Reply Testimony of Southern California Edison Company - R.20-11-003 SCE-02 E. Keating W. Walsh (U 338-E)
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Rulemaking No.: R.20-11-003
Exhibit No.: SCE-02
Witnesses: E. Keating
W. Walsh
(U 338-E)
Reply Testimony of Southern California
Edison Company
Before the
Public Utilities Commission of the State of California
Rosemead, California
January 19, 2021SCE-02: Reply Testimony of Southern California Edison Company
Table Of Contents
Section Page Witness
I. INTRODUCTION .............................................................................................1 E. Keating
II. SCE’S REPLY TO DR-RELATED PROPOSALS ...........................................3
A. The Commission Should Focus its Efforts on Proposals
That Can Be Implemented by Summer 2021 .........................................3
B. SCE’s Unspent Funds Should Not Be Used to Fund Parties’
Proposals ................................................................................................6
C. CPP Should Not Be Modified in this Rulemaking ................................6
III. SCE’S REPLY TO PROCUREMENT-RELATED PROPOSALS ...................9 W. Walsh
A. The Commission Should Not Increase LSEs’ RA
Requirements for Summer 2021 Based on a 17.5 Percent
PRM .......................................................................................................9
B. The Commission Should Not Order a Supplemental DRAM
Solicitation to Meet Summer 2021 Reliability Needs or
Increase the DRAM Pilot Budgets .......................................................13
C. The Commission Should Complete a Need Analysis Before
Authorizing Additional Procurement for Summer 2022 .....................15
Appendix A Witness Qualifications
-i-1 I.
2 INTRODUCTION
3 The two primary issues to be addressed in this rulemaking are “how to increase energy
4 supply and decrease demand during the peak demand and net demand peak hours in the event
5 that a heat storm similar to the August 2020 storm occurs in the summer of 2021.”1
6 Importantly, the California Public Utilities Commission’s (Commission or CPUC) focus in this
7 rulemaking is on “those actions that the Commission can adopt by April 2021 and that the parties
8 can implement before or during the summer of 2021.”2 Indeed, while the Commission may also
9 consider some actions designed to support the reliability of the energy grid in summer 2022,
10 feasibility and the ability to be implemented by summer 2021 should be fundamental priorities
11 for the proposals adopted by the Commission in this rulemaking. Even the most perfect measure
12 to reduce demand or increase supply will not help enhance electric system reliability in the
13 summer of 2021 if it cannot actually be implemented by this summer. Similarly, the
14 Commission should concentrate its efforts on those demand- and supply-side measures that can
15 achieve meaningful, beneficial reliability impacts on the grid in the limited time available, while
16 also prioritizing affordability and equitable cost allocation.
17 As set forth in its opening testimony, SCE’s demand response (DR) proposals satisfy
18 these key criteria. They are feasible and implementable by summer 2021,3 will provide the
19 greatest load impacts to enhance system reliability, minimize costs, and equitably allocate costs
20 among customers. SCE’s expedited procurement proposal will also support reliability during
21 critical periods of system need by maximizing the supply of import energy that can flow to the
1 Assigned Commissioner’s Scoping Memo and Ruling, Rulemaking (R.) 20-11-003, December 21,
2020, p. 1.
2 Id., pp. 1-2.
3 SCE also offers one proposal for consideration for summer 2022, expanding eligibility of the Smart
Energy Program for all residential customers by eliminating the community choice aggregator/electric
service provider restriction.
11 California Independent System Operator (CAISO) system when needed, with the costs and
2 benefits shared by all customers through the Cost Allocation Mechanism.
3 SCE’s reply testimony continues to focus on the importance of feasibility of
4 implementation by the summer of 2021, proposed measures’ contributions to grid reliability, and
5 ensuring affordability and equity. In Chapter II, SCE replies to DR-related proposals offered in
6 parties’ opening testimony. In particular, SCE discusses proposals that should not be adopted by
7 the Commission because they cannot be implemented by this summer or may not provide
8 reliable load reduction. SCE also opposes funding party proposals through uncommitted funds
9 from SCE’s 2018-2020 DR funding cycle and discusses why modifications to Critical Peak
10 Pricing (CPP) are better considered as part of a rate design proceeding (or are already being
11 considered as part of another proceeding).
12 In Chapter III, SCE replies to procurement-related proposals in parties’ opening
13 testimony. Specifically, SCE responds to the CAISO’s proposal to increase the planning reserve
14 margin (PRM) to 17.5 percent for June through October 2021 and opposes adoption of load-
15 serving entity (LSE) resource adequacy (RA) requirements for summer 2021 based on this
16 increased PRM. SCE also explains why the Commission should not order a supplemental
17 Demand Response Auction Mechanism (DRAM) solicitation to meet summer 2021 reliability
18 needs or increase the DRAM pilot budgets in this rulemaking. Finally, SCE discusses why the
19 Commission should complete a need analysis before authorizing additional procurement for
20 summer 2022.
