before the public utilities commission of the state of ... · record demonstrates that sce’s...
TRANSCRIPT
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE
STATE OF CALIFORNIA
Application of Pacific Gas and Electric Company (U 39-E) for Approval of Demand Response Programs, Pilots and Budgets for Program Years 2018-2022.
A. 17-01-012 (Filed January 17, 2017)
And Related Matters.
A. 17-01-018 A.17-01-019
SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E) OPENING BRIEF
FADIA RAFEEDIE KHOURY ROBIN Z. MEIDHOF
Attorneys for SOUTHERN CALIFORNIA EDISON COMPANY
2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-6054 Facsimile: (626) 302-6693 E-mail: [email protected]
Dated: July 24, 2017
SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E) OPENING BRIEF Table Of Contents
Section Page
i
I. INTRODUCTION AND SUMMARY OF RECOMMENDATIONS ...................................................................................1
A. Summary of Recommendations .............................................................2
B. The Commission Should Approve the Following Unopposed SCE Proposals ....................................................................3
C. The Commission Should Approve the Following SCE Proposals Despite the Concerns Raised by Other Parties ......................5
D. SCE’s 2018-2022 Portfolio Builds on the Success and Leadership of its Existing Models of DR Programs and Activities ................................................................................................6
E. Commission’s Goals and Guiding Principles for DR ............................7
F. SCE’s 2018-2022 DR Activities and Programs Proposal ......................8
G. Procedural History – Narrowing of Issues ...........................................10
II. REASONABLENESS OF SCE’S PROPOSED DR PROGRAMS AND ACTIVITIES ..........................................................................................13
A. Load Modifying Demand Response Programs ....................................13
B. Supply Side Demand Response – Reliability Programs ......................13
1. Agricultural and Pumping Interruptible ...................................14
2. Base Interruptible Program ......................................................14
C. Supply Side Demand Response – Price Responsive Programs ..............................................................................................15
1. Capacity Bidding Program (CBP) ...........................................15
2. Summer Discount Plan (SDP) .................................................16
3. Peak Time Rebate Enabling Technology Direct Load Control (PTR-ET-DLC) ..................................................17
D. Emerging and Enabling Technologies .................................................18
1. Emerging Markets & Technologies Program ..........................18
SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E) OPENING BRIEF Table Of Contents (Continued)
Section Page
ii
2. Technology Incentive Program ................................................18
3. AutoDR Program .....................................................................20
a) SCE Objects to PG&E’s Joint MOU that Improperly Seeks to Bind Other IOUs.........................21
b) IOUs Do Not Impair DRPs from Providing Technology Incentives to Their Customers .................22
4. Peak Time Rebate (PTR or PTR-ET-DLC) Program ..............26
E. Demand Response Pilots, Including DRAM .......................................26
1. Charge Ready Pilot ..................................................................26
2. DRAM Pilot .............................................................................26
F. Evaluation, Measurement and Validation ............................................27
G. Marketing, Education and Outreach (ME&O) .....................................27
1. The Objectives and Goals in the Statewide ME&O Proceeding Address OhmConnect’s Parity Concerns ..............28
2. The AB 793 Proceeding Addresses OhmConnect’s Marketplace Recommendations ...............................................29
H. Demand Response Systems Support ....................................................30
I. Integrated Programs and Activities, including Technical Audits ...................................................................................................31
J. Special Programs (Including Permanent Load Shifting) .....................31
1. Permanent Load Shifting (PLS) ...............................................31
2. Optional Binding Mandatory Curtailment (OBMC) Program ....................................................................................32
3. Rotating Outages ......................................................................33
4. Scheduled Load Reduction Programs (SLRP) .........................33
III. COST-EFFECTIVENESS OF PROPOSED DR PROGRAMS AND ACTIVITIES ..........................................................................................33
SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E) OPENING BRIEF Table Of Contents (Continued)
Section Page
iii
IV. REASONABLENESS OF BUDGET, COST, AND RATE RECOVERY REQUESTS ...............................................................................34
V. TARGETING DEMAND RESPONSE PROGRAMS IN CONSTRAINED LOCAL CAPACITY PLANNING AREAS AND DISADVANTAGED COMMUNITIES ................................................35
VI. COORDINATION BETWEEN THIS AND RELATED PROCEEDINGS ..............................................................................................42
A. Response Time Requirement on Local Resource Adequacy Resources .............................................................................................42
B. Data Access Issues ...............................................................................42
C. Baselines ..............................................................................................44
VII. REASONABLENESS OF PG&E PROPOSAL FOR POST-2019 DRAM COST RECOVERY ............................................................................45
VIII. INTEGRATION OF DEMAND RESPONSE AND ENERGY EFFICIENCY ..................................................................................................45
SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E) OPENING BRIEF Tables of Authorities
Section Page
iv
Statutes
Cal. Pub. Util. Code § 8380(b)(1). ............................................................................................................ 43
Cal. Pub. Util. Code § 8380(e) .................................................................................................................. 43
Legislation
Assembly Bill (AB) 793 .................................................................................................................... passim
CPUC Decisions
D.10-06-034 .............................................................................................................................................. 36
D.11-07-056 .............................................................................................................................................. 43
D.12-04-045 ........................................................................................................................................ 23, 29
D.14-10-046 .............................................................................................................................................. 59
D.15-03-042 .............................................................................................................................................. 44
D.15-11-042 .............................................................................................................................................. 23
D.16-06-029 ....................................................................................................................................... passim
D.16-06-034 .............................................................................................................................................. 12
D.16-08-019 .............................................................................................................................................. 51
D.16-09-020 ........................................................................................................................................ 28, 29
D.16-09-056 ................................................................................................................................ 7, 8, 23, 25
1
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE
STATE OF CALIFORNIA
Application of Pacific Gas and Electric Company (U 39-E) for Approval of Demand Response Programs, Pilots and Budgets for Program Years 2018-2022.
A. 17-01-012 (Filed January 17, 2017)
And Related Matters.
A. 17-01-018 A.17-01-019
SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E) OPENING BRIEF
In accordance with the schedule adopted for these consolidated proceedings and as
directed by the June 30, 2017 Administrative Law Judges’ Ruling Requesting Responses to
Questions and Providing Guidance on Briefs (Ruling), Southern California Edison Company
(SCE) submits its opening brief.
I.
INTRODUCTION AND SUMMARY OF RECOMMENDATIONS
SCE provides its introduction and summary of recommendations as a means to (1) orient
the reader to what we believe are the issues vis-à-vis SCE’s Application, and (2) to help focus
the attention of parties and the Commission on those matters that require resolution or further
examination in other pending proceedings.
SCE submits its opening brief after the submission of direct and rebuttal testimony and
evidentiary hearings in which 17 parties participated. SCE’s opening brief is organized
according to the proposed outline and numbering system in Attachment B of the Ruling.
2
A. Summary of Recommendations
SCE’s proposed portfolio of demand response (DR) programs and related activities for
2018-2022 are expected to provide valuable, cost-effective demand-side resources for SCE’s
customers consistent with the Commission’s and the State’s policies for DR. The evidence in the
record demonstrates that SCE’s proposed program designs and funding levels (as modified in
this brief) are reasonable and should be approved.
To accomplish its plans, SCE’s Application for 2018-2022 DR programs and activities
requested approximately $183 million for the five-year program cycle.1 As originally proposed,
SCE’s request would result in a revenue requirement decrease of approximately $13 million, or
approximately 31 percent in 2018, compared to the funding level currently authorized for SCE’s
2017 DR Programs. As a result of reviewing testimony, data requests, and filings in preparation
for this opening brief, SCE determined that the initially requested amount of $183 million should
be reduced to $177 million and on July 19, 2017, SCE filed a motion seeking to introduce two
late-filed exhibits, SCE-10 (Amended Work Paper for Emerging Markets & Technology
Program) and SCE-11 (Amended SCE 2018-2022 DR Application Budget Table) setting forth
the basis for the reduction.2
The $177 million could be further decreased should the Commission accept ORA’s
recommendation to remove the PLS program from SCE’s DR portfolio for the 2018-2022 DR
program cycle. As discussed more in Chapter II, Section J.1, SCE agrees with the
recommendation to remove the approximately $6.5 million requested for PLS in this proceeding
as long as the PLS program is incorporated into another proceeding where the funding may be
1 See SCE-01, Chapter II at p. 5:13-16. 2 SCE-10 takes into account an error in the EM&T budget that double counted direct labor costs in the
“Administration and Overhead” row when the labor costs were already included in each position listed (e.g., ENG2, ENG3, MPP1). In addition, the original EM&T labor costs did not reflect the 3% escalation per year in direct labor costs. SCE-11 reflects that updates to the requested budget for EM&T resulted in a necessary update to SCE’s initially proposed budget request; specifically, a decrease from approximately $183 million to approximately $177 million.
3
sought and provided. No party objected to ORA’s recommendation with respect to the PLS
program, so if the Commission accepts this recommendation, SCE would be seeking
approximately $171 million for its 2018-2022 DR program cycle. This amended request would
result in an annual revenue requirement decrease of approximately $19 million, or approximately
36 percent, compared to the 2017 authorized budgets for SCE’s 2017 DR Programs.
SCE requests that the Commission approve the specific programs, activities, and funding
proposed for the 2018-2022 DR program cycle as SCE continues to work with its customers,
third parties, and the Commission to meet the State’s environmental objectives and needs of the
grid, at reduced costs to customers.
Specifically, SCE requests that the Commission issue a decision:
Approving SCE’s proposed 2018-2022 DR programs and activities; and
Approving SCE’s amended proposed budget of approximately $177 million.
SCE notes that the majority of its proposed programs, portfolio, and budget is unopposed
and uncontested.
B. The Commission Should Approve the Following Unopposed SCE Proposals
For the following unopposed matters, SCE recommends that the Commission’s decision:
Approve SCE’s request to expand its official notification options for the
emergency DR programs beyond a dedicated phone line and eliminate the
mandate that customers must have a dedicated phone.3
Approve SCE’s proposal to reprogram meters on non-residential CAISO-
integrated accounts to 5-minute intervals from 15-minute intervals, with a cap of
500,000 accounts;4
Approve SCE’s DR cost-effectiveness calculations;5
3 SCE-02, p. 9:7-24 and p. 15:16-17. See JDP-01, p. 14:16-17. 4 SCE-02, p. 10:12-16. See JDP-01, p. 14:15-22; CLC-01 at pp. 35-37. 5 SCE-03, Chapter V at pp. 24-41.
4
Approve the introduction of a Firm Service Level (FSL), excess energy charges,
and automatic FSL adjustments for all customers in the AP-I program;6
Approve the proposal that all AP-I customers take service on a time-of-use rate
schedule;7
Approve SCE’s proposal to replace the type of communication device used for the
AP-I program;8
Approve SCE’s proposal to allow AP-I and BIP customers to remain on the
program without having to re-sign their contract when undergoing a superficial
name change;9
Approve SCE’s proposal to remove the essential use special condition for the BIP
program;10
Approve SCE’s proposal to eliminate the one-year term and written renewal
requirement from the Optional Binding Mandatory Curtailment program;11
Adopt SCE’s proposal to maintain the minimum and maximum economic
dispatch hours at 20 hours for its Summer Discount Plan (SDP) program;12
Adopt SCE’s recommendation to use a stakeholder process to finalize the design
of Demand Response Auction Mechanism (DRAM), if the Commission decides
6 SCE-02, Chapter II, Section A at pp. 3:6–6:1. 7 SCE-02, Chapter II, Section A at p. 6:2-6. 8 SCE-02, Chapter II, Section A at p. 6:7-24. 9 SCE-02, Chapter II, Section A at p. 7:1-13. 10 SCE-02, Chapter II, Section B at pp. 13:6–14:2; see also JDP-01, p. 17:13-15. 11 SCE-02, Chapter II, Section C at p. 15:10-15. 12 SCE-02, Chapter III, Section B at pp. 29:21–30:1. The Commission’s prior approval in D.16-06-029
to maintain the minimum and maximum economic dispatch hours at 20 hours, and the updated tariffs to reflect that approval, were specific to years 2016-2017 only.
5
to convert the DRAM pilot into an ongoing DR Resource Adequacy (RA)
procurement program;13
Adopt SCE’s recommendation to reconsider whether an increase to the cap on
reliability DR is warranted;14
Adopt SCE’s recommendation that the Commission determine demand side
management (DSM) goals in the Integrated Resource Planning proceeding and
order that the resulting DSM program funding be requested in a combined
proceeding;15
Adopt SCE’s recommendation that DR budget categories be revised as detailed in
SCE-01;16
Adopt SCE’s recommendation to remove the Rotating Outage program from
future DR applications;17
Approve SCE’s request to eliminate the Weekly Demand Response Report and
filing;18
C. The Commission Should Approve the Following SCE Proposals Despite the
Concerns Raised by Other Parties
SCE recommends that the Commission approve the following proposals based on
substantial evidence of their reasonableness:
13 SCE-02, Chapter VI, Section B at p. 56:16-19. 14 SCE-01, Chapter III, Section C at p. 15:3-7. No party objected to the proposal to reconsider the two
percent cap in a formal proceeding, but ORA recommended waiting until 2020, while the majority of parties recommended revisiting the issue earlier.
15 SCE-01, Chapter III, Section C at p. 12:3-14. 16 SCE-01, Chapter III, Section C at pp. 15:8–16:10. SCE also seeks guidance from the Commission on
how DR fund-shifting rules should apply in the future. 17 SCE-02, Chapter II, Section D at pp. 17:20–18:3 and Table II-4. 18 SCE-01, Chapter III, Section C at pp. 16:11–17:6. Approving this recommendation would align with
the Commission’s finding in D.16-09-056 (pp. 78-79) that it was no longer necessary to require IOUs to provide weekly DR exception reports.
6
SCE’s proposal to reprogram meters on CAISO-integrated residential accounts to
record interval data from 60-minute intervals to 15-minute intervals,19
SCE’s recommendation to clarify the 20-minute dispatch requirement for
resources to count toward meeting local capacity needs;20
SCE’s BIP incentive calculation proposals;21 and
SCE’s request for Marketing, Education and Outreach funds.22 SCE addresses each of the above
recommendations later on in this brief.
D. SCE’s 2018-2022 Portfolio Builds on the Success and Leadership of its Existing
Models of DR Programs and Activities
SCE has been a leader at DR integration since June 2015 when SCE began integrating
over 1,100 megawatts (MW) of its DR portfolio (approximately 90 percent of its DR resources)
into the CAISO market. SCE’s DR portfolio is comprised of both third-party delivered DR
programs and IOU-delivered programs. SCE’s current DR portfolio reflects SCE’s continued
leadership to deliver cost-effective DR programs that meet the needs of SCE’s distribution grid
and the transmission grid, while allowing customers to meet their energy needs and lower their
energy costs. In 2016, SCE had approximately 670,000 service accounts enrolled in 12 different
DR programs which resulted in over 1,300 MW of potential load reduction. SCE’s proposed
portfolio builds on the successful approaches used in 2015 and 2016. For the 2018-2022
program cycle, SCE will continue its practice of proactive program administration, customer
19 ORA was the only party to oppose SCE’s proposal to reprogram meters on CAISO-integrated accounts. Their opposition was based on the costs and an assumption SCE will be able to secure a permanent waiver from the CAISO for residential account settlement only. Notwithstanding SCE’s proposal, ORA and SCE agreed to some stipulations at hearing. See Hearing Tr. Vol I at pp. 22:13-24:4.
