. Joint Parties Protest, p. 4, “DR products envisioned by the March 2017, 2025 California Demand Response Potential Study.” D.16-09-056, OP 6.
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Energy Division California Public Utilities Commission May 19, 2020 Page 8 recommendation should be deferred to the record in any potential new Commission rulemaking32 regarding new models of DR. iv. Option B (for the treatment of Excess Energy Charges) from PG&E’s common approach straw proposal should be adopted for PG&E and the other IOUs.33 In PG&E’s Mid-Cycle Review Compliance Submittal (PG&E Advice 5799-E), PG&E provided a recap of “Common Parameters” effort pursuant to D.17-12-003, which included a straw proposal on potential alignment on BIP testing and excess energy charges for discussion purposes.34 Issuing a Resolution on PG&E’s straw proposal would not be appropriate as this issue has not been considered by SCE or discussed in a workshop process. Also, the PG&E straw proposal on excess energy charges and the Joint Parties support of it incorrectly characterize excess energy charges as compensation for financial harm incurred by the IOU. Understanding the purpose and intent of excess energy charges is essential before deciding whether any changes are warranted. The BIP program has a long history stretching back into the 1980’s and has been an SCE customer tariff option under its current name since 2001.35 Since the program’s inception, excess energy charges have been a key attribute of the program and were designed to incent customers to respond during events through a significant penalty, recognizing that performance and participation are critical during local or system emergencies. Conversely, it was only recently that IOUs were ordered to start integrating DR programs into the CAISO market in 2016 in compliance with D.14-12-024, OP 4.a. Another important fact is that BIP is a retail capacity program. As a capacity program, BIP participants are compensated a retail rate for their capacity – they do not receive retail energy payments. Accordingly, excess energy charges are not intended to provide a type of financial compensation or reimbursement, but rather should reflect an appropriate reduction to the customer or DR provider’s bill credits for failure to perform and deliver on their contracted capacity. Capacity programs and energy programs, as well as retail programs and wholesale products, have different compensation based on different embedded cost drivers. The concept of compensating customers at retail levels yet penalizing them on a wholesale basis could be met with challenges from a customer-at-large perspective. From a principled perspective, retail penalties are designed for retail incentives. Accordingly, wholesale penalties would correspond to wholesale incentives. Retail rates are higher than wholesale rates in both respects because the costs to deliver service are embedded in retail rates whereas they are 32 33 34 35 See D.17-10-017, pp. 55-56 (“the issue of new models of demand response . . . will be addressed in the future rulemaking”). Joint Parties Protest, p. 7. PG&E Advice 5799-E, Appendix B, p. AppB-4. Even before BIP, SCE had been charging excess energy in SCE’s large interruptible tariffs, Schedule I-6, and its predecessors.
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Energy Division California Public Utilities Commission May 19, 2020 Page 9 absent in wholesale rates. Attempts to blithely align the retail program’s excess energy charges and CAISO wholesale energy market performance are improper and contrary to the programs’ design and calculated value. These issues are complex and at a minimum should be approached with thoughtful deliberation among all of the parties. To that end, SCE would support holding discussions to explain the facts above to interested parties and potentially explore logic around appending wholesale penalties as an added component to existing excess energy charges in an effort to continually address non-performance on the tariffs and ensure participation during CAISO emergencies.36 SCE reiterates that issuing a Resolution on PG&E’s straw proposal would not be appropriate at this time as this issue has not been fully vetted or understood by all parties. v. SCE should align its BIP minimum load eligibility requirement to be consistent with PG&E. 37 The Joint Parties suggest a change to BIP minimum load eligibility based on it “very likely” leading to greater BIP participation without providing any factual basis.38 SCE opposes changes to its BIP minimum requirements and does not see an issue with respect to the eligibility requirements of its BIP program. SCE notes that the customers displaced by PGE’s proposed changes are primarily agriculture customers and SCE currently offers the Agricultural and Pumping Interruptible (AP-I) program to these customers. SCE clarifies it currently requires BIP customers have monthly maximum demands reaching or exceeding 200 kW. SCE customers who fall under the 200kW threshold have an alternative program option that is the AP-I program. SCE has not had any issues with maintaining or adding customers under the current tariff requirements of monthly maximum demands reaching or exceeding 200 kW. vi. SCE should expand its CBP to include a CBP Elect product similar to the one offered by PG&E. 39 The Joint Parties fail to demonstrate why modifying SCE’s CBP to include a CBP Elect product, similar to PG&E, to allow for differentiated hourly bids would be in the interest of SCE’s customers. Also, expanding CBP to add a new Elect product would require additional funding to implement which could affect implementation of the residential CBP option. 36 37 38 39 D.19-07-009, Table 9 (p. 86), Issue #4 will consider whether wholesale and retail baselines should be aligned or if they can be different. Joint Parties Protest, p. 10. Joint Parties Protest, p. 10. Joint Parties Protest, pp. 10-11.