21 II.
2 SCE’S REPLY TO DR-RELATED PROPOSALS
3 SCE appreciates the DR proposals submitted by numerous parties to provide quantifiable
4 load reduction. As explained in opening testimony, SCE developed its DR proposals to focus on
5 those actions that are feasible and implementable by this summer, that can provide flexible,
6 significant, and reliable load reduction during times of system need, and that are affordable and
7 can be implemented equitably from a cost allocation standpoint.4 With these considerations in
8 mind, SCE cautions the Commission against pursuing proposals that cannot be implemented by
9 the summer of 2021 or that may not provide reliable load reduction. Additionally, the
10 Commission should not use SCE’s unspent DR funding to fund parties’ proposals and should not
11 make modifications to CPP in this rulemaking.
12 A. The Commission Should Focus its Efforts on Proposals That Can Be Implemented
13 by Summer 2021
14 Although there is room for consideration of some limited DR measures that may not be
15 implemented until summer 2022, the Commission’s priority should remain on actions that can
16 shore up system reliability in the summer of 2021 in the event of another extreme heat storm.
17 Several parties proposed or commented on various design elements of an Emergency
18 Load Reduction Program (ELRP). However, SCE is concerned that implementation and
19 operation of certain proposals may not be possible by summer 2021, such as proposals that
20 require solicitation and procurement of services without sufficient time to develop and launch
21 necessary systems and websites and enroll participants to have meaningful megawatts by this
22 summer. For example, the DR Coalition5 proposes a statewide ELRP that would be administered
23 by an outside consultant that would be selected through an expedited Request for Proposals
4 See Direct Testimony of Southern California Edison Company (SCE Testimony), pp. 2, 6-7.
5 The DR Coalition includes the California Efficiency + Demand Management Council, Google LLC,
Leapfrog Power, Inc., NRG Energy, Inc., OhmConnect, Inc., Oracle, Tesla, Voltus, Inc., and Willdan.
31 solicitation and on-boarded around June 2021.6 This proposed timeline is unrealistic because it
2 does not account for certain vendor on-boarding requirements, like cybersecurity; nor is it clear
3 who would be responsible for creating website and informational materials about the new
4 program.
5 Other proposals that may not be implementable by summer 2021 include changes to
6 methods for calculating baselines and incentives and additions or changes to processes for
7 existing programs, such as the proposal to change the Capacity Bidding Program (CBP) baseline
8 for non-residential customers to a 5-in-10 baseline,7 the proposal to have a Firm Service Level
9 (FSL) baseline option for CBP customers on a pumping tariff,8 or proposals recommending SCE
10 adopt Pacific Gas and Electric Company’s (PG&E) CBP Elect options.9
11 As discussed in SCE’s opening testimony, SCE is currently undergoing a business freeze
12 as a result of the replacement of its legacy enterprise Customer Service System through the
13 Customer Service Re-Platform (CSRP) project and will not be able to develop any new or
14 customized solutions until after stabilization.10 SCE has concerns with its ability to perform
15 system changes, including to SCE’s notification systems, soon after CSRP go-live. SCE is
16 limited in the proposals that it can support and get completed in time for summer 2021 and
17 would likely need four to six months to implement these CBP proposals (e.g., SCE would need
18 to develop the business requirements and test these changes before it can be moved to
19 production). Accordingly, SCE does not recommend any changes to CBP baselines or adding
20 CBP options to its APX system in 2021. SCE will continue to work with stakeholders in the
6 See Opening Prepared Testimony of the DR Coalition (DR Coalition Testimony), pp. 14-15.
7 See id., p. 25.
8 See Opening Prepared Testimony of Polaris Energy Services, pp. 4-6.
9 See DR Coalition Testimony, pp. 26-27; Opening Prepared Testimony of Joint Demand Response
Parties (CPower and Enel X North America, Inc.) (Joint DR Parties Testimony), pp. 5-7; Prepared
Direct Testimony of Michael Peter Florio, The Utility Reform Network (TURN) (TURN Testimony),
pp. 26-27.
10 See SCE Testimony, pp. 6-7.
41 Retail Baseline Working Group and assess the various DR baseline options to inform future
2 program changes.
