Details for: PGE Reply to Protests of AL 5799-E.pdf


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Erik Jacobson
Director
Regulatory Relations

Pacific Gas and Electric Company
77 Beale St., Mail Code B13U
P.O. Box 770000
San Francisco, CA 94177
Fax: 415-973-3582

May 19, 2020

California Public Utilities Commission - Energy Division
Attention: Tariff Unit
505 Van Ness Avenue
San Francisco, CA 94102
Subject:

Pacific Gas and Electric Company’s Reply to the Protests of Advice
Letter 5799-E – PG&E’s Mid-Cycle Review Compliance Submittal for
its 2018-2022 Demand Response funding Application

Dear Energy Division Tariff Unit:
Pacific Gas and Electric Company (PG&E) hereby replies to protests dated May 5, 2020
from Polaris Energy Services et al (Polaris et al), the California Farm Bureau Federation
(CFBF), the California Large Energy Consumer Association (CLECA), the California
Efficiency + Demand Management Council along with CPower, Enel X and
OhmConnect (“Council et al”), and the Public Advocates Office of the Commission
(CalAdvocates), to Advice 5799-E regarding PG&E’s Mid-Cycle Review Compliance
Submittal for its 2018-2022 Demand Response funding Application (“MCR filing”).
A number of parties, including Polaris et al, CFBF, CLECA and the Council et al
expressed their objection to PG&E’s proposal to modify the eligibility requirement for the
Base Interruptible Program (BIP), specifically, the proposal to modify the 100kW
maximum demand to a 100kW average demand during the peak time-of-use (TOU)
hours in the previous 12 months. Specifically, CLECA appears to express objections on
procedural grounds. 1 Separately, the Council et al also objects to the BIP proposal and
identifies several other issues related to both BIP and other Demand Response (DR)
programs impacting PG&E in certain cases, the other IOUs other cases, and all three
IOUs in some cases. Finally, CalAdvocates’ protest centers around the magnitude of
PG&E’s underspend and its desire to freeze the DR budget for 2020 and 2021 at the
actual 2019 spending level.
To simplify the protest response, PG&E is responding to issues raised rather than
specifically by party. To this end, the responses are structured to address: (1) the
100kW BIP proposal (multiple parties), (2) DR spending levels (CalAdvocates) and (3)
Miscellaneous DR issues (Council et al).
1

Protest by CLECA at p. 2 referencing General Rule 7.4.2.





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PG&E’s Reply to Protests of Advice Letter 5799-E -2- May 19, 2020 1. 100kW Average BIP Proposal Assessment of Protests PG&E recognizes that its proposed modification to its BIP eligibility 2 impacts certain participants who may have seasonal load. As discussed in the MCR Filing, a majority of participants during 2018-2019 BIP events had load below their Firm Service Level (FSL) before the start of an event. 3 The key issue is that there currently is no mechanism for ensuring that there is a high probability that participants drop load during a BIP event. The majority of the accounts that have load below their FSLs before events are ones that have “peaky” load rather than consistent load. As Table 5 from the MCR filing illustrates, there were 344 accounts out of 517 that did not meet the 100kW threshold. However, these 344 accounts represent only 17% of total load reduction potential. The remaining 173 accounts supported 83% of total load reduction potential, which met the proposed 100kW average threshold. This suggests that although 344 accounts may represent a considerable part of the program enrollment, they only provide a small share of load reduction potential. Furthermore, customers with an average demand of 100 kW during peak times are still more likely to have load drop available compared to other BIP participants if a BIP event is called outside of peak time of use (TOU) hours. Relatedly, PG&E’s analyses show that 93% of current BIP participants that could be impacted by the eligibility change have less than a 10% participant load factor. 4 Polaris et al expressed concerns about the lack of sufficient notification. 5 PG&E stresses that if the proposal was approved there would be a reasonable transition period, as PG&E expects that this would occur at the earliest in 2021. As PG&E indicated in the MCR filing, it intended to conduct outreach to impacted participants to inform them of alternative options that may be offered by PG&E or by 3rd party DR providers. Having a transition plan in place before Commission approval would not be warranted, as it’s not clear if and in what form such approval would occur. That being PG&E’s proposes to update the BIP eligibility criterion to be 100kW on average per month during the peak TOU hours in each of the last 12 months. The current criterion is 100kW of maximum demand of 100 kW in a single month during the peak TOU hours in any of the previous 12 months. 3 MCR filing at bottom of p. 12 and pg. 13 where it states “….approximately 70% of the accounts dispatched in the six BIP events in 2018-19 had usage at or below their FSLs before the start of at least one of the events and did not further reduce load by a meaningful amount (more than 100 watts) for the duration of the event.” 4 The average load divided by the peak load in a specified time period. 5 The Polaris and CFBF protests were not served on the parties to A.17-12-012, et seq., or R.13-09-011, but only on PG&E and Energy Division Staff. Although GO 96-B does not specifically direct service on all parties, the fact that Polaris and CFBF did not serve their protests on other parties deprives those parties of knowledge about disputed issues in PG&E AL 5799-E. 2