20 See SCE-01, Chapter IV at p. 24:5-26. 21 See SCE-03, Chapter II at pp. 7:13-8:20. 22 See SCE-02, Chapter VIII at p. 63.
7
outreach and advocacy relative to DR programs in the CAISO wholesale market, and responsible
administration of the DR budget.
E. Commission’s Goals and Guiding Principles for DR
In a Guidance Decision (D.) 16-09-056, issued on October 5, 2016, the Commission
adopted an overarching goal for DR programs regulated by the Commission. Specifically, the
Commission’s adopted DR goal states that “Commission regulated demand response programs
shall assist the State in meeting its environmental objectives, cost-effectively meet the needs of
the grid and enable customers to meet their energy needs at a reduced cost.”23 SCE’s proposed
2018-2022 DR portfolio and budget is aligned with those Commission goals.
The Guidance Decision also provided a set of principles for all Commission-regulated
DR programs and SCE’s 2018-2022 DR portfolio attempts to incorporate each of these
principles. SCE’s portfolio includes:
DR that is flexible and reliable to support renewable integration and emission
reductions;
DR programs that are evolving to complement the continuous changing needs of
the grid;
DR programs that provide customers the ability to receive DR products through a
service provider of their choice;
DR programs that can evolve to be implemented in coordination with rate design;
DR processes that are transparent; and
Activities that are market-driven and lead to competitive options for customers.
For the 2018-2022 program cycle, SCE will build upon its strong existing DR portfolio
consistent with Commission policy goals and guidance. SCE will continue to support the
23 D.16-09-056, OP 7 at p. 97.
8
Commission’s principle of market-driven DR characterized by leveling the playing field between
the IOUs and third parties and facilitating customer choice.
F. SCE’s 2018-2022 DR Activities and Programs Proposal
The Commission instructed SCE to improve, streamline, and consolidate its DR portfolio,
and with this directive in mind, SCE has included several proposals aimed at achieving both
program improvements and more cost-effective use of SCE resources. Specifically, SCE has
asked that the Commission approve its request to modify budget categories to more accurately
reflect SCE’s current DR portfolio.24 SCE has also asked the Commission to approve its request
to eliminate the requirement that it submit a Weekly Demand Response Report that is no longer
utilized by the CAISO, due to SCE’s successful integration of the majority of its programs into
the CAISO market.25
In its Application (A.17-01-018) and supporting testimony, SCE proposed a portfolio of
DR programs for 2018-2022 consisting of a five-year budget for existing DR programs and
expenditures related to Emerging and Enabling Technologies and two pilots – a Charge Ready
DR Pilot to address over-generation, and the DRAM Pilot26 to further develop competitive third-
party aggregator programs. SCE’s 2018-2022 portfolio consists of:
Reliability Programs;27
Price-Responsive Programs;28
Aggregator Managed Portfolio (AMP);29
24 SCE-01, Chapter III, Section C at pp. 15:8–16:7. 25 SCE-01, Chapter III, Section C at pp. 16:11–17:6. 26 Consistent with D.16-09-056 at pp. 70-71, SCE’s proposed funding excludes DRAM pilot costs for
2018-2019, which were already approved in D.16-06-029. See Application of SCE for Approval of its 2018-2022 Demand Response Programs, Activities and Budgets at p. 2 (filed January 17, 2017).
27 Described in SCE-02, Chapter II, and in Section II.B of this brief. 28 Described in SCE-02, Chapter III, and in Section II.C of this brief. 29 Described in SCE-02, Chapter IV. SCE is not requesting any funding for AMP contracts in this
Application.
9
DR Enabling Technology Programs (Technology Incentive Program30 and PLS)31
and Emerging Markets and Technology (EM&T);32
Pilots, including the Charge Ready DR Pilot and DRAM Pilot33
SCE also proposed DR-related activities for 2018-2022, including:
DR Systems Support and DR Technology Projects, Enhancements and
Maintenance;34
DR Marketing, Education and Outreach;35 and
DR Evaluation, Measurement and Verification.36
For the 2018-2022 DR programs and related activities, SCE is proposing an amended
total five-year budget of approximately $177 million for the program cycle37 and requests
authority to recover the actual expenditures up to the total authorized budget through its existing
Demand Response Program Balancing Account (DRPBA) mechanism.38 SCE’s original
proposal is cost-effective, with the Total Resource Cost (TRC) result of 1.3 – and after correcting
the EM&T program budget, the TRC increases to 1.32 – an increase from a TRC of 1.15 in
SCE’s 2012-2014 DR Portfolio.39
30 Described in SCE-02, Chapter V, and in Section II.D.3 of this brief. 31 Described in SCE-02, Chapter V, and in Section II.J of this brief. 32 Described in SCE-02, Chapter V, and in Section II.D.1 of this brief. 33 Described in SCE-02, Chapter VI, and in Section II.E of this brief. 34 Described in SCE-02, Chapter IX, and in Section II.H of this brief. 35 Described in SCE-02, Chapter VIII, and in Section II.G of this brief. 36 Described in SCE-02, Chapter VII, and in Section II.F of this brief. 37 The budget is as set forth in SCE-04, Appendix A (showing 11 budget categories) and SCE-01, pp.
15-16 (listing the proposed 7 budget categories); see also SCE-11 (filed July 19, 2017). 38 See SCE-03, Chapter III, pp. 12-15. 39 See Southern California Edison Company’s (U 338-E) Opening Brief in A.11-03-003 at p. 12 (filed
August 22, 2011).
10
G. Procedural History – Narrowing of Issues
Although this consolidated proceeding40 has 17 parties,41 the remaining issues for the
Commission to consider are narrow because SCE’s proposal and portfolio were largely
unopposed. Several issues parties raised in protests and responses to SCE’s Application were
narrowed or eliminated by the time intervenor testimony was served or hearings were held. For
example, the Joint DR Parties stated in their protest that they “question[ed] the reasonableness of
SCE’s nearly $6 million per year budget of which over a third is allocated to SCE labor,” with
respect to SCE’s Emerging Markets & Technology program,42 yet made no further mention of
SCE’s proposed budget in direct testimony or at hearings. As described above, SCE has
determined that Joint DR Parties’ protest required further review of the proposed budget for the
EM&T program, and SCE submitted a motion on July 19, 2017 to admit late-filed exhibit SCE-
10 to reflect a correction.
On May 11, 2017,43 parties served intervenor testimony that largely supported SCE’s
proposal.44 SCE’s rebuttal testimony focused on recommendations that SCE supports and those
40 See A.17-01-012, et al., Administrative Law Judge’s Ruling Consolidating Proceedings and Setting a Prehearing Conference, issued February 16, 2017 (consolidating A.17-01-012, Application of PG&E for Approval of Demand Response Programs, Pilots and Budgets for Program Years 2018-2022; A.17-01-018, Application of SCE for Approval of Demand Response Programs, Activities and Budgets for Programs Years 2018-20122; and A.17-01-019, Application of SDG&E for Approval of Demand Response Programs, Activities and Budgets for Program Years 2018-2022).
41 Pacific Gas and Electric Company (PG&E); San Diego Gas & Electric Company (SDG&E); SCE; the Office of Ratepayer Advocates (ORA); The Utility Reform Network (TURN); Joint DR Parties (EnergyHub, Comverge, Inc., EnerNOC, Inc., and CPower);41 Electric Motorwerks, Inc.; Olivine, Inc.; OhmConnect, Inc.; California Energy Storage Alliance (CESA); California Energy Efficiency Industry Council;41 California Large Energy Consumers Association (CLECA); the Utility Consumers’ Action Network (UCAN); and the California Independent System Operator Corporation (CAISO).
42 See Joint Protest of Comverge, Inc., CPower, EnerNOC, Inc., and EnergyHub to Consolidated Applications at p. 14 (filed February 27, 2017).
43 See May 10, 2017 Email Ruling Extending Testimony Due Dates 44 JDP-01; CLC-01; ORA-01; OHM-01 at p. 1-1 (“OhmConnect does not object to the general authority
sought by the IOUs in their respective Applications.”)
11
limited areas that needed clarification or response based on issues raised by ORA, CLECA, Joint
DR Parties, and OhmConnect. 45 UCAN also served intervenor testimony, but did not address
SCE’s Application.46
Several issues were further narrowed in SCE’s rebuttal testimony. For example, CLECA
raised the issue of aligning the DR program time periods at the conclusion of a General Rate
Case (GRC) Phase 2 or Rate Design Window (RDW) proceeding.47 SCE agreed with CLECA’s
recommendation48 and further recommended that the alignment be made through a Tier 2 advice
letter, rather than a Tier 1 advice letter as proposed by CLECA.49 SCE proposed the use of a
Tier 2 advice letter because it would provide a period of time for parties to review changes and
provide comments before the changes become effective.
In their rebuttal testimony, the Joint DR Parties recommended that SCE’s AutoDR
program adopt a structure similar to PG&E’s residential AutoDR program and SDG&E’s
Technology Incentive program by providing customers a 100 percent upfront payment.50 SCE
agreed that this payment structure for AutoDR Customized incentives would be beneficial
because it would reduce administrative burdens and simplify the program for customers.51 If the
Commission adopts Joint DR Parties’ recommended change, SCE recommended a further
reduction in the incentive structure of SCE’s AutoDR Customized technology incentive,
consistent with SCE’s proposal in its 2017 Bridge Funding filing.52
45 See SCE-05. 46 UCN-01. 47 CLC-01 at pp. 26-31. 48 SCE-05, Section II.B at p. 3:8-10. 49 SCE-05, Section II.B at pp. 3:8-6:8. 50 JDP-01 at pp. 28:13-29:4. 51 SCE-05 at p. 4:9-15. 52 SCE-05 at pp. 4:15–5:2.
12
ORA recommended that due to the low TRC score of 0.10 and the lack of interest in the
program, Permanent Load Shifting (PLS) should be eliminated.53 SCE agrees with ORA’s
recommendations as further described in Chapter II, Section J.1.54
In its direct testimony, SCE recommended that the Commission re-examine the reliability
cap, the terms of which were approved in D.16-06-034 via settlement.55 ORA also served
testimony requesting the Commission revisit the reliability cap issue, but suggested the mid-
cycle review in 2020 as the appropriate time.56 In its rebuttal testimony, SCE agreed with
ORA’s recommendation to revisit the reliability cap57 and at hearing, SCE’s witness, Ms.
Keating, confirmed on cross-examination by Joint DR Parties that SCE is interested in
considering an increase of the two percent cap.58 In addition, in advance of hearing, CLECA and
SCE agreed to stipulate to CLECA’s proposal that SCE explore creating a new energy-based DR
program to help address the reliability cap issue.59 The terms of the stipulation are described in
more detail in Volume I, pages 20-22 of the hearing transcript. At hearing, PG&E introduced
Exhibit JNT-01, a proposed Joint Memorandum of Understanding (MOU) between PG&E and
CLECA, EnerNOC, Inc., CPower, Inc., EnergyHub, Inc., OhmConnect, Inc., Electric
Motorwerks, Inc., and the California Efficiency + Demand Management Council in which the
MOU parties recommend “that a collaborative process to convene stakeholders and obtain ideas
to manage the cap should start by Q1 2018.”60 The parties to the Joint-MOU also expressed their
position that the issue of how to manage the reliability cap needs to be addressed outside the
53 ORA-01 at pp. 3-6 – 3-7. 54 See also SCE-05 at pp. 6:12–7:2. 55 SCE-01 at p. 15:3-7. 56 ORA-01 at p. 6-2, lines 2-21. 57 SCE-05 at pp. 2:12–3:7. 58 Hearing Tr. Vol I at p. 38:5-25 (Keating). 59 Hearing Tr. Vol I at pp. 20:16–22:9. 60 JNT-01 at pp. 3-4, paragraph 6.
13
current litigation over 2018-2022 DR programs and budgets in this proceeding. SCE agrees that
the Commission should revisit the reliability cap issue in another proceeding and before the mid-
cycle review suggested by ORA.
Because some issues remain unresolved by parties at hearings, SCE-05 is still instructive
for the Commission to understand what needs clarification or requires resolution.
II.
REASONABLENESS OF SCE’S PROPOSED DR PROGRAMS AND ACTIVITIES
As summarized above, the majority of SCE’s proposed DR programs and activities are
unopposed. Where parties raised limited objections to specific programs, the record still
supports SCE’s proposals as reasonable.
A. Load Modifying Demand Response Programs
As approved in D.16-06-029, SCE discontinued two of the three Peak Time Rebate
(PTR) load-modifying options. SCE will maintain its PTR-ET-DLC (direct load control) option
and redesign the program to be a Supply Side – Price Responsive Program, as described below in
Section C.3.61
B. Supply Side Demand Response – Reliability Programs
In its direct testimony, SCE describes the five programs that are triggered in times of
emergency based on grid conditions: AP-I, BIP, OBMC, Rotating Outages, and Scheduled Load
Reduction Program (SLRP).62 SCE has moved its discussion of OBMC, Rotating Outages, and
SLRP to Section J in this brief because these programs are not supply-side programs.
61 See also SCE-02 at p. 32:3-18. 62 SCE-02 at pp. 2-19.
14
1. Agricultural and Pumping Interruptible
No party objected to SCE’s proposed AP-I program proposals or proposed budget.63 The
Commission should approve SCE’s proposals as reasonable.
2. Base Interruptible Program
SCE has proposed to adjust BIP incentives to account for the avoided cost of having to
procure Local RA for the BIP-15 option.64 The characteristics required by CAISO for a resource
to be counted towards meeting local capacity needs are: (1) the ability to dispatch within 20
minutes; or (2) sufficient availability for pre dispatch. While CLECA correctly states, “The
Commission has not adopted a 20-min response requirement for DR to count for local RA,”65 it
is reasonable that SCE incorporate the CAISO requirements into the BIP tariffs. In scenarios
where the CAISO identifies an area as not having enough Local Capacity, SCE will need to go
out and procure additional MW creating more costs for customers. Although CLECA generally
supports SCE’s proposal to increase incentives for 15-minute BIP,66 SCE’s request to adjust BIP-
15 and BIP-30 goes hand-in-hand. Should SCE’s proposal to adjust BIP incentives not be
accepted in whole, SCE will keep the incentive allocations for both the BIP-15 option and the
BIP-30 option the same.
If SCE’s proposal to eliminate the BIP Aggregation option from the tariff is denied, SCE
has proposed updates and the additional funding that will be necessary to ensure continued
integration of these resources into the CAISO market.67 SCE believes it is reasonable to adopt
63 While ORA initially recommended that the Commission reject SCE’s funding request of $6.4 million to reprogram Residential and Non-Residential meters to meet CAISO interval requirements, ORA also tailored its objection to “at a minimum the component that changes the meter data for Residential customers given the existing waiver and potential for more waivers going forward.” ORA-01 at p. 2-3, lines 1-9. No residential customers participate in the AP-I program.
64 SCE-03, Chapter II at pp. 7:13-8:20. 65 CLC-01 at p. 23:4-5. 66 CLC-01 at pp. 5:23-6:3. 67 See SCE-02 at pp. 12:23-13:5. “The cost to implement these system enhancements is estimated to be
$350,000. Please refer to Chapter IX of this Volume for implementation cost details and timeframe.”
15
using Firm Service Levels (FSL) at the individual Service Account for settlement purposes
because this is how settlements for direct enrolled Service Accounts are calculated.