3 In addition to the issues addressed above, some proposals could cause reliability issues,
4 rather than mitigate or prevent them. For instance, the DR Coalition proposes to allow Base
5 Interruptible Program (BIP) and Agricultural & Pumping Interruptible (AP-I) program
6 participants to have a monthly nomination process (similar to the CBP), to unenroll on a rolling
7 basis, and to add a special force majeure provision to the BIP and AP-I tariffs that would allow
8 participants that have been directed by state authorities to remain in operation to immediately
9 unenroll from the programs without penalty.11
10 First, SCE clarifies that BIP and AP-I do not require a monthly nomination process,
11 because BIP incentives and penalties are assessed based upon the participant’s energy demand,
12 not a baseline like CBP, and AP-I does not assess performance or energy penalties because SCE
13 controls the participant’s on-site load through a direct load control device, similar to SCE’s air-
14 conditioning cycling, the Summer Discount Plan program. It appears the DR Coalition is
15 seeking changes that would allow BIP participants to change their FSL month-to-month (and
16 AP-I participants to change the amount of capacity they can provide), rather than asking for a
17 monthly bid or nomination process. Second, allowing rolling unenrollment could have
18 unintended consequences such as increasing the chance for gaming or providing little to no load
19 reductions in the key summer months (e.g., a customer could unenroll from the program in June
20 and return to the program in November and provide no DR for the critical summer months).
21 Third, if the Commission adopts a force majeure provision in the BIP and/or AP-I tariffs that
22 would allow participants to immediately unenroll without penalty, SCE recommends adding a
23 provision that also gives utilities the authority and discretion to clawback previously paid
24 incentives if the customer does not unenroll within 30 days after being directed by state
25 authorities to remain in operation.
11 See DR Coalition Testimony, pp. 22-23.
51 B. SCE’s Unspent Funds Should Not Be Used to Fund Parties’ Proposals
2 The DR Coalition suggests that the Flex Alert campaign and ELRP budgets could be
3 funded from investor-owned utilities’ (IOUs) unspent DR program budgets, including SCE’s
4 unspent funds from its 2018-2022 DR funding cycle.12 The Commission should reject this
5 proposal which assumes all of SCE’s unspent authorized budgets are also uncommitted funds.
6 This is incorrect and could impact DR program integration (e.g., unspent budgets include
7 committed funding for meter reprogramming). As stated in SCE’s DR 2018-2022 Mid-Cycle
8 Status Report advice letter, certain activities planned for the 2018 and 2019 program years were
9 postponed due to CSRP and will need to be reprioritized until after CSRP stabilizes, which is
10 anticipated to occur later this year (after summer 2021).13
11 Additionally, a utility’s unspent uncommitted funding may not be proportionate to its
12 share of the total authorized budget or cost (e.g., SCE’s unspent uncommitted funding should not
13 be applied or used towards PG&E’s and San Diego Gas & Electric Company’s (SDG&E)
14 proportional shares). After the issuance of the final decision, SCE will submit an advice letter to
15 implement SCE’s incremental revenue requirement and cost recovery for the approved proposals
16 and budgets.
17 C. CPP Should Not Be Modified in this Rulemaking
18 Several parties propose design modifications to CPP, including compensating energy
19 exports and allowing Net Energy Metering (NEM) customers or customers with distributed
20 energy resources (DERs) to participate on CPP. SCE noted in its opening testimony that SCE’s
21 CPP tariffs do not contain provisions that prohibit participation by NEM or DER customers.14
22 SCE does not recommend the Commission explore modifications to CPP rates or energy export
23 compensation in this rulemaking because the proposals provided are either being considered as
12 See id., pp. 11, 16.
13 See SCE Advice 4182-E, p. 3.
14 See SCE Testimony, p. 36.
61 part of another proceeding (NEM reform in R.20-08-020) or would be more appropriately
2 considered in a rate design proceeding such as SCE’s 2021 General Rate Case (GRC) Phase 2.
3 For example, Small Business Utility Advocates recommends early temporary adoption of
4 a CPP rate allowing compensation for exports in this rulemaking for summer 2021 and 2022 or
5 expedited adoption in R.20-08-020.15 Adding a CPP rate option including export compensation
6 may require a broader redesign of the underlying rate architecture to avoid double counting of
7 the capacity credit. As such, this proposal should be considered and vetted in the NEM reform
8 or GRC Phase 2 proceedings where detailed records are being develop for equitable
9 compensation for excess generation and the valuation and treatment of demand-side DR program
10 credits.