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Energy Division California Public Utilities Commission May 19, 2020 Page 10 The Joint Parties provide no factual support that SCE’s CBP program should be modified to include a CBP Elect product similar to PG&E. Further, the Joint Parties provide no evidence that such a modification would be beneficial for SCE’s CBP customers. Should the Commission wish to consider such a modification to SCE’s CBP program, SCE recommends that further analysis be conducted to determine the effectiveness of its program design and benefit to ratepayers. The results of this further analysis can be reviewed by all interested stakeholders to determine if modification to SCE’s CBP program is warranted. Furthermore, should the Commission approve SCE’s proposal to expand eligibility of its CBP to residential aggregators and customers, the Commission should deny the Joint Parties’ proposal to preserve the unspent CBP budget for residential participants. 3. SCE Should Not be Required to Implement Improvements to its Existing Technology Incentives Program Claim Web Page. The Joint Parties propose that SCE should implement improvements to its existing technology incentives program claim process to make it easier for third-party customers to apply for and receive these incentives as directed by D.17-12-003, OP 28. Specifically, the Joint Parties suggest that SCE develop a centralized web page that provides information on the available technology incentives, the eligibility requirements (including stating that customers of third-party programs are eligible), and links to a stand-alone application for technology incentives.40 Additionally, the Joint Parties suggest that SCE should develop a more neutral web page that does not lead customers toward an SCE program at the expense of third parties and describes the available technology incentives with clear instructions for all customers regarding how to apply for the incentive.41 In D.17-12-003, OP 28, the Commission directed the IOUs to provide Auto Demand Response technology incentives to participants of any supply side demand response programs/activities not required to be analyzed for cost-effectiveness. While SCE’s Automated Demand Response Technology Incentive Program (Auto-DR or ADR Program) was already compliant with this directive, SCE needed to modify its smart thermostat incentive program and process to operationalize this directive which SCE did in 2018. Recognizing a need for improvements, SCE was already working to make changes to the customer experience and thermostat incentive application process before receiving the Joint Parties proposal. Currently, SCE is upgrading its Technology Incentive Program (TIP) mass market rebate infrastructure, including webpages, to be more user friendly for customers who purchase, install, and configure their device to apply for a rebate for a qualifying smart 40 41 Joint Parties Protest, p. 11. Joint Parties Protest, p. 12.
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Energy Division California Public Utilities Commission May 19, 2020 Page 11 thermostat, that is in compliance with D.18-11-029 OP 642 in support of Smart Energy Program (SEP), Critical Peak Pricing (CPP), and DRAM. SCE is working to offer this solution in 2020 and will plan to expand this model to support CBP in 2021 or within several months after the Commission approves the CBP-Residential program. SCE will leverage a uniform process for customers to apply for a thermostat rebate for any of the four qualifying DR programs, which includes third-party programs. When the new webpage and process is active, SCE will send DRAM third parties a communication providing all the information they will need to communicate with their customers so they can apply for control incentives. 4. The Joint Parties’ Proposal to Allow Customers to Sign Over Their Technology Incentive Payments to DR Aggregators is Flawed and is Not in Compliance with Commission Decision. The Joint Parties protest states that the cancellation rate of enabling technology incentive applications is very high, especially for residential customers and suggest that one possible reason is the level of effort required on the part of the customer to apply for their incentive payment. This suggestion, without factual support, should be accorded little weight. In addition, the Joint Parties propose that all IOUs should allow customers to sign over their incentive payments to DR aggregators similar to the process allowed for incentives in the California Solar Initiative and Self-Generation Incentive Program to help alleviate what they speculate is an issue with incentive payment applications.43 The Joint Parties’ proposal is not in compliance with D.18-11-029, OP 6.g. Furthermore, the Joint Parties err in their assumption signing over or assigning a customer’s technology incentive to their DR aggregator who fronted the payment would significantly reduce technology incentive application cancellation rates. In D.18-11-029, OP 6.g., the Commission states that “Only the customer is eligible for the Auto Demand Response control incentive, not the aggregator, demand response provider, or manufacturer cloud portion of the control.” As an administrator of a ratepayer-funded rebate and incentive programs, SCE is responsible for ensuring that programs and recipients of incentives adhere to Commission policies and requirements, such as verifying a customer’s enrollment on a qualifying DR program or verifying that the Service Account has not already received an incentive, etc. 42 43 D.18-11-029, OP 6.g. states, “For residential, small and medium business customers, the control must be able to communicate and demonstrate operability using the current Open Auto Demand Response communication protocols and standards (currently Open ADR 2.0a or 2.0b). The control may be located either on site or as part of a control system, on site and at the manufacturer/demand response aggregator or provider cloud level. Only the customer is eligible for the Auto Demand Response control incentive, not the aggregator, demand response provider, or manufacturer cloud portion of the control.” Joint Parties Protest, p. 4.