Additionally, this creates more flexibility for aggregators because they do not have to create
separate portfolios for their customers based on Load Serving Entity, participation option, or
voltage level. Each aggregator will have one portfolio and can add individual Service Accounts
to their BIP aggregation portfolio at any time, because each Service Account is responsible for
meeting its individual FSL. There are other modifications that may need to be made to the BIP
tariff in addition to the individual Service Account FSL-based aggregation method which SCE
will describe in a Tier 2 advice letter if required to retain the BIP aggregation option.
C. Supply Side Demand Response – Price Responsive Programs
SCE’s price responsive program offerings are triggered based on the price of the
wholesale market or system conditions and provide customers with incentives for participating in
DR, in addition to their regular energy tariff. In their protest of SCE’s Application and in their
direct testimony, Joint DR Parties raised objections or recommendations with respect to the
Capacity Bidding Program (CBP), the Summer Discount Plan (SDP), and Peak Time Rebate
(PTR) Program.
1. Capacity Bidding Program (CBP)
SCE more fully describes the CBP program background, proposed program changes, the
incentive structure and funding, and proposed program budget in its testimony.68 In their
testimony, both the Joint DR Parties and ORA made several recommendations regarding
modifications to SCE’s CBP program.69 Consistent with the guidance in the Scoping Memo,70
68 See SCE-02 at pp. 20:6-22:2. 69 JDP-01 at pp. 9 & 20-24; ORA-01 at p. 2-3. 70 See March 15, 2017 Scoping Memo and Joint Ruling of Assigned Commissioner and Administrative
Law Judges (Scoping Memo) at p. 3, footnote 4 (“Program designs ordered by D.16-06-029, e.g., changes to SCE’s Capacity Bidding Program, will not be litigated in this proceeding.”).
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any proposed changes to SCE’s CBP are out of scope for this proceeding, with the exception of
the proposal to expand CBP to residential aggregators. SCE is not opposed to expanding CBP to
residential aggregators (as requested by both ORA and Joint DR Parties), but raised the potential
issue of baselines,71 which is discussed further in Chapter VI, Section C. Joint DR Parties’
recommendations on the cost-effectiveness calculations for CBP were addressed by SCE in its
rebuttal testimony and demonstrate why the Commission should not accord any weight to their
concerns.72 SCE’s CBP proposals should be approved as reasonable.
2. Summer Discount Plan (SDP)
SCE more fully describes the SDP program background, proposed program changes, the
incentive structure and funding, and proposed program budget in its testimony.73 Although the
Joint DR Parties proposed to eliminate SDP for a bring-your-own-thermostat (BYOT) program,
SCE addressed that proposal in its rebuttal testimony.74 Specifically, SCE notes that Joint DR
Parties provide no support for their request of the Commission to direct SCE to phase out its
SDP program based on an unqualified statement that the SDP program is reaching “the end of
[its] useful life.”75 The record supports SCE’s opposition to the Joint DR Parties’
recommendations because SCE already has a BYOT program (the PTR-ET-DLC program) and
SDP is one of SCE’s largest DR programs representing approximately 306 MW of DR capacity
with more than 267,000 residential participants and 11,000 business customer participants.76
SDP was instrumental in (1) responding to the loss of over 2,000 MW of capacity when the San
Onofre Nuclear Generating Station (SONGS) was shut down,77 (2) providing DR to respond to
71 SCE-05 at pp. 14:22–15:18. 72 See SCE-05 at pp. 24:7–25:3. 73 SCE-02 at pp. 22:3–30:21. 74 SCE-05 at p. 16:1-13. 75 Id. at lines 7-9 citing JDP-01 at pp. 29-30. 76 SCE-02 at p. 22:14-19. 77 SCE-02 at p. 23:10-17.
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anticipated gas shortages at the Aliso Canyon Storage Facility,78 and (3) is a program where SCE
has proposed to target system-constrained areas, as discussed further in Chapter V. Based on the
evidence, the Commission should reject Joint DR Parties’ recommendations and approve SCE’s
SDP proposals as reasonable.
3. Peak Time Rebate Enabling Technology Direct Load Control (PTR-ET-
DLC)
SCE more fully describes the PTR-ET-DLC program background, proposed program
changes, the incentive structure and funding, and proposed program budget in its testimony.79
Only the Joint DR Parties raised an objection, specifically, to SCE’s proposal to change the PTR-
ET-DLC dispatch window for economic events to 11:00 a.m. to 8:00 p.m. with a minimum
duration of one hour and a maximum duration of six hours per day.80 Citing customer
satisfaction and attrition concerns, Joint DR Parties recommended that SCE use a one-to-four-
hour event duration and ensure that no single customer is called for more than four hours.81
SCE’s rebuttal addressed the concerns of attrition and highlighted that customers can opt out of
any particular event or override a portion of a PTR-ET-DLC event – thus decreasing the
likelihood of customer fatigue.82 Based on the evidence, the Commission should reject the Joint
DR Parties’ recommendations and approve SCE’s PTR-ET-DLC proposals as reasonable.
78 SCE-02 at p. 23:18-23. 79 SCE-02 at pp. 31:1–34:18. 80 JDP-01 at p. 30:5-30. 81 Id. 82 SCE-05 at pp. 17:3–18:3.
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D. Emerging and Enabling Technologies
1. Emerging Markets & Technologies Program
No party objected to SCE’s proposed Incentive Structure/Funding or Program Budget for
the EM&T Program.83 However, at hearings, ALJ Atamturk asked SCE’s witness if she could
explain why the “proposed budget is almost double what’s authorized in 2017.”84 The witness
testifying did not sponsor the testimony referenced by the ALJ and could not comment.85 SCE
provides further insight now. With the emergence of new technologies, the Emerging Markets
and Technology (EM&T) portfolio is broadening its scope of projects and demonstrations over
the 2018-2022 program years. Over 50% of the requested budget will be primarily allocated to
the four following projects: (1) Energy storage, integrated pilot programs and expanding
residential DR; (2) Electric Power Research Institute (EPRI) Core Projects for EE/DR; (3)
Lawrence Berkeley National Laboratory (LBNL) Partnerships for DR/Distributed Energy
Resources (DER)/Distribution Resource Plan assessments; and (4) Zero net Energy (ZNE)
Strategies for DER coordination.86 An additional nine projects or demonstrations will be
conducted with the objectives of enabling end-use technologies, DR codes and standards, DR
market expansion, and customer acceptance. The Commission should approve SCE’s EM&T
proposal as reasonable.
2. Technology Incentive Program
In its initial testimony supporting its DR Application, SCE proposed to consolidate all
technology incentive offers under a Technology Incentive umbrella program.87 Under the
83 SCE-02 at pp. 41-44. 84 See Hearing Tr. Vol. I at pp. 88:28-89:19. 85 Id. at p. 89:14-20 (Keating). 86 See SCE-09 and Supplemental Workpaper for Emerging Markets and Technology. See also SCE-10,
Amended Work Paper for Emerging Markets & Technology Program, filed in a July 19, 2017 Motion Seeking to Admit Two Late-Filed Exhibits.
87 SEC-02 at pp. 36-40.
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Technology Incentive Program, SCE proposed to include the PLS Program, Automated Demand
Response (AutoDR) Technology Incentive Program, and the Programmable Communicating
Thermostat (PCT) Incentive Program. In light of SCE’s agreement with ORA’s
recommendation to remove the PLS program from SCE’s DR portfolio, as described further in
Chapter II, Section J.1, the Technology Incentive Program would now consist of the AutoDR
and PCT incentive programs.
At hearing, during a line of questioning from the ALJs, SCE’s witness was asked to
explain the proposed budget request in Table V-11 on page 40 of Volume 2 of SCE’s direct
testimony.88 Specifically, ALJ Atamturk asked SCE’s witness to explain the increase in the
funding request for year 2018 followed by the requested budget for years 2019-2022 which
looked similar to the 2017 authorized budgets. SCE’s witness was unable to elaborate at that
time without the benefit of SCE’s workpapers (SCE-09) and asked if she could “get back to” the
ALJ with a response after time to review.89 SCE does so now. SCE has been providing AutoDR
incentives since the 2006-2008 program cycle. Since that time, AutoDR technology and
standards have changed and SCE seeks a one-time funding request of $3 million, as reflected in
Exhibit SCE-09.90 The one-time $3 million funding request in 2018 will be used to replace 600
AutoDR devices from an older 1.0 version to a newer 2.0 version to ensure the devices will
continue to receive DR event signals from SCE’s Demand Response Automation Server. All
device replacements are expected to be completed in 2018 allowing the budget to return to
normal operating levels in 2019-2022. Replacing these older load control devices will help
provide reliable automated load reduction during dispatched events.
AutoDR enables eligible SCE customers to participate in SCE’s DR programs by
reducing electricity usage via automated enabling technology. The AutoDR program provides
88 See Hearing Tr. Vol I at p. 88:9-27 (Keating). 89 Id. 90 See Supplemental Workpaper for Technology Incentive Program (AutoDR-TI) included in SCE-09.
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incentives to customers for installing automated load control equipment or a system, such as an
energy management system, at a non-residential customer site. Customers must also have an
interval meter and be a participant in at least one qualifying DR program. Under the PCT
Incentive Program, SCE provides a $75 rebate to customers for the purchase of an eligible
PCT.91 SCE proposes to recover administration costs and incentives for both AutoDR and PCT
incentive programs through the Demand Response Program Balancing Account (DRPBA).92 In
its rebuttal testimony and as discussed below in Chapter II, Section D.3.b., SCE explains why it
should not be responsible for providing technology incentives to customers participating in DR
programs that have been awarded through a competitive solicitation such as DRAM.
No party objected to SCE’s proposal to consolidate funding for AutoDR and PCT
incentives under one program,93 therefore, the Commission should approve this proposal as
reasonable.
3. AutoDR Program
SCE proposed no changes to its AutoDR program, beyond the request to consolidate
funding with the PCT Incentive Program. In their initial protest of SCE’s Application, the Joint
DR Parties questioned how the AutoDR program will be offered to DRAM participants.94 In its
testimony and at hearings, OhmConnect raised concerns with the technologies eligible for
incentives under SCE’s programs and also about the availability of these incentives to residential
participants in both IOU and third-party DR programs. We address each of those concerns with
91 SCE-02 at pp. 39:14-40:16; see also D.16-06-029 at pp. 26-27 (Decision authorizing a budget of $3.75 million to target 50,000 new customers and offer the $75 rebate).
92 See SCE-02 at pp. 39-40. Currently PCT incentives are recovered through the Demand Response Program Aliso Canyon Balancing Account (DRPACBA).
93 The Joint DR Parties acknowledged the consolidation of incentives under one Technology Incentive umbrella program “may ‘streamline’ SCE’s program,” (see Joint DR Parties Protest at p. 14).
94 See Joint Demand Response Parties Protest, p. 14 (filed February 27, 2017).
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reference to OhmConnect’s publicly available website and the record, including SCE data
responses and statements made at hearing by OhmConnect’s witness during cross examination.
a) SCE Objects to PG&E’s Joint MOU that Improperly Seeks to Bind Other
IOUs
First, SCE reiterates its objection to the proposed Joint-MOU between PG&E and other
parties to the extent that OhmConnect has reached an understanding about steps to develop a list
of residential AutoDR-enabled end-use devices to be considered for eligibility for an AutoDR
incentive.95 SCE also objects to any purported understanding about enrollment requirements for
participation in an AutoDR Program.96 As explained at hearings, D.16-06-029 held that “PG&E,
SDG&E, and SCE shall implement ADR programs with uniform parameters.”97 As a result of
the proposed MOU between PG&E and OhmConnect, Dr. Anderson confirmed that
OhmConnect no longer has concerns over PG&E’s technology proposals and incentives.98
OhmConnect’s testimony raised concerns that SCE’s proposals for technology incentives
unnecessarily limited the set of eligible technologies to “programmable communicating
thermostats.”99 However, in response to a data request from OhmConnect, SCE explained that
the $75 incentive for programmable communicating thermostats “is not derived from, or related
to, the AutoDR incentives authorized by D.16-06-029.”100 If OhmConnect has determined it no
longer has concerns with PG&E’s AutoDR proposals because PG&E has agreed to a
collaborative process, then it follows that OhmConnect should no longer object to SCE’s
95 See Hearing Tr. Vol. III at pp. 308 “Edison would object to any settlement between just one IOU, with respect [to] ADR, given that Edison would not be a party to the negotiations. And there is a potential that the terms of that settlement could later be determined to apply to Edison in order to maintain consistency among the utilities with respect to their ADR programs.”
96 Id. 97 Hearing Tr. Vol. III at p. 308:14-18. 98 Hearing Tr. Vol. III at pp. 318:21-319:21 (Anderson). 99 OHM-01 at p. 2-3, lines 7-10. 100 See OHM-03.
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AutoDR proposals if SCE agrees to participate in this collaborative process. SCE is willing to
participate in a collaborative process with OhmConnect and other interested parties to address its
AutoDR program incentives. This collaborative process to discuss AutoDR technologies,
incentives, and enrollment requirements should be addressed in the New Models of DR
proceeding.101
b) IOUs Do Not Impair DRPs from Providing Technology Incentives to
Their Customers
OhmConnect argues that one way to ensure non-discriminatory treatment of third-party
DRPs and their customers is to require that “ratepayer-funded technology incentives authorized
by the CPUC should be available to residential participants in both IOU and third-party DR
programs, and on equal terms.”102 Although SCE addressed this argument in its rebuttal
testimony,103 the unreasonableness of OhmConnect’s argument bears further discussion here.
First, the third-party DR providers are not operating on equal terms: they are not regulated and
their programs are not subject to cost-effectiveness evaluations – two ways in which the
Commission can ensure that ratepayer funds are being prudently spent. When asked at hearings
whether ratepayer-funded incentives should be evaluated on equal terms, OhmConnect’s witness
stated “I would agree they should be evaluated on equal terms, yes.”104 Second, ratepayer-
funded technology incentives are available to residential participants in third-party DR
programs. SCE addresses each of these issues in turn.
When SCE is not the DRP, it has limited, if any, visibility into the performance of the
resource to determine whether the DR-enabling technology was used in response to the DR event
101 In its Response due July 26, 2017 to the Motion for Adoption of Settlement, SCE will further address its objections to an MOU between PG&E and other parties that purports to modify the AutoDR program.
102 OHM-01 at p. 2-3, lines 18-20. 103 SCE-05 at pp. 18:4-20:19. 104 Hearing Tr. Vol III at p. 331:3-12 (Anderson).
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signal. The statement by OhmConnect’s witness at hearing that “the utility would have some
visibility into the performance of the DRAM resource” is not entirely accurate.105 The
requirement in the DRAM pro forma agreement for the 2018-2019 DRAM period that requires
testing of the proxy demand resources or reliability DR resource used by a third-party DRP does
not provide the IOUs with the results of the performance of these third-party resources for each
DR event that is called. IOUs are also not provided information to determine whether any
enabling technology was used, but simply are given the information that a DR event occurred
and the resulting MWs that were delivered. The testing of the resources is merely to confirm that
the resources have the capacity to perform at the level indicated when they are registered with
the CAISO. Because SCE cannot verify the cost-effectiveness of funds spent on technologies
used in third-party DRP programs, it would contravene Commission policy and directives106 to
adopt OhmConnect’s recommendation that SCE provide technology incentives to customers in
third-party programs. Specifically, in the 2016 Decision Adopting Guidance for Future Demand
Response Portfolios and Modifying Decision 14-12-024, the Commission directed the IOUs to
utilize the 2015 Demand Response Cost Effectiveness Protocols, as adopted in D.15-11-042,
when the IOUs submitted their Applications for funding of their 2018-2022 DR Portfolios.107 At
hearing, OhmConnect’s witness confirmed that its DR programs are not subjected to a cost-
effectiveness test.108 It follows that it is only appropriate for IOUs to seek funding to administer
and provide incentives to customers in IOU DR Programs.109
105 See Hearing Tr. Vol. III at p. 328:13-16 (Anderson); see also Motion of OhmConnect to Correct Errors within Evidentiary Hearing Transcripts (filed July 7, 2017).