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PG&E’s Reply to Protests of Advice Letter 5799-E -3- May 19, 2020 the case, PG&E envisioned an orderly plan in place for transitioning participants postapproval. With respect to the assertion of discrimination by CLECA 6, the proposal was not developed nor intended to single out a specific business sector but rather to ensure that participants are able to respond with load reduction when the program is called. The protests submitted by Polaris et al and CFBF raised the issue of impact on agricultural participants, without any consideration of whether the participants provide the demand response expected for the program. In a similar claim, the Council et al asserts that the proposal “Discriminates against customers based on their load duration is counterproductive….” 7 In response, PG&E respectfully asserts that DR programs were developed with requirements that support grid needs. In the case of BIP, which is a reliability program, the ability to be available for load curtailment is critical. It’s unfair to ratepayers to pay for significant incentives when a participant has a small likelihood of performing (i.e. dropping incremental load) when an actual event is called. As PG&E pointed out in its MCR filing, there are other programs such as CBP 8 which offer much greater flexibility for participants to determine their availability on a monthly basis to account for load seasonality. Separately, CLECA’s call to suspend AL 5799-E is unfounded, as it would impact the Commission’s ability to timely approve the MCR Filing 9 and risks delay for the implementation of other important modifications unrelated to the BIP proposal. Updated Proposal by PG&E While PG&E maintains its BIP eligibility proposal reasonably addresses a weakness associated with the BIP program, the weight of comments by stakeholders indicates that a more collaborative approach is warranted. Consequently, PG&E is offering to suspend this proposal at this time with an eye on working with interested stakeholders to develop either an alternative eligibility requirement or develop an alternative DR program for customers with peaky load. Procedurally, PG&E believes this effort would most likely be part of the next funding cycle (2023-2027), which currently calls for the IOUs to file their respective Applications in November 2021. 10 Protest of CLECA at p. 3. Protest of Council at p. 6. 8 The CBP program is seasonal and for the Elect and Elect+ options allows Aggregators to determine the bid price and available times. 9 The guidance decision (D.16-09-056) at p. 59 called for the Commission to present a Resolution no later than September 30, 2020. 10 D.17-12-003, OP 61. 6 7
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PG&E’s Reply to Protests of Advice Letter 5799-E -4- May 19, 2020 2. Call to Freeze DR Budget at 2019 Spend CalAdvocates’ call to have PG&E’s DR budget frozen at the 2019 spending level for 2020 and 2021 would lower the DR budget from $67M to $46M for 2020 and 2021. There is no position expressed in the protest with respect to 2022, which is the last year of the current funding cycle. As a threshold matter, PG&E fully acknowledges the difficult situation that Covid-19 has created both from an economic and human standpoint in the near term. The mid-and-long term ramifications of Covid-19 are not fully known at this time. That said, PG&E maintains that CalAdvocates’ request is inappropriate. First, this MCR filing supports prudent actions that limit unnecessary spending, including the proposal to minimize incremental investments in SmartAC, and to pilot 11 an electronic enrollment for residential CBP in order to expand the participation pool. Furthermore, in the MCR filing, PG&E recommends that funding for the Excess Supply Pilot (XSP) and the Supply Side Pilot (SSP) sunset at the end of 2020, which reduces the budget by $2.7M per year for 2021 and 2022. Further, PG&E emphasizes that the current cost recovery mechanism already provides for return of unspent funds for incentives through the Annual Electric True-up (AET). 12 Therefore, any underspending for incentives would be returned in rates on a yearly basis. CalAdvocates’ proposal to freeze the 2020 budget also is improper because it would not be decided until late in 2020 via the Commission’s Resolution. By then, most of the utilities’ spending for 2020 would have already occurred. Consequently, CalAdvocates’ proposal would put the IOUs at serious risk if they conduct their DR programs in 2020 as currently authorized, with currently established budgets. At a minimum CalAdvocates’ proposal should not be effective retrospectively. If it is not ruled out of scope entirely, consideration of CalAdvocates’ freeze must be limited to the prospective period 2021-2022. All told, PG&E questions whether CalAdvocates’ proposal would have a meaningful impact on rates and believes it would limit the state’s ability to advance its priorities for supporting grid changes under a carbon free future. Moreover, DR participants obtain financial benefits for providing services for grid reliability. 3. Miscellaneous DR Issues The Council et al presented a number of DR issues, some of which pertain to all three IOUs, while others are specific to each IOU. PG&E addresses each categorically in the subsections hereafter. Advice Letter 5752-E-A. Approximately 50% of the authorized five-year funding budget consists of customer incentives, for which PG&E returns unspent amounts in the AET annually. Any unspent amounts associated with the remaining 50% pertaining to administration would be normally returned after the end of the current funding cycle. 11 12
