BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF … · 2016-02-02 · LIMS 314-9080 BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA Order Instituting Rulemaking

LIMS 314-9080

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE

STATE OF CALIFORNIA

Order Instituting Rulemaking to Enhance the Role of Demand Response in Meeting the State’s Resource Planning Needs and Operational Requirements.

R.13-09-011

(Filed September 19, 2013)

SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E) PROPOSAL FOR

APPROVAL OF ITS 2017 DEMAND RESPONSE PROGRAM

AND BRIDGE FUNDING AUTHORIZATION

JANET S. COMBS ANGELICA M. MORALES

Attorneys for SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-4435 Facsimile: (626) 302-6962 E-mail: [email protected]

Dated: February 1, 2016

SOUTHERN CALIFORNIA EDISON COMPANY'S PROPOSAL FOR APPROVAL OF ITS 2017 DEMAND RESPONSE PROGRAM AND BRIDGE FUNDING AUTHORIZATION

TABLE OF CONTENTS

Section Title Page

-i-

I. INTRODUCTION ...........................................................................................................................1

II. SUMMARY OF PROPOSAL .........................................................................................................3

III. SCE’S CAISO INTEGRATION EXPERIENCE ............................................................................5

A. Status of Market Integration of SCE’s DR Programs ..........................................................5

B. SCE Does Not Plan To Integrate Demand Bidding Program (DBP) ...................................7

IV. SCE’S PROPOSALS FOR 2017 DR PROGRAMS ......................................................................10

A. Program Changes to Advance DR Integration with the CAISO Markets .........................10

1. Aggregator Managed Portfolio (AMP) Contracts ..................................................10

2. Capacity Bidding Program (CBP) .........................................................................12

a) CBP Product Offering Streamlining ..........................................................12

b) Improve Event Notifications to Align with Market Operations ..................................................................................................13

c) Enhance Nomination Process for Market Participation .............................14

d) Modified Dispatch Parameters ...................................................................14

3. Peak Time Rebate (PTR) .......................................................................................15

4. Over-Generation Pilots ..........................................................................................16

B. General Program Improvements ........................................................................................18

1. AutoDR ..................................................................................................................19

2. Capacity Bidding Program (CBP) .........................................................................20

3. Aggregator Managed Portfolio (AMP) Contracts ..................................................21

4. Base Interruptible Program (BIP) ..........................................................................22

a) Remove Customers for Non-Performance .................................................22

b) Remove the Option for BIP Aggregation ..................................................22


TABLE OF CONTENTS (CONTINUED)

Section Page

-ii-

5. Summer Discount Plan (SDP) ...............................................................................23

6. Circuit Savers .........................................................................................................25

V. CONTENTS OF SCE’S PROPOSED 2017 DEMAND RESPONSE PORTFOLIO ....................25

A. Cost-Effectiveness Protocols .............................................................................................26

B. Proposed 2017 DR Portfolio Budget .................................................................................27

1. Category 1: Reliability Programs...........................................................................28

2. Category 2: Price-Responsive Programs ...............................................................29

3. Category 3: DR Provider / Aggregator Managed Programs ..................................30

4. Category 4: Emerging & Enabling Technology ....................................................32

5. Category 5: Pilots ...................................................................................................32

6. Category 6: EM&V ................................................................................................32

7. Category 7: ME&O ................................................................................................32

8. Category 8: DR System Support Activities ...........................................................33

9. Category 9: Integrated Programs and Activities ....................................................34

10. Category 10: Special Projects ................................................................................34

11. Category 11: Dynamic Pricing ...............................................................................34

12. Rate Recovery Proposal .........................................................................................34

C. Anticipated 2017 MW........................................................................................................35

D. List of Programs External to 2012-2014 Application ........................................................37

1. Tariff program incentives ......................................................................................38

2. IDSM Programs .....................................................................................................38

3. AMP Contracts.......................................................................................................39

4. Proposed Schedule for Consolidating Programs....................................................39



Section Page

-iii-

E. Miscellaneous Issues ..........................................................................................................40

1. Customer Protection...............................................................................................40

2. DR Study Funding .................................................................................................42

3. AB 793 ...................................................................................................................43

VI. CONCLUSION ..............................................................................................................................44

APPENDIX A BARRIERS AND CHALLENGES SCE EXPERIENCED INTEGRATING DR INTO THE CAISO MARKETS .................................................................45

A. Issues and Barriers Related to Integration of DR into the CAISO Markets ................... A-1

1. CAISO Minimum Size Requirement .................................................................. A-1

2. Transition to new DR Registration System (DRRS) .......................................... A-1

3. Telemetry waiver for two PDR resources ........................................................... A-2

4. Use of 60-minute metering interval data for RDRR settlement ......................... A-3

5. CAISO Settlement Accuracy .............................................................................. A-4

6. Specifying Integrated DR Resource Capacity That Counts Towards Meeting Local Capacity Requirements ............................................................... A-4

7. Need for Custom Baseline Methodology for performance calculation for the residential programs .............................................................. A-5

8. RDRR and RTM Participation ............................................................................ A-5

9. Resource Adequacy (RA) Cap on Reliability DR .............................................. A-6

10. CAISO Deployment Schedules do not Incorporate Integration Testing with Market Participants ........................................................................ A-7

11. Update Frequency of Resource Registrations ..................................................... A-7

12. Discrete Dispatch and Granularity of Dispatch .................................................. A-9

13. Self-Dispatch of Day-of Resources Outside of RTM ......................................... A-9

B. Observations and Lessons Learned from DRAM Pilot ................................................ A-10



Section Page

-iv-

APPENDIX B STATUS OF CPP INTEGRATION ..................................................................................13

A. Timing Considerations .....................................................................................................B-1

B. Sub-LAP Dispatch ...........................................................................................................B-1

C. Telemetry .........................................................................................................................B-2

D. Event Notification ............................................................................................................B-2

E. Dual Enrollment ...............................................................................................................B-3

APPENDIX C COMPLETE 2017 DR PORTFOLIO BUDGET ............................................................C-1


TABLE OF AUTHORITIES

AUTHORITY PAGE

- v -

Statutes

Cal. Pub. Util. Code § 2790 ...................................................................................................................... 43 Cal. Pub. Util. Code § 380.5 ............................................................................................................... 39, 40 Cal. Pub. Util. Code § 717 ........................................................................................................................ 43

Legislation

2014 Cal. Senate Bill 1414 (Stats 2014 ch 627 § 3) ........................................................................... 39, 41 2015 Cal. Assembly Bill 793 (Stats 2015 ch 589 § 1) .............................................................................. 43

CPUC Decisions

D.06-11-049 .............................................................................................................................................. 22 D.08-04-050 .............................................................................................................................................. 35 D.10-04-006 .............................................................................................................................................. 35 D.10-06-034 ............................................................................................................................................ A-6 D.12-04-015 .............................................................................................................................................. 38 D.12-04-045 ...................................................................................................... 4, 28, 30, 33, 37, 38, 41, 42 D.13-01-024 ........................................................................................................................................ 30, 38 D.13-03-031 .............................................................................................................................................. 37 D.14-05-025 ............................................................................................................ 4, 27, 30, 31, 33, 37, 38 D.14-10-046 .............................................................................................................................................. 38 D.14-12-024 .......................................................................................................................... 3, 31, 42, A-10 D.15-02-007 .............................................................................................................................................. 42 D.15-11-042 ................................................................................................................................................ 3

CPUC Resolutions

Resolution E-4695 ........................................................................................................................ 10, 31, 38 Resolution E-4728 ...................................................................................................................... A-10, A-11 Resolution E-4737 ................................................................................................................................ A-10 Resolution E-4754 .................................................................................................................... 21, 31, A-11

Other Authorities

2013 Legis. Bill Hist., CA SB 1414, Bill Text as Amended, August 20, 2014 ........................................ 40 2013 Legis. Bill Hist., CA SB 1414, Bill Text as Amended, August 6, 2014 .......................................... 40 2013 Legis. Bill. Hist., CA SB 1414, Bill Text as Introduced, February 21, 2014 .................................. 40

1


STATE OF CALIFORNIA


R.13-09-011


SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E) PROPOSAL FOR

APPROVAL OF ITS 2017 DEMAND RESPONSE PROGRAM

AND BRIDGE FUNDING AUTHORIZATION

I.