106 See D.12-04-045 (Decision Adopting Demand Response Activities and Budgets for 2012 through 2014); D.15-11-042 (Decision Addressing The Valuation of Load Modifying Demand Response and Demand Response Cost-Effectiveness Protocols), and D.16-09-056 (Guidance Decision).
107 D.16-09-056 at pp. 75-76 (Section 4.3.3. Miscellaneous Guidance for 2018-2022 Portfolios). 108 Hearing Tr. Vol. III at p. 321:20-26 (Anderson). 109 See SCE-05 at p. 19:7-9. “SCE should not provide technology incentives for DR awarded through a
competitive solicitation process, such as the DRAM, unless DRAM bids are subject to the same cost-effectiveness test as utility DR programs.”
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At hearing, OhmConnect’s witness agreed that “the Commission wants to know that
ratepayer funds are being prudently used to procure the demand response services of importance
and value to the state.”110 OhmConnect’s witness also affirmed his understanding that DR
provided by a third party under a DRAM contract is ratepayer-funded.111 As explained in SCE’s
rebuttal testimony, the costs associated with technology incentives should be included in the
contract the third-party DRP has with SCE to provide the DR services, or in the agreement
between the DRP and the customer.112 If the IOUs were to use ratepayer funds to pay the
contract price offered by the DRP and then provide the DRP with additional ratepayer funds for
incentives, the ratepayer would either be paying twice for the benefits of providing DR to the
grid or the third-party contract would not appropriately be factoring in all costs of the program to
ensure that the market selects the most competitive offers. SCE’s position continues to be that
the cost of these incentives should be incorporated into OhmConnect’s competitively based
offers into the wholesale marketplace. Moreover, SCE found the following testimony by
OhmConnect’s witness at hearings merits particular scrutiny:
A: These reports have indicated that the DRAM solicitations have been robust. There’s been a significant amount of participation both by residential and non-residential entities. So that being said, we have limited ability to control the prices that ultimately result in these markets. And in principle, we can offer any incentive we like. But we may not be able to recoup that incentive from the market revenues given the behavior of other actors.113
No third party should have any ability to “control the prices that ultimately result in these
markets.” Nor would the marketplace be selecting “contracts at competitively determined
110 Hearing Tr. Vol. III at p. 326:22-26 (Anderson); see also Motion of OhmConnect to Correct Errors within Evidentiary Hearing Transcripts (filed July 7, 2017).
111 Hearing Tr. Vol. III at pp. 324:24-325:2 (Anderson). 112 See SCE-05 at p. 19:9-16. “All costs associated with DRAM resources should be ‘loaded’ into the
offer or bid by the DRP, including technology costs, administrative costs, and customer marketing/acquisition costs. This provides visibility into the full price the IOUs are paying for DR procured through competitive solicitations. It also avoid the IOUs paying a contract price, then providing additional ratepayer funds to provide a technology incentive for the same DR resource.”
113 Hearing Tr. Vol. III at p. 330:12-22 (Anderson).
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prices” per Ordering Paragraph 8 in D.16-09-056 if a third-party DRP could control the prices.
If OhmConnect cannot recoup the incentives it offers from market revenues “given the behavior
of other actors,” then OhmConnect is not offering the most competitive product.
Another statement made at hearings by OhmConnect is not quite accurate. Specifically,
OhmConnect stated “what we are fundamentally after here is ensuring that there is fair treatment
of customers”114 – a principle with which SCE agrees – however, SCE does not agree with the
statement that “customers . . . are paying for those incentives that under the current proposal are
only available to customers in the SCE program.”115 As explained above, ratepayer-funded
incentives are available to customers in “a third-party program like OhmConnect’s when it is
providing RA capacity via DRAM to SCE”116 because OhmConnect includes the cost of
incentives in its current DRAM bids.117 While SCE is not privy to what incentive costs are
included in OhmConnect’s DRAM bids, OhmConnect’s website currently advertises the
following:
All OhmConnect community members now have $150 in credit to apply against smart
device purchases.118
OhmConnect’s argument that “it is extremely difficult for OhmConnect to match up-front
incentives of this magnitude” – $75 for SCE and $125 if the customer receives gas service from
SoCalGas119 – is unsubstantiated.
114 Hearing Tr. Vol. III at p. 329:7-9 (Anderson). 115 Id. at p. 329:15-19 (Anderson). 116 Id. at p. 329:11-13 (Anderson). 117 Id. at p. 329:28 “We do to a degree.” (Anderson). 118 Available at https://blog.ohmconnect.com/2016/05/24/open-for-business/ [as of July 24, 2017]. 119 OHM-01 at p. 2-3, lines 1-5.
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4. Peak Time Rebate (PTR or PTR-ET-DLC) Program
No parties objected to SCE’s PTR program and PCT incentives budget, but in its
testimony, OhmConnect raised concerns that customers participating in DRAM (through a third-
party DRP) are ineligible for the $75 thermostat credit.120 OhmConnect’s witness, Dr. Anderson,
further asserted that “some of the increased program enrollment [in SCE’s PTR program] is due
to customers switching to PTR from OhmConnect’s third-party DR program precisely because of
SCE’s $75 thermostat incentive”121—yet OhmConnect provided no evidence from any customers
to support this statement. This statement should be given no weight. Moreover, according to its
website, OhmConnect currently offers a promotion to give devices (like thermostats or smart
plugs) for free122 to its customers, and as of January 2017, OhmConnect started offering its
customers an opportunity to earn up to $75 for referrals.123
E. Demand Response Pilots, Including DRAM
1. Charge Ready Pilot
No party objected to SCE’s proposed Charge Ready Demand Response Pilot.124 The
Commission should approve SCE’s proposal as reasonable.
2. DRAM Pilot
SCE has recommended that the Commission support a stakeholder process similar to the
process used for the DRAM pilots to finalize the design of a full DRAM program, if the
Commission decides to proceed from a pilot into a full-fledged program.125 The California
Energy Efficiency Industry Counsel (Efficiency Council) and Joint DR Parties both support
120 OHM-01 at p. 2-2, lines 13-16. 121 OHM-01 at p. 2-2, line 23 – p. 2-3, line 2. 122 Available at https://shop.ohmconnect.com/collections/lottery-winners-free-device-promotion [as of
July 24, 2017]. 123 Available at https://blog.ohmconnect.com/2017/01/05/ohmhours-for-everyone/ [as of July 24, 2017]. 124 SCE-02 at pp. 45-53. 125 See SCE-02 at pp. 56:14-57:2.
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SCE’s proposal for a stakeholder process to finalize the design of a full DRAM program.126 No
parties objected to this request and therefore the Commission should direct a stakeholder process
to evaluate recommended changes from the DRAM Pilot analysis report and any changes to the
RA program that would need to be considered for a 2020-2022 DRAM program design.
F. Evaluation, Measurement and Validation
No party objected to SCE’s proposed EM&V activities or program budget.127 The
Commission should approve SCE’s proposals as reasonable.
G. Marketing, Education and Outreach (ME&O)
SCE is seeking approximately $14.3 million in funds to conduct its continued marketing,
education and outreach for DR programs and activities for the five-year cycle of 2018-2022.128
This proposed budget breaks out into approximately $2.8 million per year for SCE to update
program materials, launch customer acquisition campaigns, support the administration of
notifications/alerts to customers, and communicate program changes to customers and
aggregators. As explained in its testimony supporting its Application, SCE has streamlined
much of its marketing activities into its Statewide DR ME&O129 and IDSM activities.130 In
response to a line of questioning from ALJ Hymes, SCE’s witness confirmed that the ME&O
funding for the Statewide DR ME&O and IDSM activities is not included in SCE’s request for
funding in this DR Application.131 ALJ Hymes also asked if SCE could clarify “what all goes
126 See Response of Efficiency Counsel to Applications of PG&E, SCE, and SDG&E for Approval of DR Programs, Pilots and Budgets for 2018-2022, p. 7 (filed February 27, 2017). See also JDP-01 at p. 11.
127 SCE-02, Chapter VII at pp. 58-62. 128 SCE-02, Chapter VIII at p. 63. 129 See D.16-09-020, Decision Approving Implementer for the 2017-2019 Statewide Marketing,
Education, and Outreach Program and Providing Guidance for 2017 Activities (issued September 19, 2016).
130 See SCE-02, Chapter VIII at p. 63 and Section I in the brief. 131 Hearing Tr. Vol. I at pp. 104:21-105:19 (Lim).
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into the non-labor total?”132 SCE committed to respond and does so now.133 The ME&O Non-
Labor costs as listed in Table VIII-15 of Volume 2 of SCE’s direct testimony (SCE-02), include
activities such as marketing costs related to customer acquisition, program enrollment or change
notifications, updates to program materials (either online or print), and customer retention
campaigns.
1. The Objectives and Goals in the Statewide ME&O Proceeding Address
OhmConnect’s Parity Concerns
OhmConnect has taken the position that “ratepayer funds should be used to educate and
inform the ratepayers of all available demand response options and programs available for their
enrollment, including both IOUs and third-party.”134 SCE’s disagreement is not with
OhmConnect’s position, but with its suggestion that this DR Application is the appropriate
proceeding to address the issue. The Commission is already considering issues regarding the
funding and implementation of a Statewide ME&O campaign, “Energy Upgrade California”
(EUC) from 2017 onward.135 In D.16-09-020, the Commission approved a competitively
selected implementer for the EUC program and directed the newly selected implementer, DDB-
San Francisco, to collaborate with utilities and other stakeholders to develop a five-year ME&O
Strategic Roadmap (Roadmap) and Annual Joint Consumer Action Plans (Annual Plans). The
purpose of the Roadmap and Annual Plans is “to improve longer-term planning and coordination
between marketing efforts in a number of Commission proceedings, including energy efficiency,
demand response, and residential rate reform.”136 In the Statewide ME&O proceeding, the
132 Id. at p. 105:20-23. 133 Id. at p. 105:24-26. 134 Hearing Tr. Vol. III at p. 361:1-7 (Tongue). 135 See Hearing Tr. Vol. III at pp. 359:4–360:5 referencing (D).16-09-20 (Decision Approving
Implementer for the 2017-2019 Statewide Marketing, Education, and Outreach Program and Providing Guidance for 2017 Activities) (issued September 19, 2016).
136 See Amended Scoping Memo and Ruling of Assigned Commissioner in A.12-08-007 et.al. at p. 2 (filed June 20, 2017).
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Commission highlighted its intention that the Roadmap “incorporate demand response ME&O
objectives from R.13-09-011.”137 The parity that OhmConnect seeks by asking the Commission
to direct that ratepayer funds be used to market and educate customers about available energy
saving programs and technologies offered by third parties has already been discussed, evaluated,
and incorporated into the Statewide ME&O efforts.138
2. The AB 793 Proceeding Addresses OhmConnect’s Marketplace
Recommendations
OhmConnect recommends that each IOU: (1) create an online marketplace for DR
programs – both IOU and third-party – available to its customers; and (2) devote its ME&O
resources to promoting the marketplace, rather than specific DR programs.139 Neither
recommendation is appropriate in this DR Application proceeding. First, as explained in SCE’s
rebuttal testimony, the Commission has already determined that it is not appropriate for IOUs to
use their ME&O budgets to market programs administered by third parties.140 Second, the
Commission has already directed the IOUs to create energy technology marketplaces on their
websites that include Assembly Bill (AB) 793-relevant technologies by the Fourth Quarter of
2017.141 At hearing, OhmConnect’s witness took the position that the online marketplace “is
kind of out of scope of the context of this proceeding” and then stated “we can address this in
another proceeding”142 – which contradicts the position taken in his initial testimony.143
137 D.16-09-020 at p. 66. 138 See Advice 3508-E-A, Supplemental Submission of Advice 3508-E, Southern California Edison
Company’s October 1, 2016 through September 30, 2017 Statewide Marketing, Education, and Outreach Budget (filed December 15, 2016). Page 3 indicates SCE plans to contribute $23,871,585 of ratepayer funds to the Statewide ME&O efforts and the budget includes $6.948 million for demand response and energy efficiency activities.
139 See OHM-01, Chapter 3. 140 SCE-05 at p. 21:18-21 citing D.12-04-045. 141 See Hearing Tr. Vol. III at p. 360:6-10 (referencing AB 793 proceeding). See also Resolution E-4820
at pp. 34-35 (issued April 7, 2017). 142 Hearing Tr. Vol III at p. 357:19-27 (Tongue).
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Moreover, when asked on cross-examination whether it would be fair to address the online
marketplace in the AB 793 proceeding, Mr. Tongue responded “Yes.”144 Chapter 3 of
OhmConnect’s Prepared Testimony and the recommendations within should be deemed to be out
of scope for this proceeding.
H. Demand Response Systems Support
SCE utilizes many complex systems to successfully manage its diverse portfolio of DR
programs. These systems may be developed and owned by SCE or may be outsourced to third-
party vendors. There were no objections to SCE’s proposals with respect to Demand Response
Technology Projects, Enhancements, and Maintenance Projects.145 Only ORA objected to SCE’s
request for $6.4 million to support its proposal to enhance CAISO wholesale market integration
by reprogramming its CAISO-integrated Residential meters and its Non-Residential meters.146
CLECA supported SCE’s requested budget to reprogram these meters to ensure continued
successful integration of DR into the CAISO market.147 Notwithstanding ORA’s limited
opposition, the Commission should approve SCE’s proposal because SCE has a proven track
record of efficiently integrating DR into the CAISO market and is seeking only that funding
necessary to ensure continued success. The record supports SCE’s DR Systems Support
proposals and proposed budget as reasonable and the Commission should approve SCE’s
requested funding.
143 See OHM-01, Chapter 3. 144 Hearing Tr. Vol III at pp. 357:28-358:2 (Tongue). 145 SCE-02, Chapter IX, Section D at pp. 69:15–72:22. 146 SCE-02, Chapter IX at pp. 67:22–69:11; see ORA-01 at p. 2-3, lines 1-9. 147 CLC-01 at pp. 35:10–37:3 (“I support [this proposal]. It will provide data that are needed for
integration of several DR programs into the CAISO market with proper settlement. It will provide better data on response for faster-responding DR program[s]. In addition, once a local RA requirement is determined, 5-minute meter data may also help assess compliance.”).