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PG&E’s Reply to Protests of Advice Letter 5799-E I. -5- May 19, 2020 Issues Pertaining to All Three IOUs A. Exclusion of PSPS Events from DR Program Baselines Council et al argues that PG&E’s retail CBP tariff should be revised to exclude PSPS events when calculating performance during a DR event. The Council et al’s three reasons for their position, however, are misplaced. The critical factor they overlook is the fact that CBP is bid into the CAISO market as a Proxy Demand Resource (PDR), which is subject to CAISO rules for participation in the wholesale market. PG&E’s retail DR program baselines, including for CBP, should only be adjusted for PSPS events when we take outages on the resources at the CAISO (i.e. submit outage cards to the CAISO). When that occurs the CAISO baseline is adjusted, and PG&E then may adjust the retail CBP baseline in line with the CAISO process. 13 The result would be adjusting CBP baselines in a manner consistent with what happens in the CAISO process. PG&E maintains that the existing CAISO processes for outages are the appropriate mechanism for signaling to the CAISO that a resource is not available for dispatch. The Commission should not create PSPS-specific carve-outs outside of or in place of the appropriate CAISO process, which could create potential conflicts and perverse incentives. i. The BIP does not provide an appropriate basis for adding explicit PSPS adjustments to CBP The Council et al cite BIP as a reason for their PSPS CBP proposal. BIP does not qualify as PDR, but instead is bid into the CAISO market as a Reliability Demand Response Resource (RDRR), which is a reliability product. In the CAISO market, BIP as RDRR is subject to the CAISO rules for bidding and responding to CAISO calls. Currently, however, the peak load reduction calculations used for purposes of BIP retail settlements are not aligned with the wholesale bidding process. The PSPS language addition approved January 31, 2020 for AL 5702-E, does not contribute to better alignment, which has caused PG&E to consider how to improve consistency between retail and wholesale settlements for BIP. In addition, although BIP is a statewide program, PG&E is the only IOU that incorporates PSPS into its BIP tariff. Since PSPS is an issue for all the IOUs, it may be that the question of whether PSPS should affect BIP settlement calculations should be considered on a statewide basis, rather than maintaining PG&E’s unique treatment. Since BIP and PSPS need to be reconsidered, both for achieving better alignment for BIP between retail and PG&E makes the adjustment once the DR team receives information after-the-fact about customers who were both subject to the PSPS event and in the resource subject to the outage card. The adjustment is consistent with CBP Tariff, Sheet 4, customer specific baseline. 13
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PG&E’s Reply to Protests of Advice Letter 5799-E -6- May 19, 2020 wholesale settlements and to address questions of statewide consistence, the recent addition of PSPS to PG&E’s BIP tariff may need to be revisited. Thus, relying on PSPS and BIP as the Council et al have done, is not appropriate. ii. PG&E is the DR Provider and Scheduling Coordinator for CBP in the CAISO Market, and has the Responsibility for Managing the CAISO Resource when PSPS Occurs The Council et al’s statement regarding awareness of whether their customers will be impacted by a PSPS events in CBP, the CBP aggregators do not need that information in advance. For purpose of the CAISO process, PG&E is the demand response provider and the scheduling coordinator that is responsible for bidding CBP into the CAISO market as PDR, and for the submission of outage cards when appropriate. PG&E’s demand response program team does not have more information than external parties beforethe-fact about whether specific CBP customers registered in the CAISO Demand Response Registration System (DRRS) will be impacted by a PSPS event. Instead PG&E’s team uses generally available information about geographic areas for which PSPS alerts/warnings/notifications have/are being issued, to determine which, if any, of its PDR resources in the area of the PSPS alert should have outage cards submitted. In addition to publicly available PSPS information, this decision-making process involves balancing grid needs as well as the potential for CAISO penalties. In contrast, the aggregators are not responsible for managing the effect of PSPS on bidding CBP-related PDR or for submission of outage cards. Consequently, they do not need customer specific before-the-fact PSPS information for CBP purposes. iii. PSPS adjustments for the annual LIP report are not Relevant to the Operation of CBP Lastly, the annual Load Impact Protocol (LIP) report is used in determining the amount of capacity that can