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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

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Page 1: BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF ... · record demonstrates that SCE’s proposed program designs and funding levels (as modified in this brief) are reasonable

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

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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

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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

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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

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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

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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).

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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.”)

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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.

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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.

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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.

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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.”

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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.

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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.

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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

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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.

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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.

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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.

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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

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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.

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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.

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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

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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.

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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.

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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.

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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

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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

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PROCEEDING: A1701012 - PG&E - FOR APPOVAL O FILER: PACIFIC GAS AND ELECTRIC COMPANY LIST NAME: LIST LAST CHANGED: JULY 24, 2017

DOWNLOAD THE COMMA-DELIMITED FILE ABOUT COMMA-DELIMITED FILES

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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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