11 Moreover, the Solar Energy Industries Association suggests the Commission direct the
12 IOUs to add a CPP option to certain optional commercial and industrial rates, including SCE’s
13 time-of-use Option E rate.16 SCE does not recommend this change as SCE’s optional rates differ
14 in architecture from the underlying CPP default rate option. Additionally, SCE’s Option E rates
15 were intentionally designed with optimized pricing for DER applications. Adding CPP to these
16 options, including Option E, would therefore require the broader balance of elements that go into
17 the design of CPP rates, which are designed around a standard rate structure incorporating a
18 greater level of capacity cost recovery through demand charges. If CPP were to be adopted for
19 Option E, then the CPP charge and credit structure would need to be redesigned to account for
20 the different way in which capacity costs are recovered in Option E.17 This proposal is more
21 appropriately considered as part of a rate design proceeding.
15 See Direct Testimony of John D. Wilson on Behalf of the Small Business Utility Advocates,
pp. 20-21.
16 See Prepared Testimony of R. Thomas Beach on behalf of the Solar Energy Industries Association,
pp. 12-13.
17 Option E is available to eligible non-residential customers who also install, own, or operate eligible
on-site renewable technologies or stand-alone behind-the-meter energy storage systems. Option E
does not have demand charges, but the on-peak energy charge is higher.
71 The Commission should maintain the current application of the CPP event charges and
2 credits for non-residential customers who adopt DERs and are eligible for CPP. If a non-
3 residential customer exports energy to the grid during a CPP event, the event charge should not
4 result in a credit on the customer’s bill (the product of negative registered energy (kWh) and a
5 positive event charge). Without a floor to the energy applied to the CPP charge, customers
6 would be double compensated for the level of capacity being provided. In addition, because of
7 CSRP, SCE would not be able to make these types of changes in the near-term.
81 III.
2 SCE’S REPLY TO PROCUREMENT-RELATED PROPOSALS
3 A. The Commission Should Not Increase LSEs’ RA Requirements for Summer 2021
4 Based on a 17.5 Percent PRM
5 The CAISO’s opening testimony recommends the Commission adopt an increased PRM
6 of 17.5 percent for June through October 2021 and apply the increased PRM to both the gross
7 system peak demand and to the most critical hour after peak, when solar production is very low
8 or zero.18 The CAISO proposes applying increased RA requirements on LSEs for summer 2021
9 based on this increased PRM, stating that it recommends “the Commission require additional
10 resource adequacy procurement for summer 2021,” “require incremental procurement by
11 increasing the planning reserve margin from 15% to 17.5%,” and that “[a]ny incremental
12 procurement required in this proceeding should be part of the Commission’s resource adequacy
13 program and be included in resource adequacy requirements and showings for 2021.”19
14 The CAISO acknowledges that “[g]iven the late notice and the limited resource
15 availability, penalizing individual load serving entities likely would be ineffective or unfair.
16 Therefore, the CAISO recommends waiving Commission-applied penalties for failing to meet
17 any increased 2021 planning reserve margin, as long as load serving entities demonstrate good
18 faith efforts to procure capacity.”20 However, under the CAISO’s proposal, LSEs would have a
19 regulatory requirement under the RA program to procure based on the increased PRM.21
20 SCE generally agrees with the CAISO that the Commission should reexamine the
21 appropriate PRM given changing electric system conditions, including growing renewables
22 penetration in California. SCE supports reevaluation of the PRM in the Integrated Resource
18 See Opening Testimony of Jeff Billinton on Behalf of the California Independent System Operator
Corporation (CAISO Billinton Testimony); Opening Testimony of Dr. Karl Meeusen on Behalf of the
California Independent System Operator Corporation (CAISO Meeusen Testimony), pp. 2-6.
19 CAISO Meeusen Testimony, pp. 2, 4.
20 Id., pp. 4-5.
21 See id., pp. 2, 4.
91 Planning proceeding, in coordination with the RA proceeding, and believes that any long-term
2 change in the PRM should be based on robust loss-of-load expectation analysis and a
3 comprehensive stakeholder process that provides more time for vetting of the PRM needed to
4 support grid reliability under changing system conditions and the increasing effects of climate
5 change, while also considering impacts on affordability for customers.
6 In the shorter-term, SCE is concerned about implementing the CAISO’s proposal as an
7 increase to LSEs’ RA requirements for June through October of 2021. It is too late to impose
8 increased RA requirements on LSEs for summer 2021. LSEs’ RA showings for June 2021 are
9 due on April 17, 2021 (approximately the same time as a final decision is expected in this
10 rulemaking in March to April 2021) and July 2021 showings are due just one month later on
11 May 17, 2021. This gives LSEs little to no time to procure to meet higher RA compliance
12 requirements that the CAISO recognizes LSEs may not be able to meet due to limited resource
13 availability.22 Indeed, based upon the CAISO’s testimony, the ability of LSEs to meet an RA
14 requirement based upon a 17.5% PRM is difficult and potentially impossible in some summer
15 months.23
16 SCE also notes that the Commission allowed Decision (D.) 19-11-016 system reliability
17 procurement for August 1, 2021 to be considered online for purposes of the procurement
18 requirement even if it does not yet provide RA by August 2021, if the resource is online and
19 contractually required to submit bids in the CAISO markets consistent with the RA must offer
20 obligation (Proxy RA).24 Furthermore, the IOUs may procure additional Proxy RA through the
21 Commission’s recently issued proposed decision in this rulemaking ordering the IOUs to seek
22 See id., p. 4.
23 See CAISO Billinton Testimony, p. 12 (Table 2), showing a need for 2,194 MW of additional
capacity in September 2021.