INTRODUCTION

Pursuant to the Joint Assigned Commissioner and Administrative Law Judge’s Ruling

Providing Guidance for 2017 Demand Response (DR) Programs and Activities Proposal Filings

(Ruling), Southern California Edison Company (SCE) respectfully submits its 2017 DR program

proposals and request for bridge funding authorization. As directed in the Ruling,1 SCE’s

proposal includes the following categories of information:

(1) Program changes to enable California Independent System Operator (CAISO) market

integration;

(2) Program changes for overall program improvement;

(3) Clarification of DR portfolio contents; and,

(4) Miscellaneous items.

1 See Ruling, dated September 15, 2015, p. 5.

2

Table 1 identifies the section and page number(s) in SCE’s proposal where each of the

requirements from the guidance have been addressed.

Table I-1 Cross-Reference between Ruling and SCE's Proposal2

Ruling Requirement Page in Ruling

Section in Proposal

Page in Proposal

3a. Enabling Market Integration 1. Feasibility of CAISO market integration

for each individual DR program 5 III-IV.A.3 5-17 2. Integration of reliability programs 6 Not required for SCE 3. Recommendation for Pilots to address

over-generation from renewables 7 IV.A.4 17-18 3b. Overall Program Improvements

1. Cost-effectiveness (CE) protocols 9 V.A 26-27 2. Automated Demand Response

(AutoDR) / Technology Incentives / Technical Assistance Programs 10 IV.B.1 19-20

3. Overall budget 10 V.B 27-34 3c. Contents of the Demand Response Portfolio

1. Complete budgets for 2017 proposed DR portfolio 13 Appendix C C-1-C-2

2. Anticipated 2017 MW for each DR program 13 V.C 35-37

3. List of DR programs and incentives established outside of the 2012-2014 DR application proceeding 13 V.D.1 37-39

4. Proposed schedule to consolidate all DR programs and incentives into one DR portfolio 13 V.D.2 39-40

3d. Miscellaneous Requirements 1. Customer protection 14 V.E.1 40-42 2. DR study funding 14 V.E.2 42-43

2 SCE also addresses the following items based on verbal instructions at the January 12, 2016 workshop: (1) Lessons learned from the Demand Response Auction Mechanism (DRAM) (requested by ALJ Hymes; see Appendix A); (2) Waivers for CAISO requirements granted to SCE (requested by Commissioner Advisor Tisdale; see Appendix A); (3) Assembly Bill (AB) 793 (requested by ALJ Hymes; see Section V.E.3); (4) Extension of DRAM (requested by ALJ Hymes; see Appendix A); and (5) Dispatch trigger (Requested by Commissioner Advisor Tisdale; see Section IV.A.2).

3

II.

SUMMARY OF PROPOSAL

SCE’s proposal demonstrates its increased effort towards resource bifurcation and greater

DR integration into the CAISO wholesale energy market, which the Commission has been

considering since at least 2008, when it instructed California’s investor-owned utilities (IOUs)3

to file applications presenting plans for integrating DR programs into the CAISO market.4 In

2013, the Commission initiated Rulemaking (R.)13-09-011 to enhance the role of DR in meeting

the state’s resource planning needs and operational requirements, and also confirmed its intent to

prioritize the competitive bidding of DR into the CAISO wholesale electricity market.

Commission Decision (D.)14-12-024 further advanced the process of integrating DR resources.

Most recently, D.15-11-042 ordered, among other things, that event-based DR resources not

integrated into the CAISO market by January 1, 2018 would cease to have capacity value, thus

providing an incentive for these resources to integrate more quickly.5

On September 15, 2015, Commissioner Florio and ALJ Hymes issued the Ruling

outlining expectations for this filing. SCE agrees that the 2017 DR program year is an opportune

time to review the “lessons learned” from SCE’s integration efforts of bidding price-responsive

and reliability programs into the CAISO market, with the goal of taking bigger steps toward

integration in 2017. While additional program improvements can be made in 2017, SCE has

already made significant strides that resulted in the integration of over 1,100 megawatts (MW) of

DR into the CAISO market in 2015. SCE also implemented program changes to improve DR

program reliability and effectiveness, with the goal of developing more robust resources for the

CAISO energy market and for future resource planning needs.

3 The IOUs are SCE, Pacific Gas and Electric Company (PG&E), and San Diego Gas & Electric Company (SDG&E).

4 See Administrative Law Judge’s Ruling Providing Guidance on Content and Format of 2009-2011 Demand Response Activity Applications, issued February 27, 2008.

5 In lieu of being integrated into the CAISO market, a DR resource can also receive capacity value by being embedded in the CEC’s unmanaged/base case load forecasts.

4

In accordance with the Ruling and SCE’s strategy for its demand-side management

(DSM) programs, the following principles guided SCE in the development of the DR program

changes proposed in this filing.

Increase the amount of DR integrated into the CAISO markets: Consistent with

Commission policy, SCE focused on transitioning as much of its DR as possible

into resources competitively bid into the CAISO wholesale market.

Moderate Modifications: SCE did not propose any significant program changes

that would necessitate evidentiary hearings or impede the Commission’s ability to

approve the bridge proposals in a timely manner.

Efficient use of program funds: Many of SCE’s proposed changes are intended to

improve the cost-effectiveness of DR programs to maximize ratepayer value.

Positive customer experience: SCE’s proposed changes aim to enhance customer

experience of DR programs. Though budgets, cost-effectiveness, and market

integration are key factors in the design of DR programs, negative or declining

customer satisfaction can harm DR enrollment and participation, whereas a

positive experience can contribute to higher DR participation.

Thus, SCE’s proposals will advance the integration of its DR programs into the CAISO

wholesale markets, improve customer experience, and optimize use of ratepayer funds.

In SCE’s last DR funding application, Application (A.)11-03-001, et. al., the

Commission authorized a three-year (2012-2014) DR budget of $196,338,052 for SCE.6 In

D.14-05-025, the Commission authorized two-year bridge funding for DR programs with a

budget of $172,307,062 for 2015 and 2016, or an average of $86,153,530 per year. For the 2017

bridge period, SCE requests $44,283,294 for its DR programs, a reduction of $41,870,000, or 49

percent, from the average annual authorized amount for the 2015-2016 bridge period.

6 See D.12-04-045, p. 198 & Ordering Paragraph (OP) 18 at p. 218.

5

III.

SCE’S CAISO INTEGRATION EXPERIENCE

In this section, SCE discusses the status of integrating its DR programs into the CAISO

wholesale markets.7 This section also identifies the DR programs SCE does not currently plan to

integrate into the market and the rationale for that decision.

A. Status of Market Integration of SCE’s DR Programs

SCE began bidding its DR programs into the CAISO market in June 2015 with the

integration of the following five DR programs: (1) Capacity Bidding Program (CBP), (2)

Aggregator Managed Portfolio (AMP), (3) Base Interruptible Program (BIP), (4) Agricultural &

Pumping Interruptible (AP‐I), and (5) Summer Discount Plan (SDP). The integration of these

programs resulted in a total of 70 Proxy Demand Resources (PDRs)8 and Reliability Demand

Response Resources (RDRRs).9 These five programs represent approximately 1,314 MW, or 90

percent, of SCE’s DR portfolio total of 1,457 MW.10 Of the 1,314 MW, approximately 1,164

MW was registered and bid with the CAISO; the remaining 150 MW could not be registered for

various reasons described below. SCE considers these programs fully integrated into the CAISO

market for the purposes of DR program dispatch because when the CAISO selects an SCE bid,

the entire program is dispatched, not just the integrated portion.