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I. Integrated Programs and Activities, including Technical Audits
IDSM is a marketing strategy that merges the full range of demand-side management
options including DR, EE, and distributed generation (DG). The Commission directed that
IDSM funding be requested in the IOUs’ EE Applications post-2012, and therefore, SCE
included IDSM related costs in its EE business plan filing and included no IDSM costs in this
Application.148
J. Special Programs (Including Permanent Load Shifting)
1. Permanent Load Shifting (PLS)
The PLS program encourages investment in thermal energy storage to allow customers to
shift energy use to off-peak hours. In its testimony in support of its Application, SCE noted that
there has been a lack of interest in the PLS program and reported that PLS has a cost-
effectiveness TRC score of 0.10.149 ORA recommends that due to the low TRC score and the
lack of interest in the program, PLS should be eliminated.150 SCE agrees with ORA’s
recommendation to remove the PLS program from its 2018-2022 DR portfolio and instead
incorporate it as a part of the Self-Generation Incentive Program (R.12-011-005) or the
Commission’s storage proceeding in R.15-03-011.151
ORA recommends the Commission direct SCE to remove the $6,554,690 SCE requested
for PLS for the 2018-2022 DR program cycle.152 SCE agrees with this recommendation should
the PLS program be incorporated into another proceeding where funding may be sought. In
addition, ORA has also recommended that unspent funds from previous program years be
148 SCE-02, Chapter X at p. 74. 149 See SCE-02 at p. 38 and SCE-03 at p. 26, Table V-8. 150 ORA-01 at pp. 3-6 – 3-7. 151 See SCE-05 at pp. 6:12-7:2. 152 ORA-01 at p. 3-7.
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returned to ratepayers.153 SCE agrees that any unspent uncommitted funding should be returned
to ratepayers. However, SCE received one PLS application in late December 2016 that was still
being reviewed at the time SCE filed its 2018-2022 DR Application. As of June 30, 2017, SCE
had not received any new PLS projects for 2017 and had an unspent uncommitted balance of
$3,554,921. SCE does not know what the final unspent uncommitted amount will be as of the
end of 2017, because it is unknown how many additional PLS applications may be received for
the remainder of 2017.
In addition, the PLS program requires continuous monitoring of each installed project for
a period of up to 5 years. Therefore, SCE will require minimal funding for ongoing system
monitoring and would commit a portion of its 2017 unspent uncommitted funding for these
activities for the 2018-2022 period. The Commission may conclude that due to the minimal
number of PLS projects in existence, these monitoring activities should be waived. Currently
SCE has completed one PLS project that currently requires on-going monitoring. The PLS
program also has six in-flight committed and approved PLS applications. Should the
Commission adopt ORA’s recommendation and remove the PLS program from DR portfolios
and include it in a different proceeding, SCE requests the Commission allow SCE to carryover
its 2017 unspent uncommitted funding for the continuous monitoring efforts of its committed
and completed PLS projects, unless the Commission explicitly waives the continuous monitoring
requirement.
2. Optional Binding Mandatory Curtailment (OBMC) Program
SCE’s OBMC program proposals were unopposed and uncontested. The Commission
should approve SCE’s OBMC proposals as reasonable.154
153 Id. p. 3-7, lines 14-17. 154 SCE-02 at pp. 15:3–16:2 and Table II-3.
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3. Rotating Outages
Rotating outages are used during electric system emergency conditions to avoid
widespread or uncontrolled blackouts. SCE makes no recommendations for program changes,
but requests that the Commission remove the Rotating Outage program from future DR
applications because it is not a DR program.155 SCE recommends that funding for the Rotating
Outage program be requested in SCE’s GRC proceeding, along with other outage-related
initiatives.156 With no opposition to SCE’s recommendations, the Commission should approve
them as reasonable.
4. Scheduled Load Reduction Programs (SLRP)
No customers have enrolled in this statewide legislated program since 2010 and SCE
does not forecast any enrollments for the 2018-2022 DR program cycle.157 In the event that a
customer expresses interest in the program, SCE has proposed a nominal budget for the 2018-
2022 period. No parties raised any opposition or offered any recommendations for the SLRP.
III.
COST-EFFECTIVENESS OF PROPOSED DR PROGRAMS AND ACTIVITIES
Only two parties raised objections with respect to the cost-effectiveness of SCE’s
proposed DR programs and activities. First, ORA recommended that the Commission eliminate
the PLS program given its low-cost effectiveness score.158 SCE agreed with this
recommendation as described above in Chapter II, Section J.1. Second, the Joint DR Parties
objected to SCE’s AutoDR costs, arguing that SCE’s workpapers did not include AutoDR costs
in the cost-effectiveness calculations.159 In its rebuttal testimony, SCE clarified and affirmed
155 SCE-02 at pp. 17:20–18:3 and Table II-4. 156 SCE-02, p. 18:1-3. 157 SCE-02 at pp. 18:4–19:9. 158 ORA-01 at p. 3-7, lines 1-2. 159 JDP-01 at p. 44:6-18.
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that it did include AutoDR costs in its cost-effectiveness calculations as required by the protocols
and that these costs are visible in SCE’s workpapers.160 Additionally, the Joint DR Parties
recommended that SCE’s CBP be allocated a G-Factor of 105 percent, rather than the standard
100 percent, because it is integrated into the CAISO market and is dispatchable at the Sub-LAP
level.161 SCE explained in its rebuttal testimony why CBP does not qualify for the higher G-
Factor.162
ORA also raised a general recommendation to the Commission to revise the TRC
threshold for considering a DR program or portfolio to be cost-effective from 0.9 to 1.0, to be
consistent with the cost-effectiveness threshold of energy efficiency programs.163 SCE
responded to this recommendation in its rebuttal164 and ORA provides no support for its
recommendation to change the threshold outside of the R.13-09-011 proceeding where the
Commission and stakeholders are actively discussing and evaluating new models of DR. It
would be more appropriate to re-evaluate the cost-effectiveness threshold of DR programs and
activities in the current Rulemaking proceeding.
No other parties objected to the cost-effectiveness of SCE’s proposed DR programs and
activities and the Commission should find the record supports these proposals as reasonable.
IV.
REASONABLENESS OF BUDGET, COST, AND RATE RECOVERY REQUESTS
SCE’s full budget request for the DR portfolio program cycle 2018-2022 is summarized
in Appendix A of SCE-04, as modified in SCE-11 (filed July 19, 2017).165 The majority of
160 SCE-05 at p. 23:10-21. 161 JDP-01 at p. 43:9-26. 162 SCE-05 at pp. 24:15–25:3. 163 ORA-01 at p. 3-3. 164 SCE-05 at pp. 22:12-23:9. 165 SCE anticipates the motion for late-filed exhibits will be unopposed, and on that basis, SCE-10 and
SCE-11 would become part of the evidentiary record.
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SCE’s proposed budgets are unopposed, except for objections from ORA (who raised issues
regarding reprogramming of metering and the PLS program), OhmConnect (who raised issues
about the use of ME&O funds and ratepayer funded incentives for third party programs), and
CLECA and Joint DR Parties (who objected to SCE’s proposed changes to incentives for BIP-15
and BIP-30). SCE has addressed each of these objections in its rebuttal testimony and this brief.
In addition, SCE has addressed each question raised by the ALJs at hearing with respect to
various budget requests: EM&T program costs (Section II.D.1), Technology Incentives (Section
II.D.2), and ME&O (Section II.G).166 No party has made a sufficient showing that any of SCE’s
proposed budgets are unreasonable. The Commission should approve SCE’s budgets as
proposed.
V.
TARGETING DEMAND RESPONSE PROGRAMS IN CONSTRAINED LOCAL
CAPACITY PLANNING AREAS AND DISADVANTAGED COMMUNITIES
This section address the questions raised in Section 2.2 [Targeting Demand Response in
Specific Geographic Locations] of the June 30, 2017 Ruling.
Question 1: Which programs currently have the highest penetration (e.g., by MW and
number of customers) of demand response located within transmission constrained local capacity planning areas (i.e., Los Angeles Basin, Big Creek/Ventura, Stockton, and San Diego)? (IOUs and third party providers should answer as to their programs). What steps could be taken starting in 2018 to leverage these programs to increase demand response in local capacity areas?
Answer: The Base Interruptible Program, Agricultural & Pumping Interruptible, and Summer
Discount Plan programs have the highest penetration of demand response MWs and enrolled
Service Accounts (SA) in SCE’s local capacity areas (LCA) as shown in the table below.
166 See SCE-09 and Supplemental Workpapers for Emerging Markets & Technology and Technology Incentives; see also SCE-11 (Amended Supplemental Workpaper for Emerging Markets & Technology).
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Program - Local Capacity Area MW* % of Total SA Count % of
TotalBase Interruptible Program (BIP) - LA Basin [2] 493 73% 526 83%
Base Interruptible Program (BIP) - Ventura/Big Creek [2] 96 14% 79 13%
Base Interruptible Program (BIP) - Other [2] 88 13% 25 4%Total: 677 100% 630 100%
Agricultural & Pumping Interruptible Program (API) - LA Basin [2] 4 8% 138 12%
Agricultural & Pumping Interruptible Program (API) - Ventura/Big Creek [2] 44 88% 974 83%
Agricultural & Pumping Interruptible Program (API) - Other [2] 2 4% 65 5%Total: 50 100% 1,177 100%
Summer Discount Plan (SDP) Residential - LA Basin [1] 165 80% 196,940 78%
Summer Discount Plan (SDP) Residential - Ventura/Big Creek [1] 27 13% 40,988 16%
Summer Discount Plan (SDP) Residential - Other [1] 14 7% 16,225 6%Total: 206 [3] 100% 254,153 100%
Summer Discount Plan (SDP) Commercial - LA Basin [1] 30 79% 8,640 79%
Summer Discount Plan (SDP) Commercial - Ventura/Big Creek [1] 6 16% 1,831 17%
Summer Discount Plan (SDP) Commercial - Other [1] 2 5% 440 4%Total: 38 [3] 100% 10,911 100%
LA Basin Total 692 71% 206,244 77%Ventura/Big Creek Total 173 18% 43,872 17%Other Total 106 11% 16,755 6%
Grand Total: 971 100% 266,871 100%
*2016 Demand Response Program Load Impact Tables, Utility weather, 1-in-2, 2017, August Monthly Peak, Ex Ante Portfolio Aggregate load impact.[1] Summer Discount Plan Program SA count is actual enrollments as of July 11, 2017 pulled from SCE's Customer Service System.[2] Base Interruptible Program and Agricultural & Pumping Interruptible Program SA count is based upon forecasted enrollment for August 2017.[3] Figures may differ from those in SCE's annual load impact report due to differences in measurement methodology
SCE recommends taking the following two actions to increase DR in LCAs:
1) Increase the amount of reliability DR megawatts SCE can count toward its
resource adequacy (RA) obligation. SCE has instituted a waitlist with respect to
new enrollment in those programs in an effort to comply with D.10-06-034.167
167 Under the settlement agreement approved in D.10-06-034, reliability DR is capped at 2 percent of the CAISO all-time peak demand. This cap is apportioned to the three IOUs, and provides a limit on how
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Raising the cap will allow SCE to obtain more reliability DR, which may be
located in LCAs and/or disadvantaged communities (DAC). Many BIP customers
are large manufacturing facilities that may also be significant sources of
emissions. By increasing BIP capacity in high-emission areas, the surrounding
areas would likely see some benefit through reduced emissions and increased
reliability.
2) Authorize SCE to maintain the 20-hour minimum and maximum economic
dispatch authorized for SDP in the 2017 Aliso Canyon mitigation proposal.168
SCE proposed to continue the 20-hour minimum and maximum economic
dispatch for SDP in its 2018-2022 application.169 Dispatching DR resources as
needed, while preventing over-utilization, will aid in maintaining the valuable
MW enrolled in SDP and keeping program attrition at a minimum. As referenced
in SCE’s testimony, SDP has experienced high rates of attrition due to the
increase in program dispatches.170 Requiring a mandated minimum dispatch for
any DR product has the potential to create high rates of attrition and threaten grid
reliability while depriving customers of a bill management tool.
much reliability-based DR can be counted toward meeting the RA obligation. SCE’s current reliability DR is approximately 625 MW out of the 659 MW portion allocated to SCE. SCE expects to reach or exceed the cap shortly. See SCE-01 at p. 14:7-14.
168 D.16-06-029, at p. 23 and Conclusion of Law 3 at p. 87, approved SCE’s proposal to reduce the mandated minimum and maximum economic energy event hours to 20 for both SDP residential and commercial programs for program years 2016-2017.
169 SCE-02, Chapter III, Section B at pp. 29:21–30:1. 170 SCE-02, Chapter III, Section B at pp. 26:7-28:7.
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Question 2: What steps could be taken or program changes could be made over the 2018-2022 demand response cycle to increase demand response located within local capacity areas?
Answer: As discussed in more detail in SCE’s response to Question 1, the Commission should
take two steps to increase DR located within LCAs:
1) Raise the reliability DR cap.
2) Maintain the 20-hour minimum dispatch for SCE’s SDP.
In addition, SCE presents the following ideas as potential solutions. SCE does not
recommend these actions at this time, but identifies them as areas for future exploration in the
appropriate proceeding.
3) Should the DRAM pilot be extended into a DRAM program, consider permitting
more flexibility in valuation to include portfolio considerations, project viability
and other criteria so as to increase the success rate for signed projects.
4) Consider locational incentives for IOU programs. Currently, IOU programs
provide the same incentives to all eligible customers, regardless of their specific
location or benefits they provide. For example, all SDP customers are given the
same incentive, independent of whether they are located in a local area or not.
This discussion would need to balance customer fairness issues, with any
potential environmental, grid reliability or cost-effectiveness benefits.
Question 3: Would targeting enrollment of residential, commercial, or industrial
customers facilitate locating demand response in local capacity areas? Would this require additional funding? How much and for which programs?
Answer: SCE conducted targeted marketing and outreach in response to the SONGS closure
from 2012 through 2014 and in response to the Aliso Canyon Gas Storage closure in 2016 and
2017. As explained in its testimony, SCE expects “new enrollment campaigns will target
customers with high electrical usage, as done in the past, and target system-constrained areas as
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needed.”171 The marketing funds requested in SCE’s 2018-2022 DR Application are sufficient to
maintain this activity during the 2018-2022 program cycle. If the Commission directs SCE to
implement additional marketing efforts, more funding would likely be required.
Question 4: What are the barriers to identifying and enrolling customers located within
constrained local capacity areas?
Answer: A barrier to enrolling customers within LCAs172 is lack of customer awareness. SCE
recommends that increased targeted marketing be performed in conjunction with the Statewide
Marketing, Education and Outreach proceeding, A.12-08-007, and under the Energy Upgrade
California brand. As discussed further below, SCE recommends the Commission better define
the problem it is attempting to solve and undertake a study to identify potential solutions.
Question 5: Is additional information needed to inform options to increase demand
response in local capacity areas? If yes, please specify.
Answer: It is unclear from the questions posed in the Ruling what the specific problem is that
the Commission is attempting to address. Is the Commission attempting to address issues of
environmental justice, reliability, emissions, some other issue, or a combination of multiple
issues? The solutions that will work best will depend in large part on how the problem is
defined. SCE’s service territory has two LCAs: Los Angeles Basin and Ventura/ Big Creek,
each of which cover many square miles and a large number of customers. In addition, the San
Joaquin area has been identified as a disadvantaged area that may benefit from increased DR
enrollment. If the Commission desires to target low-income customers, DACs, or constrained
circuits within these areas, more information would be required.
SCE recommends that the Commission first define the problem it would like to address,
then undertake a study to gather information on capacity, transmission, and distribution
171 SCE-02 at p. 29:14-15. 172 By definition, all LCAs are constrained.
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deficiency in LCAs at a granular level. SCE recommends the study also measure customer
awareness of DR programs and benefits, and how DR has helped relieve capacity, transmission,
and distribution constraints in LCAs over time. Gathering this information will help parties
develop targeted solutions. Some of this work may already be occurring in the Distribution
Resources Plan proceeding, and this study should align with the work there.