be attributable to the utility’s demand response programs in the Commission’s annual Resource Adequacy (RA) and Integrated Resource Planning process. Therefore, the LIP report excludes PSPS events from the “baseline calculations” or the reference load, because usage of those days does not represent customers’ normal operations. However, utilization of the CBP PDR in the CAISO market is a function of the actual available load (which can be affected by outage cards) and does not maintain a fictional assumption of normal load when the CAISO calls on the resource for operations. Therefore, the LIP report’s treatment of PSPS is irrelevant to the use of CBP in actual CAISO process for its grid operations. B. Assessment of the 5-in-10 Baseline for Non-Residential This request is outside of the Commission-directed scope for the MCR filing. The CPUC required the IOUs to perform an analysis of the 5-in-10 baseline on residential customers and the findings were to be included in the MCR. A
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PG&E’s Reply to Protests of Advice Letter 5799-E -7- May 19, 2020 baseline analysis for non-residential customers was not required. Second, using a 5-in-10 baseline for non-residential customers lacks analytical support. Previously, the Baseline Analysis Working Group 14 undertook a broad baseline assessment for wholesale settlement, which included both residential and non-residential customers. One of the findings adopted by the CAISO was that the 10-in-10 baseline was better suited for non-residential participants. 15 The current CPUC Retail Baseline Working Group (RBWG) is assessing different versions of the 10-in-10 baseline (e.g., aggregate versus individual) for non-residential customers. The RBWG is chartered with serving a report by April 1, 2021. 16 It should be noted that the 5-in-10 baseline is not an option for non-residential customers in wholesale settlement today. Moreover, using a 5-in-10 baseline for retail settlement would lead to more misalignment between retail and wholesale settlements, which seems contradictory to the intent of the analysis of the RBWG. PG&E points out that a final determination regarding the use of additional retail baselines, including applicable rules, were intended to be addressed in the next funding cycle. 17 C. Application Process and Web Page Metrics The Council et al raises two issues, which PG&E addresses independently. Application Process for Incentives First, the Council et al asserts that “the process by which customers of third parties apply for an incentive in at least two of the three IOUs’ technology incentive programs remains lacking.” It’s not clear from the document which of the two IOUs’ processes are lacking and whether they are referring to residential or non-residential customer segments. Also, it’s not clear from the protest what the specific issues are other than the claim that there is “conflicting messaging” pertaining to eligibility requirements. PG&E suggests that if the Council et al have clearly identified deficiencies or areas of improvement that it communicates them to the IOUs. That said, PG&E concurs with the Council et al that this is not a Mid-Cycle issue. Nexant BAWG Report dated June 6, 2017: https://www.caiso.com/Documents/2017BaselineAccuracyWorkGroupFinalProposalNexant.pdf 15 Nexant BAWG Report, p. 4, Table 3-1. 16 D. 19-07-009 at p. 86. 17 D.17-12-003, Finding of Fact 74 stated “Alternative baselines should not be addressed in the mid-cycle review, but rather, in a future decision in this proceeding.” This is why D.19-07-009, OP 19, instructed the IOUs to include the report of the Retail Baseline Working Group in their respective testimony for the next funding cycle (2023-2027). 14
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PG&E’s Reply to Protests of Advice Letter 5799-E -8- May 19, 2020 Web Page Metrics Second, the Council et al asks that the Commission “should direct IOUs to disclose at least twice per year key metrics on the page views, clicks, and interactions on pages relating to third-party DRP programs, including the web pages that list third-party DRP programs and other associated programs, such as technology incentives.” PG&E responds by stressing that this matter was litigated as part of the original funding Application (A. 17-01-012) and is closed. By way of a quick background, the IOUs were ordered by the Funding Decision (D.17-12-003) to provide information in their respective websites about third-party entities. Specifically, Ordering Paragraph (OP) 46 of the Funding Decision required the IOUs to ensure “names, logos, web addresses, and 2-sentence program descriptions of each qualified third-party demand response provider operating in their service territory are provided on the main home page.” This included both Aggregators for IOUs programs along with those having contracts through the Demand Response Auction Mechanism (DRAM). Furthermore, as part of OP 46, PG&E took pro-active steps to “…inform customers about the existence of the main demand response web page described herein. PG&E complied with OP 46. 18 As it relates to the Council et al’s request for website metrics, the Funding Decision was abundantly clear that “…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 to click-through.” 19 PG&E’s rebuttal testimony in the 2018-2022 Funding Application addressed this issue in detail. 