24 See D.19-11-016, Conclusion of Law 27.
101 emergency procurement.25 Thus, adopting RA requirements for summer 2021 based on a 17.5
2 percent PRM could increase LSEs’ RA obligations on top of the incremental system reliability
3 procurement already required for August 2021 pursuant to D.19-11-016 and the proposed
4 decision.
5 The Commission should not impose LSE RA requirements that LSEs cannot reasonably
6 meet. Although the CAISO recognizes that penalizing individual LSEs for failure to satisfy RA
7 requirements based upon the increased PRM “likely would be ineffective or unfair” and
8 recommends “waiving Commission-applied penalties for failing to meet any increased 2021
9 planning reserve margin, as long as load serving entities demonstrate good faith efforts to
10 procure capacity,”26 LSEs would still have a compliance obligation to meet the increased RA
11 requirements based on a difficult to apply standard. Imposing higher RA obligations on LSEs
12 but then waiving penalties also creates its own complications. Without penalties, some LSEs
13 could choose to freeride off other LSEs that pursue their RA requirements based on the 17.5
14 percent PRM. Moreover, customers of LSEs who are more successful in procuring the limited
15 resources that are available to meet the increased RA requirements would face higher costs than
16 customers of LSEs who are unsuccessful. This creates significant potential for inequitable cost
17 shifting among LSE customers.
18 SCE understands that the CAISO requires the increase of the PRM to have the ability
19 to exercise certain CAISO backstop procurement authority, which SCE does not oppose.
20 SCE’s main concern is that the Commission does not create circumstances where LSEs are
21 obligated to procure to unattainable requirements. Therefore, the Commission should focus on
22 proposals that will increase supply to the CAISO system in the summer of 2021 without these
23 problems such as the emergency procurement authorized in the recent proposed decision in this
25 See Proposed Decision Directing Pacific Gas and Electric Company, Southern California Edison
Company, and San Diego Gas & Electric Company to Seek Contracts for Additional Power Capacity
for Summer 2021 Reliability, R.20-11-003, January 8, 2021.
26 CAISO Meeusen Testimony, pp. 4-5.
111 rulemaking and SCE’s import proposal, as well as the most promising proposals to decrease
2 energy demand this summer including SCE’s DR proposals. If the Commission decides to adopt
3 the CAISO’s proposal to increase the PRM to 17.5 percent for June through October 2021, the
4 Commission should not adopt individual LSE RA compliance obligations based on that
5 increased PRM or impose individual LSE penalties for failure to meet the increased PRM.27
6 Finally, SCE agrees with the CAISO on the importance of determining system reliability
7 needs based on the crucial net peak demand hours where solar and wind generation decline but
8 electricity usage remains high. However, the CAISO’s proposal to apply the 17.5 percent PRM
9 to the net peak load lacks detail as to how this process would occur. Presently, the RA structure
10 is based upon a forecast of peak load which is then allocated among all LSEs. To establish an
11 RA requirement for the net peak load, a forecast of the net load peak would be required as well
12 as a method, consistent with cost causation, to allocate that requirement among LSEs. While this
13 matter is being considered in the RA proceeding,28 it is too complex to evaluate and implement
14 in the short time afforded to meet reliability needs in the event of an extreme weather condition
15 in summer 2021. SCE is committed to continuing to examine the structure of the RA program to
16 ensure that it evolves to meet grid reliability needs under a different set of resources than what
17 has been historically used. This process, however, will require more time, thought, and effort
18 before implementation to ensure that the rules are understood, implementable, and that sufficient
19 resources exist for it to be effective.
27 This would be similar to TURN’s proposal that the Commission could approve a 15 percent PRM for
the net peak hour as well as the gross peak for 2021, without requiring LSEs to undertake any
additional 2021 procurement or assessing penalties for their failure to do so. See TURN Testimony,
p. 12.