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Energy Division California Public Utilities Commission May 19, 2020 Page 12 SCE does not recommend the Joint Parties approach and notes that the Aggregator or DR Provider would be taking on financial risk by providing customers with incentives before the customer’s eligibility for the incentive has been verified and subsequently possibly finding out the customer was not eligible for the incentive. Also, the Joint Parties’ proposal to assign or provide a customer’s incentive to a DR provider or Aggregator would not comply with D.18-11-029, OP 6.g. The Joint Parties’ argue, without factual support, that customers bear a high level of effort to apply for the incentive. In general, SCE’s data suggests that cancellations of Auto-DR applications are primarily attributed to the customer’s eligibility of the Auto-DR incentive,44 but it should be noted that SCE did not have any cancelled Auto-DR applications in 2019. In addition, SCE reviewed thermostat incentive applications and generally found that the unpaid/cancelled applications were due to the following four reasons: (1) Service Account (SA) is not actually enrolled or registered to a CAISO resource ID; (2) the SA or device had already received a thermostat rebate; (3) no proof of purchase was provided; or (4) the customer submitted an incomplete application. 5. Improving the Marketing of Third-Party DR Programs is Not the Responsibility of the IOUs. Joint Parties claim that there is disparity in awareness among customers between IOU and third-party DR options which is the basis for their proposal for the Commission to require IOUs to develop and report key marketing metrics relating to third-party DRP programs.45 While the Commission has confirmed that the IOUs must provide information to customers on demand response options available to them, the Commission has also stated, “it is not the responsibility of the Utilities to ensure that customers click through to the websites of third-party providers, only that customers have the ability (emphasis added) to click through.”46 Additionally, the Commission has previously denied third parties’ request that IOUs use their marketing funds to support third-party programs stating that, “We find it unnecessary for the Utilities to market a program primarily administered by a third party.”47 Therefore, IOUs should not be responsible to market or improve the marketing of thirdparty DRP programs and should not be required to spend any additional of their portfolio and program marketing funding to improve, promote, track, or report on page views, clicks, and interactions relating to third-party programs including the web pages 44 45 46 47 Ten (10) out of sixteen (16) Auto-DR applications were cancelled in 2018 because the applicant/customer was not eligible for the incentive under the program rules. Joint Parties Protest, p. 3. D.17-12-003, p. 106. D.12-04-045, p. 88.
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Energy Division California Public Utilities Commission May 19, 2020 Page 13 that list third-party DRP programs and other associated programs, such as technology incentives. The Commission should reject the Joint Parties suggestion to direct the IOUs to develop biannual metric reports to disclose key metrics on page views, clicks, and interactions relating to third-party DRP programs. However, if the Joint Parties wish to participate in a workshop process to discuss improvement ideas, SCE suggests the Joint Parties participate in the Auto-DR annual issues process to address technical issues that was initiated in D.18-11-029. In this forum, the Joint Parties can propose concrete ideas for the working group to consider and possibly address in the following year’s process. 6. SCE Clarifies Rational for Proposal to Report IDSM in DR Category 5. SCE rejects the Cal Advocates’ assertion that SCE’s proposal to include DR-funded IDSM activities in DR Category 5 should be denied because IDSM activities were not considered when the new budget categories were established.48 In D.17-12-003, the Commission states that “budget categories” may be revisited during the mid-cycle review in order to assess their reasonableness.” Exclusion of an IDSM budget category or excluding IDSM from one of the existing seven budget categories was an outcome of a lack of coordination between CPUC proceedings. At the time the IOUs filed their 2018-2022 DR Applications, IDSM was unknown and there was no indication on what the outcome of the limited EE/DR integration activities in the EE proceeding was going to be. Additionally, it is not clear that the Commission intended to exclude DR funded programs and activities that were approved in other proceedings from the DR portfolio budget categories. Demand Response Auction Mechanism (DRAM) and Direct Participation Electric Rule 24/32, which represent budgets outside of D.17-12-003 were included in Category 3. SCE agrees with Cal Advocates that IDSM activities were not