As part of its integration efforts, SCE registered at least one resource from each Load

Control Group (LCG)11 in all five programs. Thus, a CAISO award of any integrated resource

7 In Appendix A, SCE also identifies the challenges it faced when integrating DR programs, along with barriers to achieving further integration. In addition, lessons learned during implementation of the Demand Response Auction Mechanism (DRAM) pilot programs are discussed in Appendix A.

8 PDR is a CAISO product for economic DR that can be either Day-Ahead (DA) or Day-Of (DO). 9 RDRR is a CAISO product for reliability DR. RDRR must always have a DO component that is

dispatched in the real-time market in response to reliability conditions. RDRR can also have a DA component that is dispatched on an economic basis.

10 See SCE’s August 2015 DRP and ILP Report. 11 LCG is the lowest level of dispatch granularity for SCE DR programs and it typically consists of

more than one DR resource (whether registered in the CAISO market or not) because there is no Continued on the next page

6

always resulted in SCE’s dispatch of all customers in the corresponding LCG. The only

exception is the CBP DA 2‐6 program, which did not meet the CAISO’s 100 kW minimum

bidding requirement for registration in the CAISO market. Because CBP DA 2-6 did not have a

registered LCG in the CAISO wholesale market, the resource was dispatched in conjunction with

the corresponding CBP DA 1‐4 LCGs based on the CAISO awards for the integrated CBP DA 1‐

4 PDRs. For instance, if a CBP DA 1-4 PDR in SCE’s North Sub-Load Aggregation Point (Sub-

LAP) was awarded by the CAISO for 5pm-7pm, SCE also dispatched its CBP DA 2-6 in the

North Sub-LAP for the same hours.

SCE has not registered all of the capacity in four of the five integrated programs (CBP,

AMP, BIP, and SDP). 12 At this time, 85 resources representing 4 MW have not been registered

because they do not meet CAISO’s minimum PDR or RDRR size requirement. In addition, SCE

has not registered another 88 resources (representing 146 MW) that are large enough to be

integrated. SCE purposefully delayed integrating these resources pending more experience

managing the operational complexity of bidding DR resources into the CAISO market and

further testing of SCE’s internal operational processes and system limitations. After

participating in the CAISO market for several months, SCE identified and has begun

implementing improvements to its DR operations and systems. As operations stabilize and

become more efficient, and processes become more automated via improved systems, SCE plans

to register additional resources large enough to be integrated, especially those with large

capacities. SCE expects this work to be the main focus of its 2016 and 2017 integration efforts.

Table III-2 shows the breakdown of DR MW by those that are directly integrated (e.g.

registered LCGs) as PDRs and RDRRs and those that are indirectly integrated (e.g. non-

registered LCGs) but are dispatched alongside the directly integrated resources:

Continued from the previous page

segregation of customers by Load-Serving Entity (LSE) as is the requirement by CAISO for PDRs and RDRRs.

12 All AP-I MW have been integrated and registered with the CAISO.

7

Table III-2 Directly vs. Indirectly Integrated MW

(As of August 31, 2015)13

CBP 1-4 CBP 2-6 AMP BIP AP-I SDP Total

Directly Integrated MW

10 - 74 648 64 368 1,164

Indirectly Integrated MW

18 8 24 97 0 3 150

Total MW 28 8 98 745 64 371 1,314

The Ruling instructed SCE to “explain the mechanisms in place to ensure compliance

with dual participation rules”14 for partially integrated programs. SCE maintains a public

document on its website that communicates allowable dual participation options to customers

and third-party aggregators.15 SCE also monitors and enforces dual participation rules at the

enrollment stage. Prior to enrolling a Service Account (SA) in a DR program, SCE checks to

ensure that enrollment in the requested program would not violate dual participation rules.

B. SCE Does Not Plan To Integrate Demand Bidding Program (DBP)

The Ruling states: “For programs deemed not feasible to be integrated, the Utilities shall

provide an explanation of the barriers and include any potential barrier mitigation actions.”16

SCE’s DBP is the only non-dynamic pricing, dispatchable DR program that meets this criteria.

DBP is a penalty-free program that provides participating customers with an energy

incentive for load reductions on a day-ahead basis. SCE notifies enrolled customers of an event

at 12:00 p.m. the day before the event. At that time, customers must decide whether they wish to

13 MW based on the contract nominations and expected resource performance as of August 31, 2015. 14 Ruling, p. 6. 15 See Demand Response Programs Dual Enrollment Options for Business Customers, available at

https://www.sce.com/wps/wcm/connect/6bcb2795-711d-4613-b794-11a64fedae57/DR+Dual+Enrollment+FS+r2_WCAG_K.pdf?MOD=AJPERES [as of February 1, 2016].

16 Ruling, p. 6.

8

participate in the event. They do not face penalties or charges for opting out of the event. If a

customer wishes to participate, they nominate a specific amount of load reduction per hour. SCE

pays for customer load reduction at the rate of $0.50/kWh for reductions within 50 percent to

200 percent of their nomination. For example, a customer with a nominated reduction of 100

kWh would be paid for reductions in the range of 50 kWh to 200 kWh. Customers are not

penalized or charged for reductions outside the 50 percent-200 percent payment band.

In 2015, the average DBP event provided a load impact of 86 MW. Consistent with prior

years, a substantial majority of this load reduction was delivered by customers who dual-

participate in DBP and BIP. In 2016, DBP provided only 4.6 MW of Resource Adequacy (RA)

value in August due to nearly all of its MW capacity being counted under BIP.

Market integration of DBP will not provide value to ratepayers for three reasons: high

integration costs, difficulty to translate DBP’s program design into a CAISO-compatible market

product, and differences between CAISO market prices and customer incentives.

DBP would be costly to integrate due to the large scope of changes necessary to do so.

The majority of DBP’s load comes from customers participating in both DBP and BIP. Because

a customer cannot dual-participate in more than one CAISO resource registration, SCE

determined that integrating DBP as a standalone resource would provide, at best, a small number

of MW. If forced to choose, most customers would opt for the capacity incentive offered by

BIP. Thus, DBP market integration would require a modification of BIP that would allow day-

ahead economic participation in addition to BIP’s real-time market (RTM) participation as an

RDRR resource. SCE estimates approximately $640,000 as the cost for this change.17

In addition to cost, the primary design feature of DBP as customers know it today—the

ability for the customer to determine both participation and the load reduction amount the day

before the event—does not lend itself to CAISO integration. Customers have advised SCE that

17 This estimate includes $150K to retire the current form of DBP; $312K to $402K for systems modifications to create a DA economic nomination feature within BIP; and $88K for customer education and training.

9

DBP’s day-ahead and penalty-free nomination feature is a critical element of its program design.

For example, due to the variable nature of their business and “just in time” operational processes,

some customers do not have enough certainty to predict their DR capability more than a few

days in advance. On the other hand, SCE cannot create a resource registration and offer DR load

into the CAISO market without knowing how much load customers can provide. It is neither

feasible nor practical for SCE to create new resource registrations on a daily or weekly basis

after surveying customers to determine their available load.

The final obstacle for DBP integration is the large difference between the DBP energy

incentive of $0.50/kWh and the CAISO day-ahead market prices at which the resource would be

offered. As a matter of compliance with Federal Energy Regulatory Commission (FERC)

market regulations, SCE cannot offer a resource at a price lower than its cost. Therefore, DBP

would be integrated at an offer price of $500/MWh.18 However, since January 2010, the CAISO

day-ahead market has never cleared above $183/MWh within DBP’s available hours of 12pm to

8pm. In fact, since that time, day-ahead market prices have only exceeded $150/MWh in a total

of twelve hours during DBP’s event availability window. This means that if SCE was to

integrate DBP at its current price of $500/MWh, there is little reason to believe it would receive

a market award for dispatch. Because DBP is an energy-only program, customers cannot earn

incentives if the program is not dispatched. SCE also considered a scenario in which customers

could nominate both their day-ahead load quantity and load price. However, this would further

increase the cost to integrate DBP and the operational challenge of translating DBP’s day-ahead

nomination into a CAISO resource registration.