28 SCE and the California Community Choice Association have submitted a joint proposal that would
require RA to be procured to meet the gross peak load, the net peak load, and contain a sufficient
amount of energy to meet all other hours’ needs as well. See Southern California Edison Company
(U 338-E) and California Community Choice Association’s Track 3 Proposal, R.19-11-009,
August 7, 2020; Southern California Edison Company (U 338-E) and California Community Choice
Association’s Revised Track 3B.2 Proposal, R.19-11-009, December 18, 2020.
121 B. The Commission Should Not Order a Supplemental DRAM Solicitation to Meet
2 Summer 2021 Reliability Needs or Increase the DRAM Pilot Budgets
3 TURN’s opening testimony supports a proposal in the opening comments of the
4 California Efficiency and Demand Management Council to authorize, on an expedited basis, an
5 additional DRAM auction for summer 2021, with a budget of at least $13 million.29 The Joint
6 DR Parties also reference their prior recommendation for an incremental DRAM solicitation for
7 2021 delivery year resources.30 However, they assert that while a fourth quarter 2020 decision
8 “would have allowed appropriate time to run the solicitation, execute contracts, and enroll
9 customers in market integrated resources and placed on Resource Adequacy supply plans,” “if a
10 decision authorizing a supplemental DRAM for 2021 does not occur in January 2021, the Joint
11 DR Parties believe it will be extremely challenging to achieve these steps in time for Summer
12 2021 deliveries.”31 Therefore, the Joint DR Parties’ opening testimony focuses on the DRAM
13 pilot budget for the solicitation for 2022 deliveries.32 The Joint DR Parties and the DR Coalition
14 request that the Commission authorize a substantial increase in the DRAM pilot budget for 2022
15 (and potentially part of 2021) in this rulemaking, suggesting that the annual budget should be
16 increased from $14 million to $27 million.33
17 The Commission should not order a supplemental DRAM solicitation for summer 2021
18 deliveries or increase the DRAM pilot budget for 2022 (or 2021) in this rulemaking.
19 Although DRAM resources can play an important role in providing reliability, this is not the
20 right time to procure additional DRAM resources to address summer 2021 reliability concerns;
21 nor is this the right time or venue to nearly double the DRAM pilot budget for 2022. In addition
22 to the timing concerns acknowledged by the Joint DR Parties in using a DRAM solicitation to
29 See TURN Testimony, pp. 14-15.
30 See Joint DR Parties Testimony, p. 10.
31 Id.
32 See id., pp. 9-11.
33 See id., pp. 9-10; DR Coalition Testimony, p. 6.
131 meet summer 2021 reliability needs, DRAM is still a pilot, and is currently undergoing an
2 evaluation process that has not yet been completed. The Commission found this evaluation
3 process to be necessary because DRAM has not shown itself to be reliable enough on its own to
4 be considered reliable for widespread use, let alone for resolution of a potential statewide
5 electricity reliability problem.34 Specifically, in 2019, the Commission identified that several
6 critical improvements are required to address the shortcomings in the DRAM implementation,
7 stating that:
8 The demand response auction mechanism (Auction Mechanism) has been
9 successful in engaging new customers and third-party demand response providers
10 and in offering competitive bidding prices for resource adequacy. For the
11 Commission to continue its operation, however, the Auction Mechanism needs
12 several immediate critical changes to address shortcomings in performance,
13 reliability, and offering competitive prices in the wholesale energy market.35
14 In D.19-07-009, the Commission also authorized annual budgets of $14 million for
15 DRAM solicitations in 2020 through 2022, and specifically rejected party recommendations to
16 increase those budgets, including requests by several of the same parties to increase the annual
17 budgets by $13 million to a total of $27 million.36 The Commission reasoned that: “We have
18 already determined that we should not expand the Auction Mechanism until it has been deemed
19 successful in the areas of performance and reliability. Hence, we should not expand the budget
20 significantly until we improve performance and reliability.”37
21 It is not clear that any of the shortcomings of the DRAM pilot discussed in D.19-07-009
22 have been addressed yet. The evaluation process has not been completed and neither the Joint
23 DR Parties nor the DR Coalition present any evidence that these issues have been remedied.
24 Indeed, the Final Root Cause Analysis report regarding the August 2020 extreme heat wave
25 events prepared by the CAISO, the Commission, and the California Energy Commission (CEC)