20 PG&E’s perspective at the time and to this day is that it is not the IOUs’ role to build a viable business for third-party DRPs/Aggregators or undertake their customer acquisition activities. The Commission’s decision as quoted above re-affirmed PG&E’s position. It merits emphasizing that the Commission has taken steps to not only level the playing field, but to even give preference to 3rd party resources. A prime example is the priority given to third-party resources in the annual BIP lottery. 21 Further, PG&E has discontinued marketing the SmartAC program for various reasons, including recognition that 3rd party resources can recruit residential customers. Advice Letter 5233-E and 5233-E-A. D.17-12-003 at p. 106. 20 PG&E’s Rebuttal Testimony, June 5, 2017, Page 2B-D-K-13 to 2B-D-K-15, Section G. 21 D.18-11-029, OP 5. 18 19
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PG&E’s Reply to Protests of Advice Letter 5799-E -9- May 19, 2020 D. Aggregator Eligibility for Technology Incentives By way of clarification, PG&E provides a one-stop application process for both EE and DR residential rebates for smart thermostats in order to assure a seamless customer experience. Customers and devices that qualify for the EE rebate are automatically screened to identify those on a DR program with any DR provider. Appendix A of the MCR Filing (AppA-1 footnote [2]) attempted to offer that clarification; however, since the IOUs utilized a common format for the MCR filing per the request of the Energy Division, there may have been unintended confusion as each IOU has its own process for screening applications. To clarify for PG&E, the metrics provided by the Council et al do not actually represent the true cancellation rates as the received numbers represent both DR and EE applications submitted to PG&E. As indicated in the clarifying table below, the number of DR applications are those that were identified as qualifying for an ADR rebate. Leveraging this approach ensures the majority of customers who are on DR programs make it through to completion as indicative of the 0% for 2018 and 8% for 2019, respective cancellation rates. 2018 2019 # of EE/DR Applications 11,214 14,532 # of ADR Applications 1,597 1,786 # of paid ADR Applications 1,597 1,642 Cancellation Rate 0% 8.06% For the ADR program, the CPUC clarified 22 that for residential and small to medium business customers, “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.” E. Piloting of Shift, Shimmy and Shape Programs PG&E believes it is premature to embark on further pilots without additional policy guidance from the Commission. First, the Commission had previously signaled an intent to open a New Models of DR Rulemaking, 23 which will be used to help inform future DR programs and presumably pilots. Second, the Lawrence Berkeley National Lab (LBNL) is now starting its next DR Potential Study (Phase 4). Third, the CEC has opened a Load Management initiative 24 to look at this issue holistically. While PG&E believes its Excess Supply and Supply Side Pilots provided valuable insight, we think that until further policy D.18-11-029, OP 6(g). D.17-10-017, OP 14, which states “…all issues addressed in the scoping memo of Rulemaking 13-09-011 have been resolved, except for the issue of new models, which this Decision determines shall be addressed in a future rulemaking.” 24 CEC Docket #19-OIR-01 22 23
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PG&E’s Reply to Protests of Advice Letter 5799-E - 10 - May 19, 2020 guidance is provided, there would be limited value in initiating other pilots. This is precisely the reason why PG&E in its MCR filing recommended that its two existing pilots sunset after the end of the current funding, which concludes in 2020. Plus, with the broader economic uncertainty, initiating new pilots at this point in time seems unwarranted from a budgetary standpoint. PG&E recommends that the issue of new pilots be addressed in the next funding cycle. II. Issues Limited to PG&E A. SmartAC Smart AC Attrition The Council et al expressed that while “PG&E cites several logical reasons” for the attrition in its SmartAC program, “it is not clear to what extent each of these reasons has contributed to such a rapid decline.” PG&E emphasizes that a confluence of factors has contributed to a decline and therefore it’s difficult to attribute a precise percentage to each factor. While PG&E cites several factors, including customer moves and a market trend towards smart thermostats, the attrition has also been partly caused by CPUC policy, which has restricted incremental dual enrollment between SmartAC and SmartRate. 25 Historically, both SmartAC and SmartRate have been adopted by 20% of participants. 26 Further exacerbating the downward participation trend is the loss of bundled service customers who are moving to Community Choice Aggregation where SmartRate is no longer available and customers simply chose to drop out of SmartAC as well due to the complimentary nature of both programs. Bring-Your-Own-Device (BYOD) Program Without commenting on the merit of PG&E offering a BYOD program, the rollout of any new DR program in PG&E’s assessment is beyond the scope of the MCR filing. 27 It’s worth reminding parties that during the 2018-2022 funding Application process, the Council et al, who have certain members listed in the protest by Council et al. advocated for PG&E to convert its SmartAC program to a “BYOT” program for new enrollees and to phase out D.18-11-029, OP 1 as implemented by Advice Letter 5437-E. MCR Filing at p. 6. 27 D. 17-12-003, page 137 indicates that “We reiterate the direction we provided to the Utilities in D.09-08-027 and D.12-04-045 regarding the process for requesting changes or adjustments to the demand response programs and budgets we approve in this decision. Changes such as requests for new demand response programs, increases in the total budget for a demand response program area, or changes to policies specifically adopted in this decision should be made through an Application or a Petition for Modification. We authorize the Utilities to request non-controversial changes to program tariffs and implementation procedures via a Tier 2 Advice Letter. 25 26