initially considered in D.17-12-003, but that was due to a timing issue. In December 2017, the Commission issued D.17-12-003, Decision Adopting Demand Response Activities and Budgets for 2018 Through 2022. Then almost six months later, the Commission issued D.18-05-041, Decision Addressing Energy Efficiency Business Plans, which adopted DR funded activities and budgets pertaining to limited integration of DR and EE efforts (i.e. IDSM). SCE’s MCR AL proposal to include IDSM activities in Budget Category 5 was intended to streamline and capture IDSM budget activities and align with historical practices rather than confuse stakeholders as Cal Advocates suggests. Additionally, contrary to Cal Advocate’s assertions, DR funded IDSM activities have been approved by the CPUC to be requested through the EE proceeding since 2012.49 Since EE funding 48 49 Cal Advocates Protest, p. 4. D.12-04-045. Decision Adopting Demand Response Activities and Budgets for 2012-2014. p.174. Available at: http://docs.cpuc.ca.gov/PublishedDocs/PUBLISHED/GRAPHICS/165317.PDF
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Energy Division California Public Utilities Commission May 19, 2020 Page 14 cycles differ from DR funding cycles, there will always be a need to re-adjust and correct the tracking and reporting of DR IDSM funding in the Monthly ILP and DRP Report. SCE looks to the Commission to weigh in on the tracking and reporting of the EE/DR integration budgets approved in D.18-05-041 and the cost recovery of this funding in IOUs’ Annual Budget Advice Letter (ABAL) process. SCE recommends these activities and funding should be consistent with previous IDSM activities. Further, “testing and deploying” integration strategies discussed in D.18-05-041 would appropriately fit within the Pilots DR budget category.50 Therefore, SCE’s proposal to include limited EE/DR integration activities in Category 5 remains a reasonable approach to streamline and clarify budget activities. Finally, maintaining a consistent characterization of IDSM as a Pilot, as done with previous IDSM activities, will ensure consistent treatment of IDSM funds and prevent potential future impacts on costeffectiveness to the DR portfolio.51 It remains inappropriate to include IDSM costs in the calculation of cost-effectiveness for the DR portfolio as those costs and their reasonableness are completely out of the scope of the DR proceeding, they do not comprise costs tied to any DR programs, and they will be driven by third-party EE vendors under the scope of the EE proceeding.52 As such, the Pilots DR budget category, which is not assessed for cost-effectiveness is the most appropriate category to house IDSM funds. SCE requests Commission approval of SCE’s proposal to include DR-funded IDSM activities in DR Category 5. Conclusion Should the Commission approve Cal Advocates recommendation to decrease SCE’s 2020 and 2021 authorized budgets and adopt other modifications or proposals, SCE has concerns with the costs associated with any additional work in conjunction with reduced budgets which would put further cost pressures on SCE’s DR portfolio and result in the cancellation of other necessary activities or changes. SCE asserts that participation in demand response programs is a terrific option for customers to save money on their energy bills while helping to provide carbon free energy to the California 50 51 52 D.18-05-041, Conclusion Of Law Paragraph 10 states “Each IOU PA should set aside a minimum annual amount of $1 million for the residential sector and a load-shareproportional amount of $20 million for the commercial sector from each IOU PA’s IDSM budget to test and deploy integration strategies, which may test multiple program design and customer incentive approaches, as well as multiple technology types, with emphasis on demand-response-capable control technologies.” 2016 Demand Response Cost-Effectiveness Protocols, p. 18, states “The only type of costs which can be excluded from the portfolio cost-effectiveness analysis are the costs associated with “pilot” programs.” Available at https://www.cpuc.ca.gov/WorkArea/DownloadAsset.aspx?id=11573 D.16-08-019, p. 74
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Energy Division California Public Utilities Commission May 19, 2020 Page 15 grid. SCE implores the Commission to preserve demand response program budgets as they were approved in D.17-12-003. SCE appreciates the opportunity to submit this reply and respectfully request the Commission to issue a resolution approving AL 4182-E as submitted. Sincerely, /s/ Gary A. Stern, Ph.D. Gary A. Stern, Ph.D. GAS:do:jm cc: Edward Randolph, Director, CPUC Energy Division Aloke Gupta, Supervisor, CPUC Energy Division Jean Lamming, Analyst, CPCU Energy Division Greg Wikler, The Council Jennifer A. Chamberlin, CPower Mona Tierney-Lloyd, Enel X North America, Inc. John Anderson, OhmConnect., Inc. Service Lists R.13-09-001 and A.17-01-012, et al.
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