For the reasons discussed above, SCE has determined that the costs and operational

challenges of integrating DBP into the CAISO market outweigh the benefits. Furthermore, given

the program’s RA value of less than 5 MW and the substantial difference between its energy

18 $0.50 per kWh * 1,000 kW per MW = $500/MWh.

10

incentive and the wholesale cost of the energy it is intended to displace, SCE recommends that

the CPUC approve the retirement of SCE’s DBP effective for the 2017 program year.

SCE also has a dispatchable dynamic pricing program, Critical Peak Pricing (CPP),

which it does not plan to integrate into the CAISO market. The Ruling states, “dynamic pricing

programs, (e.g., Critical Peak Pricing, Real-Time Pricing, and Time-of-Use rates) should not be

included in the 2017 proposal.”19 Therefore, SCE does not discuss CPP in this section.

However, to the extent the Commission wants to understand why SCE is not planning to

integrate CPP into the CAISO markets, SCE has included its rationale in Appendix B.

IV.

SCE’S PROPOSALS FOR 2017 DR PROGRAMS

In this section, SCE discusses the DR program changes it proposes for 2017. Subsection

A describes program changes intended to increase integration of SCE’s DR programs into the

CAISO market. Subsection B describes general program modifications intended to improve the

DR portfolio. The 2017 budget proposal reflecting these proposed modifications is in Section V.

A. Program Changes to Advance DR Integration with the CAISO Markets

In this section, SCE proposes incremental program changes to enable SCE to integrate

additional MW of DR into the CAISO markets. Many of these proposals are based on

experience and lessons learned from programs that were integrated in 2015.

1. Aggregator Managed Portfolio (AMP) Contracts

In Resolution E-4695, the Commission approved two of the four re-negotiated AMP

contracts SCE submitted for approval for the 2015-2016 bridge period.20 With the current AMP

19 Ruling, p. 13. 20 SCE’s Advice Letter (AL) 3078-E was submitted on July 15, 2014. The four Aggregators SCE

negotiated and filed contracts with in AL 3078-E were Constellation Newenergy, Inc., Energy Connect, Inc., EnerNOC, Inc., and IP Keys (formerly known as North America Power Partners).

11

contracts expiring at the end of 2016, SCE requests Commission authorization to negotiate AMP

contracts for 2017, with the following modifications, and allow SCE to continue to integrate

these resources in the CAISO wholesale market. If the parties agree on cost-effective contracts

that include the proposed modifications, SCE will submit executed 2017 AMP contracts for

Commission approval in an advice filing, similar to the 2015-2016 AMP contracts. Any

contracts or contract amendments would be for 2017 only, in compliance with the Ruling.21

Proposed modifications to the AMP contracts will include terms and conditions to address

integration issues such as telemetry and PDR registration requirements. Other AMP

improvement modifications are discussed in the overall program improvement section below.

The telemetry issue described in Appendix A affected the market integration efforts of

SCE’s AMP contracts. As noted in that section, SCE had to redistribute two registered resources

that were each over 10 MW into six smaller resources with capacities under 10 MW. Because

the 2015-2016 AMP contracts were an extension of the 2013-2014 AMP contracts, funding and

contractual terms were not included in the 2015-2016 bridge AMP contracts to address this

integration issue. For the 2017 AMP agreements, SCE will include a telemetry provision that

would require the aggregator to provide telemetry if required (e.g., if the registered resource

exceeds 10 MW). This will allow SCE to integrate and dispatch each LCG as a single resource

rather than registering multiple resources.

In addition to telemetry requirements, the CAISO also has a minimum PDR bidding

requirement of 100 kW. To ensure SCE’s AMP contracts can continually be offered in the

wholesale market,22 2017 AMP contracts will also require aggregators to nominate at least 100

kW for each Sub-LAP. Requiring nominations that meet the CAISO minimum PDR bidding

requirement will reduce the non-registered kW in SCE’s integrated portfolio.

21 See Ruling, p. 12. 22 If the registered resource should fall below 100 kW, SCE would have to remove the resource from the

market and dispatch the resource alongside integrated resources.

12

Because some of the above changes to the AMP program may have material impacts to

aggregator costs, SCE will allow aggregators to make adjustments to capacity commitments and

prices, which will require new CE calculations. SCE will include applicable CE measurements

when filing any executed 2017 AMP contracts.

2. Capacity Bidding Program (CBP)

SCE proposes to make several incremental modifications to its CBP program that will

further advance the integration of DR into the CAISO markets (e.g. day-ahead market (DAM)

and real-time market (RTM)) and will significantly improve the efficiency of the CBP program

delivery as an integrated resource: (1) modifications that will streamline the current array of CBP

product offerings; (2) improvements to event notifications to adapt to current and future market

operating conditions; (3) modifications that will improve the nomination process; and (4)

revision of dispatch parameters to enable program operation in the DAM and RTM. These

proposed modifications are informed by SCE’s observations and lessons learned from integration

activity in 2015.

a) CBP Product Offering Streamlining

Currently SCE offers six different CBP products, covering different four- to eight-hour

time periods. SCE proposes to reduce the current number of CBP products from six (Day-Ahead

(DA) 1-4, DA 2-6, DA 4-8, Day-Of (DO) 1-4, DO 2-6, & DO 4-8) to two (DA 1-6 & DO 1-6).

By only offering a 1-6 hour product for CBP DA and DO, the current CBP event window and

monthly event maximum will need to be revised from the eight hour maximum window to a six

hour maximum window with a monthly event maximum of five events (e.g. 30 hour monthly

maximum divided by 6 hour daily maximum), respectively. SCE does not propose a 1-8 hour

product because based upon historical program participation, the 4-8 products were rarely used

(DA 4-8 & DO 4-8). The last time an aggregator participated in DA 4-8 was February 2014;

SCE has not had an aggregator participate in the DO 4-8 product since 2011. Further,

13

consolidating the existing 1-4 and 2-6 offerings into a 1-6 offering (for DA and DO) simplifies

program administration and enables the resource to meet the minimum 100 kW PDR bidding

requirement while still meeting RA requirements. Eliminating multiple products and adjusting

the availability window for the revised products will simplify SCE’s integration activities, enable

the full integration of the Capacity Bidding Program into the CAISO wholesale energy market,

and eliminate the need to dispatch other products concurrently with a similar integrated resource

(e.g. SCE will not need to dispatch CBP DA 2-6, based on the CAISO dispatch of CBP DA 1-4,

because the DA 2-6 was not integrated because it did not meet PDR bidding requirements).

b) Improve Event Notifications to Align with Market Operations

SCE also proposes to modify DA event notifications from 3:00 P.M. the weekday before,

to 5:00 P.M. the non-holiday weekday before. This modification will align SCE’s notification

process with CAISO’s processes and reduce dispatching the program unnecessarily because

market awards were not received to allow sufficient time to notify aggregators of events. On

several occasions in 2015, SCE had to dispatch CBP in advance of receiving CAISO’s day-ahead

market (DAM) awards due to program’s 3:00 P.M. notification cut-off time. By changing the

CBP tariff DA notification time requirement, program dispatches will be based on CAISO

market conditions.