34 See D.19-07-009, p. 31.
35 Id., p. 2. See also id., p. 21.
36 See id., pp. 31-32.
37 Id., p. 32.
141 shows that Proxy Demand Response (PDR) (RA) (i.e., DRAM resources) received RA credit for
2 243 MW during the August 14, 2020 Stage 3 event, not including transmission and distribution
3 losses or a PRM gross up.38 However, these resources only received real-time awards of 191
4 MW during the Stage 3 event on August 14, and only had metered load drop of 79 MW.39
5 This poor performance supports the need for further evaluation of the performance and
6 reliability contributions of DRAM resources before ordering additional DRAM solicitations or
7 increasing the DRAM pilot budgets. If the DRAM resources did not provide a significant
8 contribution of load reduction when the grid most needed it, then any future DRAM solicitations
9 should require additional parameters to ensure the resources are offered in the real-time market
10 and dispatched when needed. Merely offering to pay more capacity payments to participants in a
11 pilot, without a commensurate obligation for these resources to dispatch during reliability events,
12 will not provide the grid reliability the Commission is seeking.40
13 C. The Commission Should Complete a Need Analysis Before Authorizing Additional
14 Procurement for Summer 2022
15 The California Energy Storage Alliance argues that the Commission should issue a
16 procurement order for summer 2022 by March 2021.41 SCE does not necessarily oppose
17 authorizing additional procurement for summer 2022, but given the cost of such incremental
38 See CAISO, Commission, CEC, Final Root Cause Analysis, Mid-August 2020 Extreme Heat Wave,
January 13, 2021, p. 56 (Table 4.3), available at: http://www.caiso.com/Documents/Final-Root-
Cause-Analysis-Mid-August-2020-Extreme-Heat-Wave.pdf.
39 See id.
40 The Commission should also reject the Joint DR Parties’ suggestion that the rules governing 2020
DRAM resources be applied to the DRAM solicitation for 2022 deliveries. See Joint DR Parties
Testimony, pp. 10-11. It does not make sense to revert to a prior pilot year’s rules. The energy
requirement that the Joint DR Parties want removed was added for 2021 to specifically address
concerns from a previous DRAM evaluation, see D.19-12-040, Finding of Fact 14, and the Joint DR
Parties ignore other refinements that have been made to the 2020 DRAM rules. It is not accurate that
the 2020 DRAM rules (without the energy requirement) was a “proven model of DRAM
performance,” as claimed by the Joint DR Parties. Joint DR Parties Testimony, p. 11. Indeed, the
Joint DR Parties’ argument that further changes to the DRAM rules are needed supports SCE’s point
that DRAM is a pilot still undergoing evaluation and the current unknowns make it inappropriate to
order a supplemental solicitation or increase DRAM pilot budgets.
41 See Opening Testimony of Jin Noh on Behalf of the California Energy Storage Alliance, pp. 42-43.
151 summer 2022 procurement for customers, the uncertainty of the CAISO system capacity need for
2 2022, and the efforts that are already underway to increase supply and reduce demand for
3 summer 2021, the Commission should first complete a need analysis that determines whether
4 there is a need for additional procurement for summer 2022 (and if there is, how much
5 incremental capacity is needed).
6 The need analyses that have been offered into the record in this rulemaking, including
7 SCE’s 2021 loss-of-load expectation study and the CAISO’s stack analysis, focus on 2021
8 system needs. Accordingly, the Commission should undertake a need analysis to determine
9 whether there is a need for incremental system capacity in 2022 before authorizing additional
10 procurement for summer 2022. Moreover, that need analysis should consider the supply- and
11 demand-side actions that are already being pursued for summer 2021, which may also be in place
12 for summer 2022 or easily extended to summer 2022, including the D.19-11-016 procurement,
13 the emergency procurement ordered in the recent proposed decision,42 demand-side measures
14 adopted in this rulemaking, and any additional procurement that is approved in the final decision
15 in this rulemaking. A premature authorization of additional procurement for summer 2022 could
16 unnecessarily duplicate those efforts and impose costs on customers for resources that are
17 ultimately not needed. Therefore, the Commission should not authorize summer 2022
18 procurement until after it determines that incremental procurement for summer 2022 is necessary
19 considering all of these other activities to increase supply and reduce demand.
42 See Proposed Decision Directing Pacific Gas and Electric Company, Southern California Edison
Company, and San Diego Gas & Electric Company to Seek Contracts for Additional Power Capacity
for Summer 2021 Reliability, R.20-11-003, January 8, 2021.
16Appendix A Witness Qualifications
1 SOUTHERN CALIFORNIA EDISON COMPANY
2 QUALIFICATIONS AND PREPARED TESTIMONY
3 OF ERICA KEATING
4 Q. Please state your name and business address for the record.
5 A. My name is Erica Keating, and my business address is 2244 Walnut Grove Avenue,
6 Rosemead, California 91770.
7 Q. Briefly describe your present responsibilities at Southern California Edison Company
8 (SCE).