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PG&E’s Reply to Protests of Advice Letter 5799-E - 11 - May 19, 2020 the existing direct load control program. 28 However, it seems now Council et al would like to maintain PG&E’s direct load control SmartAC program and also develop a BYOD program in tandem. For residential DR program options, PG&E additionally offers SmartRate and residential CBP as choices for customers, and both are eligible for smart thermostat rebates through AutoDR. Residential CBP, through aggregators or DRPs, is the primary venue to leverage smart thermostats at PG&E at this time. Having an additional new DR smart thermostat program would pose challenges in a number of ways. This includes the potential for one program to cannibalize the other and could actually create confusion with four potential programs in the residential market. At a minimum, this issue requires further deliberation, which is more suitable for the next funding cycle as it would be a new program offering. B. BIP a. Revisions to Eligibility Requirements Please refer to Section 1 above titled “100kW Average BIP Proposal.” b. Excess Energy Charge PG&E points out that the straw proposal that relates to BIP excess energy charges is not a PG&E specific proposal, but one that memorializes the outcome of discussions from the Common Parameters effort. 29 It is not necessarily a recommendation for adoption by PG&E nor is it clear to PG&E where other parties stand on this issue. That said, PG&E’s existing BIP tariff has a fixed $6 per KWh excess energy charge. 30 At this point, PG&E believes that this charge is reasonable and provides a simplified approach to this issue. Furthermore, PG&E has not had a CAISO market award since the BIP program was integrated as a RDRR product into the CAISO’s market. Therefore, we believe experience with future market awards may be useful information to inform if one of the options (A or B), or potentially a different option, would be optimal. JDRP’s Intervenor Testimony, May 11, 2017 at p. 29, lines 24-26. PG&E’s MCR Filing, Appendix B, Attachment A, p. AppB-5. 30 PG&E’s BIP tariff at Sheet 12 under Excess Energy Charges. 28 29
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PG&E’s Reply to Protests of Advice Letter 5799-E - 12 - May 19, 2020 c. Additional Proposed Changes i. Exempt Customers from Re-Testing if They Reduce Their FSL to the Demand Level Achieved During the Failed Test PG&E does not support exempting a customer from re-testing if the customer reduces their FSL to the demand level achieved after a failed test. When a customer enrolls in the BIP program, the decision to pick an achievable FSL is a serious commitment that determines both the potential load reduction in emergency events and the very substantial incentive amount paid out to the customer every month. The participant must consider the burden on the grid and to ratepayers if the participant cannot drop to its chosen FSL. PG&E’s objective is to ensure that participants are held accountable to the program’s objectives, while not placing an undue burden on the customer. Currently the customer can change its FSL once a year. Allowing a customer an additional opportunity to “opt out” of their committed FSL after an initial test does not encourage customers to set an achievable FSL, or to drop to their FSL during an emergency, if the customer can modify their FSL thereafter and avoid a retest. Representatives and aggregators are expected to work with the customers to determine the reasons for the failure to meet the FSL in any specific event. If there was an operational challenge or a unique circumstance that prevented the customer from meeting their FSL, which can be corrected in a retest. There is significantly more flexibility for a customer after a retest if the customer still tries and fails to meet their FSL, including the ability for customers to modify their FSL outside of the open deenrollment period. While it is up to PG&E’s discretion to retest the customer at their new FSL, and should remain so, PG&E has historically exempted customers from testing again at a new FSL so as not to burden customers who have made a significant attempt to reach their FSL. In addition, if customers decide to de-enroll during the open season (in the month of November), they should still be subject to a test or retest at PG&E’s discretion following open enrollment because their participation does not conclude until the end of the calendar year. The customer is still enrolled in the program, receiving incentive payments, and expected to drop load during an emergency event.