SCE also proposes to modify DO event notifications to enable participation in the CAISO

RTM. In 2015 (the first year of integration), SCE primarily bid its CBP PDR resource in the

DAM. Since that time, SCE has gained significant experience with DR market integration and

seeks to expand its experience in the RTM. Although SCE is still fine-tuning the operational

processes that will enable CBP DO to participate in the RTM, a 20 minute notification

requirement for CBP DO should be sufficient to allow for the shorter lead times of the RTM

relative to the DAM.

To minimize the amount of time between the notice of awards and notifying DR

participant, SCE is working on system enhancements that will automate the translation and

14

processing of CAISO awards to SCE’s notification system. If the Commission approves SCE’s

proposed program modifications to enable RTM participation, SCE will immediately work on

system modification and enhancements to try to implement these changes by July 2017. If

system changes require additional time, SCE will complete system changes and enhancements

no later than December 31, 2017, thus RTM participation may be delayed to January 2018.

c) Enhance Nomination Process for Market Participation

Consolidating SCE’s current CBP products into one DA and one DO product should

resolve some of the issues associated with the CAISO minimum PDR bidding requirement. To

fully integrate the resource and meet the CAISO’s minimum PDR bidding requirement, SCE

proposes to add a requirement to its CBP tariff that would require aggregators to nominate at

least 100 kW per location or Sub-LAP. This modification will advance CAISO integration

because it will reduce the non-registered resources for CBP.

SCE also recommends requiring aggregators to provide the Load Drop Estimate (LDE)

for each service account as part of the nomination process. Requiring aggregators to provide the

LDE and nominate at least 100 kW for each Sub-LAP will ensure the DR resource is bid into the

wholesale market at the appropriate value and meets the market’s requirements. In 2015, SCE

bid the CBP PDR based upon the 2015 ex ante values from the 2014 CBP load impact study.

These values may not accurately represent the potential MW available since ex ante values are

based upon the average kW per service account. These two modifications to the CBP

nomination process will advance CAISO integration because they will result in bids that

accurately reflect the portfolio’s potential and will meet the CAISO’s minimum PDR bidding

requirements.

d) Modified Dispatch Parameters

SCE also proposes to modify dispatch parameters in conjunction with the proposed

modifications above. In 2015, SCE integrated its PDRs into the Day-Ahead Market (DAM) but

15

recognizes that DR products can add value in the RTM. Because there are significant price

differences between the DAM and the RTM, the CBP event trigger should be modified to ensure

the product is priced properly for the relevant market (i.e., CBP DA for DAM and CBP DO for

RTM). SCE recommends including a price component in conjunction with the 15,000 Btu/kWh

heat rate so that the program can be priced appropriately for the market in which it will be

integrated.

Elimination of the 4-8 products and changing the event window to 1:00 P.M. to 7:00

P.M. will affect the components used to calculate cost-effectiveness. Thus, SCE has included

updated cost-effectiveness analysis for CBP based upon the above changes in Section V.A. The

Total Resource Cost (TRC) results of the proposed modifications for the CBP DA and DO

programs is 1.46 and 1.52, respectively.

3. Peak Time Rebate (PTR)

SCE’s PTR program is an incentive program that offers participating residential

customers bill credits for lowering their energy usage during scheduled event periods called

throughout the year. Participants are awarded incentives based on the actual energy reduction

achieved during the event compared to their otherwise typical usage for the same comparative

time. PTR has three options:

PTR (no technology): SCE sends PTR event notifications to customers via email,

phone or text message. Participating residential customers can earn incentives of

$0.75/kWh reduced during PTR events;

PTR (Enabling Technology): SCE sends PTR event notifications to a customer-

owned device communicating with SCE's meter. Participating customers receive

credits of $1.25/kWh reduced during PTR events; and

PTR-ET-DLC (Direct Load Control): Enabling technology is used and controlled by

SCE or an SCE-approved third party. Participating customers receive credits of

$1.25/kWh reduced during PTR events.

16

In AL 3323-E,23 SCE requested decommissioning of the PTR and PTR-ET options

because they are not cost-effective. PTR-ET-DLC, however, continues to grow and has the

potential to drive greater per customer energy savings and dispatch flexibility. SCE proposes

changes to the PTR-ET-DLC program that will be implemented in 2017 to enable a portion of

the program to be integrated into the CAISO wholesale market in 2018. In order to enable PTR-

ET-DLC for market readiness, the following changes are required:

Modify dispatch window to one event per day, at any time of the day, for up to four

hours per day during any non-holiday weekday;

Modify incentive level from an energy payment of $1.25/kWh to an energy payment

of $0.25/kWh, along with a fixed annual payment of approximately $25/year/ SA;

Modify to dispatch from DA to DO notification;

Modify to dispatch at the Sub-Lap level;

Modify to allow use for either reliability or capital deferral needs;

Eliminate customers’ ability to dual-participate in PTR-ET-DLC and SDP; and

Make necessary IT system changes to update incentive levels and dispatch flexibility

by both hours and location.

4. Over-Generation Pilots

The Ruling encourages the IOUs to develop pilots that explore the solutions offered in an

IOU-funded study24 that investigated the relationship between renewables and over-generation.25

That study determined that the increase in renewable energy brings the potential for over-

23 SCE’s AL 3323-E was filed December 9, 2015. 24 “Investigating a Higher Renewables Portfolio Standard in California,” conducted by Energy and

Environmental Economics (E3), January 2014, Study Team: Energy and Environmental Economics, Inc. (E3), ECCO International, DNV KEMA; Study Sponsors: LADWP, PG&E, SDG&E, SCE, and SMUD.

25 Ruling, p. 7.

17

generation, and that DR has great potential for mitigating this risk. One of the key over-

generation solutions identified in the E3 Study is energy storage.

Based upon these findings, SCE recommends a pilot program that would study the

application of an energy storage technology, specifically, pumped water storage. The

recommended pumped storage pilot would involve working with four municipal and wholesale

water companies to modify their water pumping systems’ controls to provide the capability to

respond to over-generation events. The pilot would involve pumping water to the water

companies’ existing elevated tanks (on mountain sides, towers, etc.) in response to an over-

generation DR signal. The pilot would include the testing of various pumping scenarios and

measuring the absorption of energy (kWh), and power (kW), volume and flow rates of water,

responsiveness of pumps, and the ability of supervisory control and data acquisition (SCADA)26

systems to respond to DR signals. Based upon discussions with various water companies, it is

anticipated that the largest hardware and software costs will include energy management control

systems and submeters. Alternately, other energy storage systems that may be considered for the

over-generation pilot include, batteries, capacitors, compressed air, and other storage methods.

The pilot may consider initial cost, operating cost, round-trip efficiencies, performance

characteristics, longevity, and operating cycles. SCE may also leverage and expand existing DR

projects that include energy storage technologies and other storage methods that may not

specifically be designed to address over-generation. SCE also recommends that its pilot include

research on how to modify and apply pilot results to future distribution business grid models.

SCE’s recommended research questions include, but are not limited to:

What is the energy storage system performance in the lab and in the field of the

various technologies?

26 SCADA systems are a type of industrial control system often used in industrial and infrastructure processes, such as water treatment and distribution.

18

What are the most beneficial and cost-effective use cases for absorbing excess energy

during an over-generation event?

What customer behaviors and drivers, by segment, are needed for participation in

over-generation programs, including but not limited to, market interest, incentive

structure, technology to communicate and automate events, and reduction of

economic and market barriers for customer participation?

Are there viable multi-use energy storage systems that would add value (and increase

cost-effectiveness) such as municipal or regional water agencies that can use

automation and communication for over-generation, traditional demand response, and

other uses?

Are there ancillary services to test response to communication signals and validate

how over generation programs can cost-effectively integrate into the market?

How can the determination be made of the temporal and locational value of load

shifting?

Given that the intent of the pilots is to prepare for 2018, SCE recommends that the pilot

begin as early as possible, preferably in the second quarter of 2016. The over-generation pilot’s

proposed budget of $1,000,000 is based upon an estimate of working with four municipal and

wholesale water companies to respond appropriately to over-generation events, including the

acquisition and installation of any required additional equipment.