9 A. I am currently the Principal Manager of the Demand Response Products team within the
10 Customer Programs and Services department at SCE. I am responsible for all Demand
11 Response programs and operational support activities associated with these programs.
12 Q. Briefly describe your educational and professional background.
13 A. I hold a Bachelor of Arts Degree in Communications with minors in History and German
14 from California State University at Fullerton. I completed a graduate degree from
15 California State University at Long Beach where I received a Master of Public
16 Administration. I began my career in 2001 at the city of Rancho Cucamonga as the
17 administrator of the city’s capital improvement program, as well as the operations
18 manager for the City’s municipal utility. In 2010, I started with SCE as a contracts and
19 Requests for Offers (RFO) originator in the Energy Procurement and Management
20 Department and progressed to senior originator in 2012. In that period of time I oversaw
21 the procurement of SCE’s resource adequacy portfolio, led the procurement of
22 conventional generation resources in SCE’s Local Capacity Requirements RFO, and
23 more recently was responsible for SCE’s Renewables Portfolio Standard RFO. In 2016, I
24 was promoted to Senior Manager of the Large Power Demand Response programs
25 responsible for approximately 1,000 MW of demand response programs. In 2019, I was
26 promoted to Principal Manager of Demand Response Products.
27 Q. What is the purpose of your testimony in this proceeding?
28 A. The purpose of my testimony in this proceeding is to sponsor portions of SCE’s Reply
29 Testimony preliminarily marked for identification as SCE-02 and titled Reply Testimony
30 of Southern California Edison Company. Specifically, I am sponsoring the portions of
31 the testimony where I am identified as the witness in the Table of Contents.
A-11 Q. Was this material prepared by you or under your supervision?
2 A. Yes, it was.
3 Q. Insofar as this material is factual in nature, do you believe it to be correct?
4 A. Yes, I do.
5 Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best
6 judgment?
7 A. Yes, it does.
8 Q. Does this conclude your qualifications and prepared testimony?
9 A. Yes, it does.
A-21 SOUTHERN CALIFORNIA EDISON COMPANY
2 QUALIFICATIONS AND PREPARED TESTIMONY
3 OF WILLIAM V. WALSH
4 Q. Please state your name and business address for the record.
5 A. My name is William V. Walsh, and my business address is 2244 Walnut Grove Avenue,
6 Rosemead, California 91770.
7 Q. Briefly describe your present responsibilities at Southern California Edison Company
8 (SCE).
9 A. I am a Vice President, responsible for managing the Energy Procurement & Management
10 Operating Unit at SCE. My organization’s responsibilities include contracting for
11 wholesale energy supply, including renewables and energy storage; energy compliance;
12 energy solicitations and valuations; energy contract management and financial
13 settlements, and energy market operations, including the bidding and scheduling of SCE’s
14 utility-owned and contracted resources into organized wholesale energy markets.
15 Q. Briefly describe your educational and professional background.
16 A. I earned a Bachelor of Arts Degree in Business Economics from the University of
17 California, Los Angeles in 1997. I earned a Juris Doctor Degree from The George
18 Washington Law School in 2000. I was hired by SCE in July 2005 as an Attorney 2.
19 I was promoted to Senior Attorney in 2009 and was responsible for several major energy
20 proceedings including resource adequacy and Renewables Portfolio Standard.
21 From 2010-2011, I served as the Manager 3 of Renewable Procurement and was
22 responsible for leading a team of originators in the procurement of all of SCE’s
23 renewable power through competitive solicitations, bilateral opportunities, and standard
24 renewable procurement programs. In 2014, I was promoted to Director and Managing
25 Attorney for the Resource Policy and Planning group responsible for representing SCE at
26 the Commission in all of its energy and resource policy proceedings. I also managed
27 SCE’s Power Procurement law group and Contracts and Intellectual Property law group.
28 In 2018, I was promoted to Assistant General Counsel in the SCE’s Law Department
29 with responsibility over cybersecurity, litigating the company’s positions before the
30 Federal Energy Regulatory Commission, and all transactional work related to SCE’s
A-31 energy procurement, interconnection agreements, and supply management activities.
2 I assumed my current position in February 2020.
3 Q. What is the purpose of your testimony in this proceeding?
4 A. The purpose of my testimony in this proceeding is to sponsor portions of SCE’s Reply
5 Testimony preliminarily marked for identification as SCE-02 and titled Reply Testimony
6 of Southern California Edison Company. Specifically, I am sponsoring the portions of
7 the testimony where I am identified as the witness in the Table of Contents.
8 Q. Was this material prepared by you or under your supervision?
9 A. Yes, it was.
10 Q. Insofar as this material is factual in nature, do you believe it to be correct?
11 A. Yes, I do.
12 Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best
13 judgment?
14 A. Yes, it does.
15 Q. Does this conclude your qualifications and prepared testimony?
16 A. Yes, it does.
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