Question 6: Pursuant SB 535 (Stats. 2012, Ch. 830) as codified in the Cal. Health and
Safety Code § 39711, the California Environmental Protection Agency developed the CalEnviroScreen tool and identified disadvantaged communities. In at least one instance the Commission has adopted a definition of eligible disadvantaged communities as the top quartile of census tracts as identified by CalEnviroScreen on either a state-wide or a utility-wide basis, whichever is broader. Is this a reasonable definition to use for the purpose of targeting demand response programs in disadvantaged communities?
Answer: SCE recommends the Commission adopt a consistent definition of DACs across all
proceedings. For that reason, SCE supports the definition proposed in this question, as it is
consistent with the definition proposed in the Integrated Resources Plan (IRP).
It is important to SCE that its DR programs, along with its other clean energy programs,
consider customer equity issues in program design. However, there should be greater discussion
around the question of where and how to target these programs. It is necessary to clearly define
the objectives that the Commission and other stakeholders are trying to achieve, so that SCE can
provide more meaningful input on the outcomes and processes. For example, if the priority is to
support the broad diffusion of DR, then the DAC definition proposed above may be sufficient
information to target DR programs. However, if the goal is to deploy DR programs in areas that
maximize customer bill savings or address locational issues, then SCE’s marketing goals and
outreach strategy could be materially different.
Finally, there are remaining procedural questions around the CalEnviroScreen. For
instance, when the CalEnviroScreen scores are next updated, what would happen if a particular
census tract exits the top quartile ranking after work has begun to increase DR penetration there?
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Questions like this can be discussed in a workshop or explored in the study recommended in
SCE’s responses to other questions.
Question 7: How do your responses to questions 1-4 above change if the goal is to further
prioritize increasing demand response customers located within local capacity areas that have a high percentage of disadvantaged communities, defined as proposed in question 5? Are there any overlapping approaches that could promote both goals? [Per the Administrative Law Judge’s Ruling Correcting Ruling of June 30, 2017,173 Question 7 was revised to refer to Questions 1-5 and Question 6 instead of Questions 1-4 and Question 5.]
Answer: Prioritizing DR customers located within LCAs that also have a high percentage of
DACs would not change SCE’s answers to any of the above questions. The same solutions that
can help non-disadvantaged communities can also help DACs. SCE’s outreach can target any
area desired, whether an LCA, a census tract, or a community, and is typically performed on a
territory-wide basis, which already includes DACs.
As discussed above, raising the cap on reliability DR may be able to specifically address
DACs by increasing the amount of MW that can be enrolled in BIP and AP-I. Many BIP
customers are large manufacturing facilities that may also be significant sources of emissions.
By increasing BIP capacity in high-emission areas, the surrounding areas would likely see some
benefit through reduced emissions and increased reliability.
To better target and address DACs located in LCAs, SCE recommends the Commission
first define the problem it is addressing, undertake a study to gather information on the problem
and potential solutions, and then work with stakeholders to craft and implement appropriate,
targeted solutions.
173 Issued July 12, 2017.
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VI.
COORDINATION BETWEEN THIS AND RELATED PROCEEDINGS
A. Response Time Requirement on Local Resource Adequacy Resources
As discussed by CLECA in their opening testimony,174 the CAISO has recently adopted a
change in the Availability Assessment Hours, which dictate when a resource providing Resource
Adequacy capacity has to bid into the market. Like CLECA, SCE is concerned about having
differing requirements for DR resources between the various jurisdictional entities – which could
result in increased costs to customers and higher barriers to entry for DR resources. SCE
encourages the Commission to work closely with the CAISO to coordinate reliability
requirements, such as the Availability Assessment Hours as well as the Local Capacity counting
rules. SCE recommends discussing this issue in the RA proceeding (R.14-10-010) and working
with the Commission and the CAISO to develop reasonable and coordinated requirements that
reflect the value of DR resources to grid reliability.175 While CLECA is correct in stating that
the “Commission has not adopted a 20-min response requirement for DR to count for local
RA,”176 it is reasonable for SCE to reflect CAISO requirements in the design and valuation of
DR programs – because if the CAISO finds a Local Capacity area deficient, it would require
additional (double) procurement, which would create additional costs for the customers.
B. Data Access Issues
The Scoping Memo included in the scope of this proceeding the question of whether the
IOUs’ programs sufficiently address data access issues for third party DRPs.177 In its response to
the Applications, OhmConnect identified an issue with asymmetric data access between the
IOUs and third-party DRPs and proposed several potential solutions aimed at facilitating the
174 CLC-01, pp. 39:13-40:18. 175 SCE-05 at p. 29:1-6. 176 CLC-01 at p. 23:4-17. 177 Scoping Memo, p. 3.
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transfer of customer usage data to third parties. OhmConnect proposed that: (1) the IOUs
establish a mechanism whereby customers can opt in to sharing their energy usage information
with qualified third parties; (2) the IOUs make available to qualified third-party DRPs
anonymized data for all utility customers; and (3) the IOUs display on their websites, alongside
their own DR programs, the DR programs offered by qualified third parties.178
Commission-approved mechanisms for sharing usage data with third parties already exist
via the CISR-DRP form, Green Button Connect, and the Rule 24 Click-Through process that is
under development. OhmConnect has not established that a new method is needed or
appropriate. In addition, any additional data-sharing method must comply with data privacy law
and rules. State law makes it impermissible for SCE, an electrical corporation, to “share,
disclose, or otherwise make accessible to any third party a customer's electrical or gas
consumption data, except as provided in subsection (e)179 or upon the consent of the
customer.”180 The Commission has also outlined a policy of data minimization, in which only
data that is necessary to provide a specific purpose should be provided to a third party,181 and
only with customer consent.182 Providing anonymized data sets without customer consent
conflicts with the data minimization policy established in SCE’s Rule 25. OhmConnect has not
demonstrated that its proposals would comply with customer protections afforded by state law
and Commission rules.
OhmConnect identified a concern that the IOUs’ proposed programs for 2018-2022 do
not eliminate barriers to data access, and therefore recommended that the Commission order the
178 Response of OhmConnect to Consolidated Applications for 2018-2022 Demand Response Programs, pp. 5-7 (filed February 27, 2017).
179 CAL. PUB. UTIL. CODE § 8380(e) explains primary purposes for the utility. 180 CAL. PUB. UTIL. CODE § 8380(b)(1). 181 D.11-07-056, pp.71-73. See also SCE Tariff Rule 25, “Protecting the Privacy and Security of
Customer Usage Information,” available at https://www.sce.com/NR/sc3/tm2/pdf/Rule_25.pdf 182 SCE Rule 25, Section 6.b.
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IOUs to establish an online marketplace for third-party and IOU DR programs, and to use IOU
ME&O funds to promote the marketplace, rather than the IOUs’ own programs.183 As SCE
described in its rebuttal testimony, this proposal raises concerns with duplication of SCE’s Rule
24 website and the marketplace ordered pursuant to AB 793, as well as a funding source for
continuous maintenance of data, and adherence to the IOU/DRP “firewall” established in D.15-
03-042.184 OhmConnect has not described how its proposal would address any of these
concerns. Further, as described in Chapter II.G above, at evidentiary hearings, OhmConnect
retreated from positions taken in direct testimony and confirmed the appropriateness of
considering ME&O issues, including its online marketplace proposal, in another proceeding such
as Statewide ME&O or AB 793.
Data access issues are currently being explored in other proceedings, including the DR
OIR (R.13-09-011), the Integrated Distributed Energy Resources (IDER) and Distribution
Resource Plan. Care should be taken not to duplicate efforts, but to have a consistent venue to
consider data access issues. As described above, OhmConnect’s customer data access issue is
best considered in R.13-09-011. Therefore, for the purposes of its 2018-2022 DR Application,
SCE’s proposals appropriately coordinate with other proceedings and sufficiently address data
access issues for third-party DRPs until those issues are completely resolved in other venues.
C. Baselines
In its initial testimony, SCE explained how it has been working within the CAISO
Energy Storage and Distributed Energy Resources (ESDER) Phase 2 initiative through two
separate working groups: the Baselines Analysis Working Group (BAWG) and the Load
Consumption Working Group.185 Based on the record in the proceeding, many of the parties are
in agreement that the Commission should require its staff to participate in the development of
183 OHM-01 at pp. 3-1 – 3-5. 184 SCE-05 at p. 21:3-21. 185 SCE-01 at pp. 21:19–22:10.
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alternative baselines that is currently under discussion at the CAISO in the ESDER stakeholder
initiative.186 More recently, in the R.13-09-011 proceeding, SCE filed comments explaining that
while it does not oppose comments emphasizing the importance of aligning retail and wholesale
baselines, SCE cautions against focusing on perfect alignment over the intended purpose of
baselines, which is to measure performance accurately.187 SCE supports the Commission
continuing to explore baselines in the R.13-09-011 proceeding and recommends the Commission
create a working group to consider and build on the work done in the CAISO’s BAWG. SCE
recommends workshops in the second quarter of 2019 after the IOUs have a full year of
bifurcation under our belts and after implementation of the prohibited resources requirements for
DR.
VII.
REASONABLENESS OF PG&E PROPOSAL FOR POST-2019 DRAM COST
RECOVERY
SCE has no comment on this.
VIII.
INTEGRATION OF DEMAND RESPONSE AND ENERGY EFFICIENCY
SCE appreciates the Commission including the integration of energy efficiency (EE) and
demand response (DR) in the scope of the EE Business Plan Application and DR Funding
Application proceedings. The Staff Proposal includes some recommendations that have merit
regarding the technical integration of EE and DR. However, SCE recommends that the
Commission establish policy goals for the integration of EE and DR and a roadmap to achieve
them.
186 JDP-01 at pp. 40-41; CLC-01 at pp. 38-39. 187 See SCE’s Reply to Responses to Questions Regarding the Pathway to New Models of Demand
Response and Remaining Barriers to the Integration of Demand Response into the CAISO Market at p. 5 (filed July 17, 2017).
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As SCE explained in its EE Business Plan, to help California meet its ambitious energy
goals and address challenges of grid modernization, the Commission should take certain
regulatory actions to maximize the usefulness of demand-side management (DSM) resources.188
The Commission first should establish resource need (supply and demand) and goals in an
integrated resource setting, such as is underway in the Integrated Resource Planning (IRP) effort.
SCE recommends that individual DSM resource goals be replaced by a common goal to which
all DSM resources can contribute, such as greenhouse gas (GHG) reduction. The Commission
should also establish common measurement and valuation protocols, including cost-effectiveness
evaluations, to enable IOUs and DSM program administrators (PAs) to evaluate and select
resources. In addition, the Commission should consolidate resource funding (for example, EE
and DR funding) to facilitate resource allocation among DSM resources (i.e., among programs,
resource types (EE and DR), and procurement strategies (e.g., third-party solicitations, IOU/PA
program, etc.)).
SCE recognizes that all of these activities will take time to develop and that they should
not be implemented until after the current funding applications for EE and DR are resolved.
Establishing the ultimate goals for integration of EE and DR, though, will help parties and the
Commission better evaluate whether proposed activities are effective toward achieving those
goals.
COMMENTS ON STAFF-RECOMMENDED INTEGRATION ELEMENTS 1-3
1. Integration Element 1 – Residential time-of-use (TOU)-enabling Thermostats:
a. Comment on the merits of the proposal, explaining your rationale.
SCE addresses the merits of each of the five projects within Integration Element 1 below.
In general, Integration Element 1 is narrowly focused on device adoption and preparation for
default residential TOU rates and less on identifying and removing policy and implementation
188 See SCE’s Amended EE Business Plan, pp. 4-5.
47
barriers to the integration of EE and DR. It is essentially combining incentives rather than
integrating two DSM resources.
Project #1: Coordinate TOU outreach efforts with EE, DR, and AB 793 efforts: SCE
believes this recommendation is redundant to current activities. For example, SCE’s TOU-
related education and outreach already directs customers to DR and EE solutions that can help
them manage their energy usage. In addition, the Commission recently approved SCE’s AB 793
education and outreach plan related to energy management technology solutions for EE and DR.
Also, the Staff Proposal states that this activity “could be completed internally at the CPUC.”189
It is unclear how coordination of activities being developed and implemented by the PAs could
be internally coordinated at the CPUC. SCE recommends the Commission not include this
project in its EE/DR integration efforts.
Project #2: Market and evaluate price-responsive thermostats within PG&E’s
SmartRate program, allowing participants to automate response to TOU rates and CPP
events: SCE supports marketing and evaluating price-responsive thermostats in an effort to
determine DR value for those devices. The Staff Proposal states, “With default residential TOU
prices on the horizon, customers will benefit if the CPUC and IOUs prioritize the effort to
publicly post the new TOU rates on existing IOU OpenADR servers.”190 If the Commission
decides to pursue this project, it should consider whether it will be more efficient to have a large
number of residential customers connect to the IOU systems or if it should be done through third
parties.
Project #3: Collect Standard Usability Scale (SUS) scores for EMTs being used or
considered for use at IOUs: SCE opposes the inclusion of this project. Whether user-friendly
energy management technologies (EMTs) enhance automation is something that can be
189 Staff Proposal, p. 31. 190 Staff Proposal, p. 25.
48
considered for EE or DR and is not necessarily a function of the integration of the two resources.
The consideration of whether IOUs should collect SUS scores would be more appropriately
considered in the IOUs’ AB 793 EMT plans. SUS scores may support EMT adoption and
procurement decisions, but they do not necessarily affect integration of EE and DR and may not
correlate with actual adoption of EMTs.191 Therefore, SCE recommends the Commission
exclude this project from its EE/DR integration efforts as it takes the focus away from the
integration of two DSM resources and concentrates attention on devices.
Project #4: Work with industry and marketing experts to agree on standard customer-
friendly EE, TOU, and DR terminology: SCE supports inclusion of this project in the EE/DR
integration effort. SCE recently enlisted various naming/branding research experts to conduct
extensive research to identify best practices and to develop an approach for naming SCE’s
portfolio of programs, products, services, and rates. A key finding from the research is that
terminology that is clear, descriptive, intuitive, and benefit-oriented helps customers make better
decisions about which offerings are best suited to their needs. Names should also be tested
qualitatively and quantitatively with customers prior to their formal introduction to identify
potential linguistic or cultural issues that could negatively affect the customer experience.
Project #5: Work with vendors to develop and pilot a cost-effective TOU-friendly
thermostat, focusing on usability and effectiveness for low-income homes: SCE supports
inclusion of a variation of this project in the EE/DR integration effort. The focus should be on
developing a methodology to establish the incremental value of existing smart thermostats for
low-income customers, rather than the development of an entirely new device. Current smart
191 Research findings from a Smart Thermostat usability study commissioned by Sacramento Municipal Utility District (SMUD) highlighted that ease of use, and likewise SUS scores, are not a significant predictor for market preference. In fact, market-leading smart thermostats scored lower on SUS scores due to innovative or proprietary product designs, yet lead market adoption and DR program participation, indicating that SUS scores may not be a significant predictor of DSM program participation. SMUD’s study is available at http://www.herterenergy.com/pdfs/Publications/2014_Herter_CommunicatingThermostatUsability.pdf
49
thermostat devices in the market have pre-programming capability that if programmed correctly
are well-suited to managing customer demand on a TOU rate structure.
b. What changes would you recommend and why?
As stated in SCE’s response to Question 1a, the Commission should eliminate proposed
projects 1 and 3 from Integration Element 1. SCE also recommends identifying additional
barriers to EE and DR integration and deferring much of the TOU-related customer outreach to
the TOU proceeding.
c. Is the budget appropriate, or should it be amended? How and why?