B. General Program Improvements

In this section, SCE includes proposals intended to “improve the programs in general,”

including a proposal to further improve SCE’s AutoDR program.27 SCE included its revised CE

analysis in Section V.A below because it reflects both general program improvements and

improvements intended to increase integration of DR in the CAISO market. The Ruling also

27 Ruling, pp. 9-10.

19

directed the IOUs to consider making budget reductions,28 which was a driver for some of SCE’s

proposed program improvements. SCE’s overall budget is discussed in Section V.B below.

1. AutoDR

AutoDR is a program that provides incentives to qualified business customers to offset

the purchase and installation costs of technology and equipment that enables automated response

to DR events. As noted in the Ruling, the AutoDR program is a key factor in advancing DR.29

Although not required to propose new improvements to AutoDR as it has already done so in

2014,30 SCE has evaluated the current AutoDR incentive structure and proposes program

changes that will improve cost-effectiveness and align with reduced market pricing.

SCE proposes to make moderate modifications to the AutoDR Express program

incentives to increase cost effectiveness. The AutoDR Express program provides incentives to

customers with peak electricity demand of 50-499 kW for predetermined (deemed) savings on

standard lighting and HVAC technologies. The current program incentive structure provides

$300/kW of tested load reduction for enabling technologies. SCE proposes to revise the

incentive to $200/kW and will continue to pay customers up to 100 percent of project cost.

SCE proposes to make more significant modifications to the structure of the AutoDR

Customized incentive program. The AutoDR Customized program currently consists of a 60/40

payout structure, with DR program participation required for one year. 31 Customers are eligible

to receive a maximum of $300 per kW for verified load reduction based on the results of a two-

hour onsite test. 60 percent of project cost is paid out after AutoDR equipment is installed and

potential load reduction has been measured during the test event. The other 40 percent is

disbursed based on average load reduction for all events during the one-year required

28 Ruling, p. 10. 29 Ruling, p. 10. 30 Ruling, p. 10. 31 While the 40 percent “participation bonus” is based on one year of participation in DR program

events, the customer is required to be enrolled in a qualified DR program for three consecutive years.

20

participation in an eligible AutoDR program. The total incentive is capped at 100 percent of

actual project cost. The project terms/guidelines provide for single accounts with allocated

incentives at or greater than $200,000 to sign a Letter of Agreement and projects with accounts

at this level require a three-year participation in a DR program.

During the 2012-2015 DR funding cycle, the average incentive cost per kW for AutoDR

has been $244/kW out of the $300/kW maximum. SCE proposes to eliminate the 60/40

incentive structure, as it incents performance only through the first year. A reduced incentive of

$150/kW with a cap of 50 percent of total project costs and no additional incentive will continue

to retain interest in AutoDR technology and better reflect market pricing conditions. This

reduced incentive structure will better incent DR program performance throughout the three-year

program enrollment obligation, as customers will have to perform to recoup their investment.

2. Capacity Bidding Program (CBP)

In addition to the CBP modifications proposed in Section IV.A.2 to improve integration

in the CAISO market, SCE proposes two additional changes aimed at overall program

improvements and enhancement of the customer market integration experience. SCE proposes

to update the CBP Capacity Payment Bands to align with other third-party programs, such as

AMP and LCR. Currently the CBP capacity payment band does not align with the payment

bands in the AMP and LCR agreements. This modification will make the program competitive

and consistent with other third-party DR programs. Table IV-3 shows SCE’s proposed Capacity

Payment Bands for CBP.

21

Table IV-3 Proposed CBP Capacity Payment Bands

Delivered Capacity Capacity Payment Calculation

105% or more of Nominated Capacity

1.05 * Capacity Nomination * Capacity Credit Rate

Greater than or equal to 75% of Nominated Capacity but less than 105% of Nominated Capacity

Delivered Capacity * Capacity Credit Rate

Greater than or equal to 60% of Nominated Capacity but less than 75% of Nominated Capacity

Delivered Capacity * 50% * Capacity Credit Rate

Less than 60% of Nominated Capacity

[Delivered Capacity – (60% * Capacity Nomination)] * Capacity Credit Rate

SCE also proposes to clarify the payment terms to allow for other SCE-approved forms

of electronic payment. Currently, CBP payments are issued by check and sent via U.S. mail.

This reduces risk of lost payments and reduces time between settlements and payment, resulting

in greater efficiency to DR participants.

3. Aggregator Managed Portfolio (AMP) Contracts

In compliance with Resolution E-4754, OP 7, SCE will maintain the annual adjustment

provision in the 2017 AMP contracts unless the Commission approves SCE’s 2017 AMP

contracts after October 1, 2016. The AMP contracts annual adjustment provision requires

Aggregators to elect this provision by the October 1 before the operating year. Therefore,

Aggregators would need to make their annual capacity adjustment by October 1, 2016 for the

2017 operating year. Also, because these would be one-year contracts, there is no need for the

annual capacity adjustment provision to be included in these AMP contracts as they may not

exist beyond 2017.

22

4. Base Interruptible Program (BIP)

BIP provides bill credits to customers in exchange for the customer’s agreement to

reduce demand to a Firm Service Level (FSL) upon notice from SCE. Customers have the

option to enroll in either a 15-minute or 30-minute response time. SCE applies excess energy

charges for customer usage above their FSL during periods of interruption.

SCE proposes two changes to BIP for 2017: (1) remove customers for repeated non-

performance; and (2) remove the option for aggregation of accounts on BIP.

a) Remove Customers for Non-Performance

The BIP tariff currently applies excess energy charges of approximately $13/kWh to

customers with usage above their FSL. This motivates customer performance, but the tariff does

not provide SCE with a means to address customers with non-performance in multiple,

consecutive BIP events despite the application of excess energy charges. SCE proposes to

update the BIP tariff to allow SCE to either remove customers from the program or require a

revised FSL if the customer fails to reduce demand to their FSL during multiple, consecutive BIP

events. Any customer removals would be effective at the customer’s next billing cycle after

multiple, consecutive failures to reduce demand during BIP events.

It is important to note that BIP non-compliance is not a widespread problem, and that the

application of excess energy charges provides important ratepayer protection. SCE’s analysis

indicates that less than one percent of enrolled BIP customers exhibit repeated non-performance.

The vast majority of BIP customers meet their performance obligations and would not be

affected by this change. The proposed tariff change would provide SCE the authority to remove

chronic non-performers who provide minimal benefits to ratepayers.

b) Remove the Option for BIP Aggregation

Pursuant to D.06-11-049, SCE created an option for third parties to aggregate multiple

SCE customers onto a single BIP contract. SCE proposes to discontinue the option for BIP

23

aggregation due to the existence of other DR aggregation options as well as the lack of interest in

this option of the BIP tariff.

Third parties now have various options to aggregate SCE’s customers onto DR tariffs or

contracts. SCE has bilateral contracts via the AMP program and the Local Capacity

Requirements Request for Offers (LCR RFO). Both the 2016 and 2017 pilot years of the

DRAM, which offers additional opportunity for aggregation, are well underway. In addition,

SCE recently launched a solicitation for additional preferred resources contracts in the South

Orange County area (the Preferred Resources Pilot RFO #2). SCE has only had one customer

use SCE’s BIP aggregation option for a brief period in 2009. In addition, eligible customers can

receive the full BIP incentive by simply enrolling directly and bypassing an aggregator entirely.

Despite being used only once for a brief period in 2009, the existence of the BIP

aggregation option creates costs for ratepayers. For example, any administrative, tariff, or billing

changes related to BIP must be developed and implemented for both the traditional BIP program

as well as the aggregator option. Any SCE expenses and employee labor time spent to maintain

the BIP aggregation option are costs for which ratepayers are not receiving benefits.