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PG&E’s Reply to Protests of Advice Letter 5799-E - 13 - May 19, 2020 ii. Excess Energy Charges Should Not Escalate After the Open Enrollment Period Based on Failed Tests Occurring Prior to the Open Enrollment Period. PG&E opposes the position expressed by Council et al as it pertains to not escalating excess energy charges. Due to the scope of testing and other external factors, PG&E cannot always test and retest customers within the same calendar year. In addition to the time required to produce detailed compliance reports following a test, PG&E ensures ample time is given to customers to digest their test results and redress any reasons for failure. Moreover, PG&E may at times postpone retests in order to be mindful of extenuating external circumstances that would cause undue hardship to customers. Lastly, PG&E does not dictate the timing of CAISO initiated test events which could occur in late Fall. If the customer’s enrollment status does not change during open enrollment, there is no reason that customers who fail to comply during a fall test should be exempt from an increase in excess energy charges if a retest occurs on or after January 1 of the following year. It’s important to note that PG&E does, however, honor all FSL changes and de-enrollments for customers when they become effective on January 1st following the November open enrollment. iii. Allow Electronic Signature of Add/Delete/Update Forms PG&E supports allowing electronic signatures for its BIP add/delete/update forms. PG&E would like to roll out this feature in 2021 if PG&E can leverage existing infrastructure, and also adhere to consumer privacy laws, regulatory rules and tariffs, and customer authorization. That said, if the Commission were to freeze PG&E’s budget per CalAdvocates’ proposal, then it may limit the ability to undertake certain projects such as this one. The process for rolling out an electronic signature form for BIP is not an issue for the MCR and could be handled through a Tier 2 advice letter per previous Commission guidance. C. CBP a. Improved Enrollment Process for Residential CBP PG&E appreciates the support expressed by Council et al and is happy to report that the Commission approved its tariff request on an
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PG&E’s Reply to Protests of Advice Letter 5799-E - 14 - May 19, 2020 expedited basis. 31 PG&E and 3rd party Aggregators share a common goal of growing the residential CBP market and this pilot is expected to contribute to that growth. b. Allow for Changes in Price by Hour for CBP Elect PG&E supports considering greater flexibility in bidding options for CBP (Elect and Elect+). However, such flexibility would likely result in new incentive rates and structures. It requires thorough research and design, as well as system and process enhancements, which again could be constrained if CalAdvocates’ proposal to limit PG&E’s budget is adopted. From a process standpoint, while incremental improvements to the bidding process could be handled outside of the MCR through a Tier 2 advice letter per previous Commission guidance, new incentives and rate structures would most likely be within the scope of the next funding cycle. PG&E respectfully requests that the Commission approve Advice 5799-E as submitted. /S/ Erik Jacobson Director, Regulatory Relations cc: 31 Werner Blumer, Energy Division Polaris Energy Services et al (Polaris et al) California Farm Bureau Federation (CFBF) California Large Energy Consumer Association (CLECA) California Efficiency + Demand Management Council along with CPower, Enel X and OhmConnect (“Council et al”) Public Advocates Office of the Commission (CalAdvocates) CPUC disposition letter dated April 27, 2020 approving AL 5752-E and AL 5752-E-A.
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