Because the project descriptions are high-level, it is difficult to assess whether the
budgets are appropriate. Also, several of the proposed activities are already occurring, so it is
unclear whether any additional budget is needed for such activities. Finally, the total budget of
$690,000 includes $420,000, or approximately 60 percent, in consulting fees.192 Given that the
implementation of many of the projects are the responsibility of the IOUs, the IOUs should make
the determination of whether consultants are needed.
d. Are the technologies recommended appropriate? Why or why not?
While EMTs are one appropriate technology to consider, SCE recommends that the
Commission’s efforts to integrate EE and DR focus less on specific devices and technologies and
more on processes, regulations, program rules, and barriers related to integrating the two
resources. Once the Commission establishes its goals for integration of EE and DR, third parties
and PAs should be able to propose program ideas that are not constrained to particular programs
or technologies.
192 See Staff Proposal, Appendix A, pp. 31-33.
50
e. Should this proposal be coordinated with any other aspects of the energy efficiency or demand response portfolios and why?
This proposal should be coordinated with the AB 793 and TOU implementation efforts to
avoid redundancy.
f. Is there a role for Commission and ratepayer funded activities related to standardization and interoperability of relevant technologies? What do you recommend?
The Commission has an important role related to standardization and interoperability of
technologies, which is necessary to allow IOUs or third parties to leverage products in the
marketplace as DSM resources. Standardization can reduce DSM program operational costs,
increase customer choice, and incrementally increase the availability of DSM resources. A good
example of the effectiveness of Commission and ratepayer-funded activities related to
standardization is the development of the OpenADR standard, which is now a national standard.
This standard has enabled IOUs to take advantage of the new smart thermostats currently in the
marketplace without sacrificing or stifling the technical innovation the market can deliver.
Standardization has thus allowed customer choice in the marketplace and fostered true
competition among vendors.
g. What can and/or should the Commission do to ensure utility provision of pricing data to customers to facilitate use of control technologies?
In SCE’s view, customers are generally concerned more with their bill amount than
pricing data. SCE already provides useful bill-related information to customers through online
and automated tools such as SCE’s MyAccount Budget Assistant, Bill-to-Date, Energy Advisor,
and SCE EnergyManager® Suite of Tools (non-residential customers). In addition, through AB
793 implementation efforts, SCE will seek third-party solutions from the marketplace that
leverage real-time energy information from the customer’s smart meter and/or coupled devices.
Therefore, SCE does not recommend additional action from the Commission related to pricing,
usage, and billing data at this time.
51
2. Integration Element 2 – Non-residential lighting, HVAC, and other:
a. Comment on the merits of the proposal, explaining your rationale.
Similar to the first element, Integration Element 2 is focused on addressing the
integration of technology measures and does not address policy issues related to integrating EE
and DR. In general, the proposal has merit in its assumption that providing incentives for
including DR capability with EE measures may help achieve greater integration of EE and DR.
However, previous evaluation studies193 have shown that this approach has had limited success
due to a number of factors such as the restrictions from specific rules and processes associated
with the EE and DR program portfolio structures.
SCE agrees with the approach to leverage third parties as much as possible. However,
the proposal does not align with the Commission’s requirement for third-party EE programs that
“to be designated as a third-party program, the program must be primarily designed and
presented to the utility by the third party, in addition to delivered under contract to a utility.”194
By specifying certain programs and measures to be integrated, the proposal appears to be taking
program design out of the hands of the third parties.
b. What changes would you recommend and why?
Rather than specifying certain programs and measures to be integrated through additional
incentives above and beyond the current program models, SCE recommends that the IOUs
include in their third-party solicitations for EE programs a request for programs that integrate EE
and DR and allow third parties to propose innovative proposals. This will allow the market to
drive the inclusion of AutoDR technology in EE measures where appropriate. If the
Commission and the IOUs select the EE programs to be combined with AutoDR without a
thorough analysis and understanding of likely adoption rates and incremental costs, there may be
193 See Itron IDSM Omnibus Study, 2012, available at http://www.calmac.org/publications/CPUC_IDSM_FinalReport.pdf
194 See D.16-08-019, pp. 69-70.
52
a risk that ratepayer funds will be used to incentivize the development of an integrated
technology that ultimately may not be used to its full potential. SCE had limited success
integrating AutoDR with established EE programs with set rules and processes, and therefore
SCE recommends that some of SCE’s pilot challenges be examined before developing more
detailed proposals.
As noted in the Staff Proposal, Integration Element 2 is “a starting point for
discussion.”195 Therefore, if the Commission decides to move forward with the proposed
integration element, SCE recommends that the Commission establish a workshop or working
group to analyze and discuss the specific proposals prior to requiring the IOUs to file advice
letters with more concrete proposals. SCE has conducted similar Integrated Demand Side
Management (IDSM) studies in the areas of lighting, new construction, pumping, and HVAC
integration and the working group would benefit from the discussion regarding the project
outcomes.
c. Is the budget appropriate, or should it be amended? How and why?
It is difficult to project a budget at this time considering the proposal is a list of potential
projects that are a starting point for discussion. It appears that the proposed budget of $18.93
million is a repurposing of the IOUs’ previously authorized IDSM funds and not a “bottom up”
estimate based on assumptions about project goals, incentive levels, customer uptake, etc. SCE
recommends that a budget for the proposed activities be based on the desired policy objectives
and technical capabilities and potential of the markets, and should be developed after parties
discuss and analyze the proposals.
195 Staff Proposal, p. 33.
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d. Are the technologies recommended appropriate? Why or why not?
SCE recommends that a working group or workshop examine the recently completed EE
and DR potential studies196 to more fully assess the potential and appropriateness for technology
integration. While many end uses such as lighting, HVAC, and pumping meet EE program
requirements, the ability to participate in DR programs may not be as obvious. Including
technology stakeholders in the working group discussion will provide a more informed
assessment and could also identify gaps and opportunities for EE/DR measure integration.
e. Should these strategies be a full-scale program or initiated in some kind of limited, pilot fashion? Explain your rationale.
For any implementation that is new or has not been widely used before, SCE
recommends a demonstration project or scaled deployment before evolving to a full-scale
program. This approach enables stakeholders to identify cost-effective opportunities that can
best address the goals of the full-scale program while limiting funding risk. However, it should
be noted that SCE has already completed several IDSM projects and scaled deployments and has
successfully integrated EE and DR measures and processes at the program level in several of its
current IDSM program activities. These are discussed more in SCE’s response to Question 7.
In addition, if EE measures such as energy management systems, HVAC, and retrofit
lighting ballasts are required to be DR-ready without analysis and understanding of likely
customer enrollment and participation in DR, there is a risk that ratepayer funds will be used to
pay for features that are not being used. DR requires customer education, program enrollment,
and ongoing communication and participation, unlike most EE measures that do not affect
customer operations and/or comfort and are often “set it and forget it” types of measures. These
196 EE Draft 2018 Potential & Goals Study available at: http://www.cpuc.ca.gov/general.aspx?id=6442452619; DR Potential Study documents available at: http://www.cpuc.ca.gov/General.aspx?id=10622
54
programmatic concerns should be addressed before implementing a full-scale program for any
integrated measure.
f. What is the best way to facilitate customer participation in these types of programs and maximize their use of the relevant technologies?
Based on SCE’s experience, an effective way to facilitate customer participation in these
types of programs is to first review and analyze service account energy usage information for
different building types and develop a monthly pipeline to summarize the types of identified
buildings and other relevant account information. After identifying potential service accounts
for the programs, SCE would develop a comprehensive, multi-channel campaign with optimal
channel mix to target the accounts and building types to generate awareness and enrollments of
EMTs. Effective means of generating awareness and enrollments include: (1) customer and
contractor collateral, direct mail and email for lead pre-qualification; (2) leveraging of
community and business associations (i.e., peer-to-peer influence); and (3) focused one-on-one
customer outreach.
g. Should funding be made available for automated demand response incentives and/or incorporating demand response technologies into energy efficiency programs?
A preferred solution would be to have a single source of funding for both EE and DR as
that would eliminate issues of whether certain funds can be used for certain activities. If the
Commission continues the current situation of separate funding sources for EE and DR, SCE
agrees that funding should be available for incorporating DR technologies into EE programs,
assuming programs can be designed to validate that the DR functionality is being used by the
customer.
h. Should funding be made available for training and education of market actors? If so, how much and why?
Adoption and utilization of automated DR technologies could be improved by providing
additional training and education for market participants (e.g., contractors, retailers, property
owners/managers, customers, design professionals). A study performed by PG&E
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acknowledged needed improvement in this area. Specifically, the study states, “[c]urrent
awareness of the role of demand response remains quite low so continued and increased
education regarding the code requirements as well as the overall need for, and the potential
financial benefits of demand response as an energy management practice can be effective at
increasing market awareness and improving compliance with the code.”197 Market participants
each play a role in attaining and participating in DR programs. “Recognizing the differences
between the groups’ interest in technical systems, regulatory compliance, and market opportunity
can increase the impact of an outreach campaign.”198 The scope and potential benefits of
providing these activities should be identified before funding and budget amounts can be
determined.
3. Integration Element 3 – Combined energy efficiency and demand response potential research
a. Comment on the merits of the proposal, explaining your rationale.
SCE supports the Staff Proposal to combine the methodology from the first CPUC DR
Potential Study into the EE Potential Study scheduled to be published May 1, 2019.199 SCE
recommends the Commission transition to having a common goal, such as GHG reduction
targets, for DSM programs rather than having individual goals, such as kilowatt hour (kWh) and
megawatt (MW) savings for EE and participation and MW goals for DR. This will provide load-
serving entities greater flexibility to determine the most cost-effective means of achieving the
state’s GHG reduction targets. Combining the EE and DR Potential Studies is an important first
step in being able to move toward a common goal for DSM resources.
197 Misti Bruceri & Associates, LLC, PG&E’s Emerging Technologies Program, Automated Demand Response in Title 24, Part 6: Stakeholder Outreach Assessment. San Francisco: (April 2017), p. 29. Available at http://title24stakeholders.com/wp-content/uploads/2017/07/Automated-Demand-Response-in-Title-24-Final.pdf
198 Id. 199 Staff Proposal, p. 14.
56
b. What changes would you recommend and why?
The Staff Proposal states that the specific details about how to conduct the DR potential
study in combination with the EE study “can be worked out by staff and its consultants.”200 SCE
recommends that these discussions include the Demand Analysis Working Group (DAWG). The
DAWG focuses on “methods and approaches for including demand modifiers in demand
forecasts, including demand response, distributed generation, transportation electrification and
additional achievable energy efficiency.”201 Thus, the DAWG has experience in assessing
impacts from both EE and DR.
c. Should the Commission re-authorize $1 million annually for five years from the DR applications for this continued research? Is the budget appropriate, or should it be amended? How and why?
SCE does not oppose the Commission re-authorizing $1 million annually for five years
from the DR applications for this continued research. However, SCE recommends that the
budget be reassessed after a detailed scope of work is developed.
d. Comment on whether or not it is appropriate to link work in the integrated resource planning proceeding to potential and goals for energy efficiency and demand response.
It is appropriate to link the work in the IRP proceeding to potential and goals for EE and
DR because one of the purposes of the IRP is to enable load-serving entities to “[m]eet the
greenhouse gas (GHG) emissions reduction targets established by the CARB for the electricity
sector and that reflect the electricity sector’s percentage in achieving the economy-wide GHG
emissions reductions of 40 percent from 1990 levels by 2030.”202 To be able to do this, the
Commission will need to understand the effects of EE and DR on each other and their combined
potential to contribute to GHG reductions.
200 Id. 201 Available at http://www.dawg.info/about-demand-analysis-working-group. 202 R.16-02-007, p. 9.
57
Other/General Questions
4. If the Commission adopts the proposed integration elements for energy efficiency and demand response, or some sub-set that you recommend, how will this integration affect cost-effectiveness of either energy efficiency or demand response programs? Why?
SCE does not anticipate a significant effect on EE cost-effectiveness from further
integration of EE and DR because the proposal consists primarily of adding DR incentives to
existing EE measures. Some of the proposed integration projects could result in increased
adoption of EE measures, leading to potential increases in EE savings. This reduction in energy
usage reduces overall DR potential. In that scenario, the DR cost-effectiveness would likely be
lower. However, SCE expects that combining DR incentives with EE measures may result in
DR that would not have otherwise occurred. Thus, while the DR potential may be lowered by
the EE, if the DR would not have occurred in the first place, the DR benefit is higher, which
could positively affect DR cost-effectiveness.
5. What changes should the Commission make to program rules, including participation rules or rules about funding of incentives, if any, to facilitate rational integration of energy efficiency and demand response technologies in residential and non-residential buildings?
Parties will be able to better determine specific program participation rules that may need
to change once detailed integration plans are developed. An AutoDR program participation rule
that may be a hindrance to greater adoption of integrated EE and DR offerings is the requirement
that customers must have at least 12 months of usage history for a service account to be eligible.
The Commission should provide utilities greater flexibility and application of this administrative
requirement to allow customers and businesses that do not meet the requirement to take
advantage of integrated EE and DR offerings.
As noted in SCE’s response to Question 2a, for a program to count as a third-party
program in an IOU PA’s EE portfolio, it must be designed, proposed, developed, and
implemented by the third party. In addition, each IOU PA must transition at least 60 percent of
its EE portfolio to be outsourced to third parties by the end of 2020. If the Commission adopts
58
any of the proposals under Integration Element 2, which have been proposed and, at a high-level,
designed by Energy Division, the Commission should make an exception to the requirement
from D.16-08-019 and allow these programs to qualify as third-party programs if they are
awarded to a third party through a competitive solicitation process.
As stated in its Amended EE Business Plan, SCE recommends that the Commission
develop a unified DSM funding authorization process in advance of the next funding
applications because it “will allow utilities greater flexibility to allocate funds between programs,
resources (e.g., EE and DR), and procurement vehicles in order to achieve overarching DSM
goals.”203 SCE welcomes any flexibility the Commission will authorize to combine EE and DR
funds to develop integrated offerings for customers.
6. If the Commission directs a limited integration between demand response and energy efficiency, is the proposed list of actions that could be taken in this proceeding, as listed on pages 17 and 18 of the Staff Proposal, appropriate and sufficient? If you recommend that certain activities be added or subtracted, explain your reasoning.
SCE assumes this question is referring to the Table entitled “Proposed Action for
Relevant Proceedings” on pages 16 and 17 of the Staff Proposal. In general, the actions on pages
16 and 17 of the Staff Proposal are appropriate for the EE Business Plan and DR Funding
Application proceedings if the Commission directs a limited integration of EE and DR.
However, the scope of the actions should be amended based on SCE’s recommendations
discussed in these comments. For example, one of the actions in the Staff Proposal for the EE
Business Plan application is to “Direct proposed Integration Elements 1 and 2, including related
implementation and advice letter process.”204 SCE agrees that the action to propose certain
integration elements should occur in the EE Business Plan application, but SCE disagrees that
Integration Elements 1 and 2 should be proposed as defined in the Staff Proposal and SCE
203 SCE Amended EE Business Plan, p. 5. 204 Staff Proposal, p. 16.
59
recommends additional analysis through a workshop or working group effort. Thus, the table
should be modified to refer to solutions ultimately adopted by the Commission and not the
proposed elements in the Staff Proposal.