Based on the other opportunities available to customers for aggregation, the lack of

participation in SCE’s aggregation option, and the fact that eligible customers can receive the

full BIP incentive by enrolling directly, SCE has determined that the value derived from keeping

the BIP aggregation option available is not worth the administrative effort required to do so.

5. Summer Discount Plan (SDP)

The SDP program provides incentive payments to customers in exchange for the

customers’ agreement to allow SCE to remotely control their air conditioning during demand

response events. Residential and commercial participants have the option to have their air

conditioner shut off completely or for only a portion of the event duration. SCE installs a radio

device on the customer’s air conditioning unit, enabling SCE to remotely turn off the A/C.

Residential customers can choose to also be provided an override feature that allows them to opt

24

out for up to five events per year. The program is currently integrated into the CAISO wholesale

market.

SCE proposes to more efficiently allocate program incentives by removing non-

performing participants who fail to meet a minimum usage requirement, indicating no air

conditioning load during SDP events. Recent data analyses have shown that not all SDP

participants contribute to DR load impacts, and approximately six percent of residential

customers and approximately four percent of commercial customers did not have their AC

systems operating during any DR events. In an effort to prevent incentive payments for lack of

performance, SCE is proposing to modify the eligibility requirements of the program to require

that participating customers have a minimum premise load for at least one SDP event day per

calendar year. This will ensure that the customer had load available to be reduced.

SCE proposes to establish the following criteria for program eligibility:

Residential customers must show a minimum 1.5kWh of usage during the hour prior to event start or the hour after event end in at least one event per calendar year.

Commercial customers must show 0.2kWh of usage per rated AC tonnage during the hour prior to event start or the hour after event end in at least one event per calendar year.

Customers who do not meet this eligibility requirement will be removed from the SDP

program and not allowed to re-enroll for at least 12 months after the date of the removal. In

addition, it will be required that the customer have a meter that provides a minimum of hourly

interval data reads to participate on the program. The proposed tariff change would provide SCE

the authority to remove non-performers who provide minimal demand response benefits and to

improve the overall performance of the program.

Upon commission approval of the changes, customers participating in SDP will be

informed of the program change, and non-performers will be removed at the beginning of 2017.

SCE notes that in order to provide customers with advance notice of this change, a final decision

on this filing is needed by September 2016. If the final decision is issued later than September

25

2016, SCE will be unable to provide sufficient advance notice to its customers to allow

implementation of these program changes at the beginning of 2017.

6. Circuit Savers

Since 2006, SCE has implemented supplemental residential DSM marketing to a small

set of customers via the Circuit Savers program. The outreach was designed to help provide

local circuit loading relief through program participation in DR programs such as SDP. The

program did not provide any incentives or technology for DR programs. It provided additional

local marketing funding for outreach to specific communities in possible constrained areas with

summer peaking loads.

In recent years, the opportunities for addressing locational circuit constraints through

third-party solutions have been evolving through new program initiatives such as the Preferred

Resources Pilot and LCR RFO. Because the Circuit Savers program is categorized as a

marketing, education, and outreach (ME&O) program, program solicitation efforts must align

with the availability of operational program budgets. Currently, there are no plans to actively

promote SCE’s residential DR programs in 2017 due to anticipated program changes such as

discontinuing program options within the PTR program and reduced SDP outreach.32 For these

reasons, SCE proposes to eliminate the Circuit Savers marketing program in 2017.

V.

CONTENTS OF SCE’S PROPOSED 2017 DEMAND RESPONSE PORTFOLIO

In this section, SCE discusses various aspects of its proposed DR portfolio for 2017 as

required by the Ruling. Subsection A provides an updated cost-effectiveness analysis for DR

32 For the last ten years, the program has provided supplemental local marketing funding for SCE’s DR programs as was needed during that time, but SCE expects that enrollments for locational DR will be largely achieved by third parties through both the new PTR program design and external RFO solicitations for future residential programs and products that will be focused on local dispatch and integrated into the CAISO wholesale market.

26

programs in which SCE’s proposed changes alter the cost-effectiveness inputs. Subsection B

contains SCE’s total budget request for its 2017 DR portfolio. Subsection C identifies the

estimated MW savings for each DR program in 2017. Subsection D identifies any DR programs

or incentives for which funding was authorized in a proceeding other than SCE’s 2012-2014 DR

Funding Application. Subsection E contains SCE’s schedule proposal for transitioning to the

inclusion of all DR programs and incentives being requested in one proceeding.

A. Cost-Effectiveness Protocols

Per the Ruling, SCE provides a revised cost-effectiveness analysis for the only DR

program where its proposals alter cost-effectiveness inputs:33 CBP (DO and DA options). As

directed, SCE used the most recent E3 avoided cost model.34

The A-factor represents the portion of capacity value that can be captured by the DR

program based on the frequency and duration of calls permitted. For instance, a program with

unlimited calls and unlimited frequency of occurrence would have an A-factor of 1.0, reflecting

the fact that a program with these parameters has the same capacity (system reliability) value as a

combustion turbine. SCE’s A-factor model is based on the loss of load expectation (LOLE)

analysis of SCE’s system. SCE’s LOLE and A-factor spreadsheet models were also used in

Phase 2 of SCE’s 2015 GRC Rate Design Proposal.

A primary input into the A-factor model is the hourly probability of a loss-of-load event,

calculated by the LOLE model. LOLE is a measure of system reliability that indicates the ability

(or inability) to deliver energy to the load, and the LOLE model estimates when a loss of load is

likely to occur. The main bases for calculating a probabilistic estimate of LOLE hourly

distribution include thirty-year weather and load data and a forecast of expected load and

resources in 2017.

33 See Ruling, p. 10. 34 Available at https://ethree.com/public_projects/cpucSGIP.php [as of February 1, 2016].

27

The Total Resource Cost (TRC) cost-effectiveness results for both CBP options are

shown in Table V-5. Both options, Day-Of and Day-Ahead, have TRC cost-effectiveness results

that are calculated at above the 0.9 threshold, and as such, are cost effective.35

Table V-4 TRC Test Results for CBP

Program TRC Capacity Bidding Program (Day Of) 1.52 Capacity Bidding Program (Day Ahead) 1.46

B. Proposed 2017 DR Portfolio Budget

SCE requests a total DR budget authorization of $44,283,294 for 2017, reflecting a

reduction of approximately $41,870,238, or 49 percent, from the annual average of the 2015-

2016 bridge funding authorized in D.14-05-025.36 Table V-5 summarizes the funding request.

35 The Commission has stated that programs with TRC test results higher than 0.9 are considered to be cost-effective. See D.12-04-045, p. 44.

36 D.14-05-025, Attachment 4.

28

Table V-5

2015-16 Authorized and 2017 Requested, with Percentage Reduction, by Category $ in ‘000s

Funding Category

Average Annual Authorized 2015-2016

Requested 2017 Change

Percentage Decrease

Category 1: Reliability Programs $1,441 $750 $(691) 48%

Category 2: Price Responsive Programs $23,748 $6,429 $(17,319) 73%

Category 3: DR Provider/Aggregator Managed Programs

$24,650 $17,325 $(7,325) 30%

Category 4: Emerging & Enabling Technologies

$17,281 $10,081 $(7,200) 42%

Category 5: Pilots $0 $1,000 $1,000 Increase of $1,000

Category 6: EM&V $2,535 $2,535 $ -- No Change

Category 7: ME&O $5,865 $1,663 $(4,022) 72%

Category 8: DR System Support Activities $5,967 $4,500 $(1,467) 25%

Category 9: Integrated Programs and Activities $0 $0 $ -- Not Applicable

Category 10: Special Projects $4,667 $0 $(4,667) 100%

Category 11: Dynamic Pricing $0 $0 $ -- Not Applicable

Total Budget $86,154 $44,283 $(41,871) 49%

In addition, as instructed in the Ruling, SCE included a complete budget for the proposed

2017 DR portfolio, including the subcategories for each DR category, in Appendix C. The

following subsections describe the primary cost reduction drivers for each budget category and

SCE’s proposal for rate recovery.