7. If the Commission re-purposes the integrated demand side management funds currently authorized as part of the energy efficiency portfolios, as suggested by staff, are there any activities that are currently funded through this mechanism that should be continued? Explain.
SCE currently utilizes the IDSM funding approved in the EE bridge funding decision in
2014205 to conduct integrated activities, pilots, and other programs with integrated approaches
that combine EE and DR. These have included statewide IDSM regulatory coordination, DR
IDSM integrated programs and activities (including technical assistance, local IDSM marketing
support, and DR IDSM pilots. Currently, in coordination with SCE’s EE portfolio, there are a
number of these DR IDSM activities continuing with specific integrated program commitments
for customer delivery. These include the statewide IDSM regulatory coordination, the DR IDSM
integrated programs and activities (which includes technical assistance, DR Energy Leader
Partnership, and DR Institutional Partnerships), the local IDSM marketing program, and a
number of IDSM pilots (some of which were identified in the Staff Proposal). While all of the
DR IDSM program activities are continuing this year, there are some pilots that are winding
down or that have sunset. SCE recommends continuing and completing any in-flight activities.
It is important to note that doing so may result in limited funding being available for the
activities in the Staff Proposal. Therefore, SCE recommends a workshop or working group to
assess the current IDSM activities and the activities in the Staff Proposal to determine which
activities should be continued and or implemented and to establish appropriate budgets for the
activities. To the extent there are IDSM funds remaining, the Commission should consider
authorizing the IOUs to use those funds to support their AB 793 implementation activities
205 D. 14-10-046, p.107.
60
because (1) there were additional requirements added to the final resolution without an
opportunity to request funding to implement such requirements; and (2) these activities
contribute to integration of EE and DR.
8. Are there additional activities and associated funding that the Commission should consider for better energy efficiency and demand response integration outside of those proposed by staff in the attached proposal?
The Staff Proposal is limited in that it focuses primarily on “automated energy
management technologies that integrate EE and DR.”206 While these proposals are important to
consider, SCE recommends the Commission establish overarching policy objectives and goals
for the integration of EE and DR. These should include a common goal for EE and DR (and
potentially other DSM resources); a common funding source to enable flexible use of customer
funds for EE, DR, and the combination of the two (and potentially other DSM resources); and
updated cost-effectiveness protocols that enable appropriate evaluation of combined EE and DR
portfolios. The integration of EE and DR should not be limited to automated energy
management technologies because there are other means to achieve integrated EE and DR.
206 Staff Proposal, p. 4.
61
9. Provide any other comments on the Energy Division Staff Proposal or the
general subject of integration of energy efficiency and demand response activities.
If the resolution of EE/DR integration issues will delay the Commission issuing a
decision on SCE’s DR Application for funding of the 2018-2022 program cycle, SCE
recommends that the integration issues be addressed in a separate track so as to avoid further
delay to a decision on the DR Application.
Respectfully submitted,
FADIA RAFEEDIE KHOURY ROBIN Z. MEIDHOF
/s/ Robin Z. Meidhof By: Robin Z. Meidhof
Attorneys for SOUTHERN CALIFORNIA EDISON COMPANY
2244 Walnut Grove Avenue Rosemead, California 91770 Telephone: (626) 302-6054 Facsimile: (626) 302-6693 E-mail: [email protected]
July 24, 2017
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE
STATE OF CALIFORNIA
Application of Pacific Gas and Electric Company (U 39-E) for Approval of Demand Response Programs, Pilots and Budgets for Program Years 2018-2022.
A.17-01-012 (Filed January 17, 2017)
And Related Matters.
A.17-01-018 A.17-01-019
CERTIFICATE OF SERVICE
I hereby certify that, pursuant to the Commission’s Rules of Practice and Procedure, I have this day served a true copy of SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E) OPENING BRIEF on all parties identified on the attached service list(s) for A.17-01-012, et al. Service was effected by one or more means indicated below:
Transmitting the copies via e-mail to all parties who have provided an e-mail address. Placing the copies in sealed envelopes and causing such envelopes to be delivered by US
Mail to the offices of the Commissioners(s) or other addresses(s).
ALJ Nilgun Atamturk CPUC 505 Van Ness Avenue San Francisco, CA 94102
ALJ Kelly A. Hymes CPUC 505 Van Ness Avenue San Francisco, CA 94102
Executed this July 24, 2017, at Rosemead, California.
/s/ Sandra Sedano Sandra Sedano Legal Administrative Assistant SOUTHERN CALIFORNIA EDISON COMPANY
2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770
PROCEEDING: A1701012 - PG&E - FOR APPOVAL O FILER: PACIFIC GAS AND ELECTRIC COMPANY LIST NAME: LIST LAST CHANGED: JULY 24, 2017
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ERIKA DIAMOND DAVID P. LOWREY ENERGYHUB DIRECTOR, REGULATORY STRATEGY 232 3RD STREET, SUITE 201 COMVERGE, INC. BROOKLYN, NY 11215 999 18TH STREET, SUITE 2300 FOR: ENERGYHUB DENVER, CO 80202 FOR: COMVERGE, INC.
ROBIN MEIDHOF DONALD C. LIDDELL SR. ATTORNEY ATTORNEY SOUTHERN CALIFORNIA EDISON COMPANY DOUGLASS & LIDDELL 2244 WALNUT GROVE AVENUE 2928 2ND AVENUE ROSEMEAD, CA 91770 SAN DIEGO, CA 92103 FOR: SOUTHERN CALIFORNIA EDISON COMPANY FOR: CALIFORNIA ENERGY STORAGE ALLIANCE
DONALD KELLY, ESQ. E. GREGORY BARNES EXECUTIVE DIRECTOR ATTORNEY UTILITY CONSUMERS' ACTION NETWORK SAN DIEGO GAS & ELECTRIC COMPANY 3405 KENYON STREET, STE 401 8330 CENTURY PARK COURT, BLDG 3. CP32D SAN DIEGO, CA 92110 SAN DIEGO, CA 92123 FOR: UCAN FOR: SAN DIEGO GAS & ELECTRIC COMPANY
MONA TIERNEY-LLOYD ROSANNE O'HARA SR. DIR., WESTERN REGULATORY AFFAIRS CALIF PUBLIC UTILITIES COMMISSION ENERNOC, INC. LEGAL DIVISION PO BOX 378 ROOM 5039 CAYUCOS, CA 93430 505 VAN NESS AVENUE
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FOR: ENERNOC, INC. SAN FRANCISCO, CA 94102-3214 FOR: ORA
MARCEL HAWIGER NORA SHERIFF STAFF ATTORNEY COUNSEL THE UTILITY REFORM NETWORK ALCANTAR & KAHL LLP 785 MARKET ST., STE. 1400 345 CALIFORNIA ST., STE. 2450 SAN FRANCISCO, CA 94103 SAN FRANCISCO, CA 94104 FOR: TURN FOR: CALIFORNIA LARGE ENERGY CONSUMERS ASSOCIATION
BRIAN CRAGG DARREN P. ROACH ATTORNEY PACIFIC GAS AND ELECTRIC COMPANY GOODIN, MACBRIDE, SQUERI & DAY, LLP LAW DEPT. 505 SANSOME ST., STE. 900 PO BOX 7442, MC B30A SAN FRANCISCO, CA 94111 SAN FRANCISCO, CA 94120 FOR: OHMCONNECT, INC. FOR: PACIFIC GAS AND ELECTRIC COMPANY
SARA STECK MYERS JENNIFER A. CHAMBERLIN ATTORNEY AT LAW EXE DIR - MRKT DEVELOPMENT / CAISO 122 - 28TH AVENUE CPOWER SAN FRANCISCO, CA 94121 2633 WELLINGTON COURT FOR: ON BEHALF OF JOINT DR PARTIES CLYDE, CA 94520 (COMVERGE, INC., CPOWER, ENERNOC, INC., FOR: CPOWER, INC. ENERGYHUB)
JASON B. KEYES ELIZABETH REID PARTNER CEO KEYES & FOX LLP OLIVINE, INC. 436 14TH ST., STE.1305 2120 UNIVERSITY AVENUE OAKLAND, CA 94612 BERKELEY, CA 94704 FOR: SOLARCITY CORPORATION FOR: OLIVINE
JOHN NIMMONS, ESQ. MELANIE GILLETTE ATTORNEY AT LAW SR. POLICY DIRECTOR JOHN NIMMONS & ASSOCIATES, INC. CA EFFICIENCY+DEMAND MANAGEMENT COUNCIL 175 ELINOR AVE., SUITE G 1535 FARMERS LANE, SUITE 312 MILL VALLEY, CA 94941-0000 SANTA ROSA, CA 95405 FOR: ELECTRIC MOTORWERKS, INC. FOR: CALIFORNIA EFFICIENCY + DEMAND MANAGEMENT COUNCIL (CEDMC) (FORMERLY: CALIFORNIA ENERGY EFFICIENCY INDUSTRY COUNCIL)
JORDAN PINJUV COUNSEL CALIFORNIA INDEPENDENT SYSTEM OPERATOR 250 OUTCROPPING WAY FOLSOM, CA 95630 FOR: CAISO
ALISSA BURGER CASE COORDINATION
Information Only
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CENTER FOR SUSTAINABLE ENERGY PACIFIC GAS AND ELECTRIC COMPANY EMAIL ONLY EMAIL ONLY EMAIL ONLY, CA 00000 EMAIL ONLY, CA 00000
MRW & ASSOCIATES, LLC BLAKE ELDER EMAIL ONLY CLEAN ENERGY SPECIALIST EMAIL ONLY, CA 00000 EQ RESEARCH 401 HARRISON OAKS BLVD., STE. 100 CARY, NC 27513
NATHANAEL A. GONZALEZ CASE ADMINISTRATION MGR - PROJECT / PRODUCT SOUTHERN CALIFORNIA EDISON COMPANY SOUTHERN CALIFORNIA EDISON COMPANY 8631 RUSH STREET 8631 RUSH STREET ROSEMEAD, CA 91789 ROSEMEAD, CA 91770
ANNLYN FAUSTINO JOHN W. LESLIE, ESQ REGULATORY & COMPLIANCE ATTORNEY SAN DIEGO GAS & ELECTRIC COMPANY DENTONS US LLP 8330 CENTURY PARK COURT, CP32F 4655 EXECUTIVE DRIVE, SUITE 700 SAN DIEGO, CA 92118 SAN DIEGO, CA 92121
GREGORY ANDERSON SUE MARA CALIFORNIA REGULAROTY AFFAIRS CONSULTANT SAN DIEGO GAS & ELECTRIC COMPANY RTO ADVISORS, LLC 8330 CENTURY PARK COURT 164 SPRINGDALE WAY SAN DIEGO, CA 92123 REDWOOD CITY, CA 94062
DAVID SCHLOSBERG JOANIE YUEN DIR - ENERGY MARKET OPER CASE MGR EMOTORWERKS PACIFIC GAS & ELECTRIC COMPANY 846 BRANSTEN ROAD 77 BEALE ST., MC B9A SAN CARLOS, CA 94070 SAN FRANCISCO, CA 94105 FOR: ELECTRIC MOTOR WERKS, INC. (EMOTORWERKS)
JOHANNA FORS SEBASTIEN S. CSAPO REGULATORY AFFAIRS PACIFIC GAS AND ELECTRIC COMPANY PACIFIC GAS AND ELECTRIC COMPANY 245 MARKET STREET, MAIL CODE N3F 77 BEALE STREET, B10A SAN FRANCISCO, CA 94105 SAN FRANCISCO, CA 94105
BRIAN KOOIMAN FRANCESCA WAHL OHMCONNECT, INC. DEPUTY DIR - POLICY & ELECTRICITY MKTS 350 TOWNSEND ST., STE. 210 TESLA, INC. SAN FRANCISCO, CA 94107 444 DE HARO ST., STE. 101 SAN FRANCISCO, CA 94107
JOHN W. ANDERSON LUKE TOUGAS DIR - ENERGY MARKETS CLEAN ENERGY REGULATORY RESEARCH OHMCONNECT, INC. 175 BLUXOME STREET, @102 350 TOWNSEND S., SUITE 210 SAN FRANCISCO, CA 94107 SAN FRANCISCO, CA 94107 FOR: OHMCONNECT, INC.
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SHIRLEY A. WOO MEGAN M. MYERS ATTORNEY AT LAW ATTORNEY PACIFIC GAS AND ELECTRIC COMPANY LAW OFFICES OF SARA STECK MYERS PO BOX 7442, MC B30A 122 - 28TH AVENUE SAN FRANCISCO, CA 94120-7442 SAN FRANCISCO, CA 94121
BARBARA R. BARKOVICH ERIC KIM CONSULTANT MARKET / INFRASTRUCTURE POLICY BARKOVICH & YAP, INC. CALIFORNIA ISO PO BOX 11031 250 OUTCROPPING WAY OAKLAND, CA 94611 FOLSOM, CA 95630 FOR: CALIFORNIA LARGE ENERGY CONSUMERS ASSOCIATION
JOHN GOODIN ANDREW B. BROWN CALIFORNIA INDEPENDENT SYSTEM OPERATOR ATTORNEY 250 OUTCROPPING WAY ELLISON SCHNEIDER HARRIS & DONLAN LLP FOLSOM, CA 95630 2600 CAPITOL AVE., STE. 400 FOR: CALIFORNIA ISO SACRAMENTO, CA 95816
MIKE CADE NKECHI OGBUE INDUSTRY SPECIALIST MGR - REGULATORY AFFAIRS ALCANTAR & KAHL ECOBEE, INC. 121 SW SALMON STREET, SUITE 1100 250 UNIVERSITY AVE. SUITE 400 PORTLAND, OR 97204 TORONTO, ON M5H 3E5 CANADA
MARTHA GUZMAN ACEVES BRUCE KANESHIRO OFFICE OF COMMISSIONER GUZMAN ACEVES CALIF PUBLIC UTILITIES COMMISSION CPUC - EXEC. DIV. DEMAND RESPONSE, CUSTOMER GENERATION, ANEMAIL ONLY AREA 4-A EMAIL ONLY, CA 00000 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214
CATHLEEN A. FOGEL DANIEL BUCH CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION DEMAND RESPONSE, CUSTOMER GENERATION, AN ELECTRICITY PRICING AND CUSTOMER PROGRAMAREA 4-A AREA 4-A 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214
HELENA OH JEAN A. LAMMING CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION ELECTRICITY PRICING AND CUSTOMER PROGRAM DEMAND RESPONSE, CUSTOMER GENERATION, ANAREA AREA 4-A 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214
KATHERINE J. STOCKTON KELLY A. HYMES
State Service
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CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION DEMAND RESPONSE, CUSTOMER GENERATION, AN DIVISION OF ADMINISTRATIVE LAW JUDGES AREA ROOM 5111 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214
NATALIE GUISHAR NILGUN ATAMTURK CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION DEMAND RESPONSE, CUSTOMER GENERATION, AN DIVISION OF ADMINISTRATIVE LAW JUDGES AREA 4-A ROOM 5119 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214
PIERRE BULL SHELLY LYSER CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION DEMAND RESPONSE, CUSTOMER GENERATION, AN ELECTRICITY PRICING AND CUSTOMER PROGRAMROOM 4-A AREA 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214 FOR: ORA
SUDHEER GOKHALE WERNER M. BLUMER CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION ELECTRICITY PRICING AND CUSTOMER PROGRAM DEMAND RESPONSE, CUSTOMER GENERATION, ANROOM 4102 AREA 4-A 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214
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