1. Category 1: Reliability Programs

SCE proposes a total budget of $750,000 for Category 1 for the 2017 bridge funding

period. This is a decrease of $691,000, or 48 percent, from the average annual 2015-2016

authorized amount. DR programs included in Category 1 include AP-I, BIP, Optional Binding

Mandatory Curtailment (OBMC), Rotating Outages, and Scheduled Load Reduction (SLR). The

$691,000 cost reduction is a result of changes to the AP-I and BIP programs since the 2012-2014

funding cycle. D.12-04-045 authorized a total of $4,324,410 for the 2012-2014 funding cycle for

29

Category 1 programs, of which 91% was funding authorized for AP-I and BIP. Budgets for

Category 1 programs were continued at the same funding levels for the 2015-2016 bridge

funding cycle.37 In 2012-2014, funding for AP-I and BIP was primarily attributed to labor costs

and non-labor costs such as AP-I load control devices and installation, BIP Remote Terminal

Units (RTU) and aircards for the RTUs. During the 2012-2014 program cycle, SCE phased out

the use of RTUs for BIP, therefore, the funding for RTUs and aircards are no longer needed. In

addition to reductions in non-labor funding, AP-I and BIP labor budgets are requested based

upon recent spending averages. SCE expects the current labor and non-labor spending trends to

continue in 2017 for these programs. No budgets changes are being sought for OBMC, Rotating

Outages, and the SLR programs.

2. Category 2: Price-Responsive Programs

SCE proposes a budget of $6,429,000 for Category 2 in 2017. This is a decrease of

$17,319,000, or 73 percent, from the average annual 2015-2016 authorized amount. DR

programs included in Category 2 include CBP, DBP, SDP, and PTR. The $17,319,000 cost

reduction is due to four factors: (1) elimination of DBP; (2) cost reductions as a result of changes

to CBP discussed in Sections IV.A.2 and IV.B.2; (3) increase in budget to enable changes

discussed in Section IV.A.3 for PTR-ET-DLC; and (4) SDP budget reduction. The first three

factors are discussed in earlier sections of this document. The fourth factor, SDP budget

reduction, is discussed below. Table V-6 shows the budget change for Category 2 from 2015-

2016 authorized amount to 2017 proposed amount.

37 For the 2015-2016 bridge funding cycle, Category 1 was authorized two-thirds of its 2012-2014 authorized amount ($2,882,941).

30

Table V-6 DR Budget Category 2: Budget Change from 2015-2016 Authorized to 2017 Proposed

$ ‘000s

Program

Average Annual

Authorized 2015-2016


CBP $220 $198 $(22)

DBP $495 $-- $(495)

SDP $21,464 $4,507 $(16,957)

PTR $1,569 $1,724 $155

Total Budget for Category 2 $23,748 $44,283 $(17,319)

In D.12-04-045, SDP was authorized $64,391,768 for the 2012-2014 funding cycle. For

the 2015-2016 bridge funding period, D.14-05-025 authorized a budget of $42,928,845 (or

$21,463,922 per year) for SDP. Much of the funding approved in D.12-04-045 was for expenses

related to purchasing and installing cycling devices. Much of the budget for cycling devices and

installation will not be needed in 2017 because SCE anticipates SDP enrollment will decrease

significantly due to a high rate of event-related attrition and less spending on large-scale

enrollment campaigns.

3. Category 3: DR Provider / Aggregator Managed Programs

SCE proposes a budget of $17,325,000 for Category 3 for the 2017 bridge funding

period. This is a decrease of $7,325,000, or 30 percent, from the average annual 2015-2016

authorized amount. D.13-01-024 authorized a total of $49,307,888 for the five Demand

Response Resource Purchase Agreements (AMP contracts), representing up to 296 MW, for

2013 and 2014. Of the $49.3 million, approximately $1.4 million was authorized to fund

administrative costs such as labor and associated non-labor activities. The remaining $47.9

million was for the contracts’ capacity incentive costs. For the 2015-2016 bridge funding cycle,

D.14-05-025 authorized the same amount as the 2013-2014 AMP contracts but required SCE re-

negotiate these contracts, with modifications, for the 2015-2016 bridge period. CPUC

31

Resolution E-4695 approved only two of the four re-negotiated contracts SCE submitted in

Advice Letter 3078-E.

The $17,325,000 SCE proposes for Category 3 consists of $560,000 to administer AMP

contracts and $16,765,000 for AMP capacity payments. The $7,325,000 funding reduction is

based upon the anticipated 2017 AMP contract capacity costs representing up to 150 MW. If the

Commission approves AMP contracts for 2017 and the capacity cost for these contracts exceeds

SCE’s budget request of $16,765,000, SCE will seek additional funding. Alternatively, if the

Commission decides not to approve any AMP contracts for 2017, SCE requests an additional

$200,000 for additional administrative costs for its Capacity Bidding Program. If the AMP

program is eliminated, AMP Aggregators are likely to migrate to CBP.

Category 3 also includes a funding line item for the Demand Response Auction

Mechanism (DRAM). On October 9, 2015, SCE filed AL 3292-E which included a budget of $6

million for the 2017 DRAM Pilot.38 AL 3292-E details the DRAM Pilot design, schedule, and

forecast expenditures. The increase in funds requested for the 2017 DRAM pilot, compared to

the 2016 DRAM pilot, is due to potentially longer term contracts39 and higher value products40.

As authorized by D.14-12-024, OP 5b and corresponding discussion elsewhere within D.14-12-

024, and confirmed by Resolution E-4754, OP 8 and OP 9, the 2017 DRAM Pilot will be funded

from the authorized 2015-2016 bridge funding period in D.14-05-025. Therefore, SCE will shift

$6,000,000 from its unspent, uncommitted AMP program funding to fund the DRAM Pilot

through 2017. SCE does not request any funding for 2017 DRAM activities in this filing.

38 Advice Letter 3292-E et al, titled “Southern California Edison Company, Pacific Gas and Electric Company, and San Diego Gas & Electric Company’s Demand Response Auction Mechanism Pilot for 2017.”

39 The 2016 DRAM pilot is a 7-month duration (June to December), whereas, the 2017 DRAM pilot is a 12-month duration (January to December).

40 The 2016 DRAM pilot is for System RA only, whereas, the 2017 DRAM pilot will include System, Local, and Flexible RA.

32

4. Category 4: Emerging & Enabling Technology


$7,200,000, or 42 percent, from the average annual 2015-2016 authorized amount. Category 4

consists of DR activities related to AutoDR and DR Emerging Markets and Technologies

(EM&T). The $7,200,000 cost reduction for Category 4 is driven by the changes to the AutoDR

program discussed in Section IV.B.1.

5. Category 5: Pilots

SCE proposes a budget of $1,000,000 for Category 5 in 2017 for the Over-Generation

Pilot discussed in Section IV.A.4. This Category did not include any funding in 2015-2016.

6. Category 6: EM&V

SCE expects activities for budget category 6 to remain the same in 2017 as they were

during the 2016-2016 bridge period. Therefore, there are no changes from the average annual

2015-2016 authorized amount to the 2017 proposed amount.

7. Category 7: ME&O


$4,202,000, or 72 percent, from the average annual 2015-2016 authorized amount. The

$4,202,000 cost reduction is due to five factors: (1) removal of local marketing for DBP due to

the elimination of the program; (2) removal of local marketing for Circuit Savers due to the

elimination of the program; (3) reduced local marketing for SDP-residential; (3) reduced local

marketing for PTR; and (4) local marketing funding for Permanent Load Shifting (PLS) is not

requested because SCE anticipates there will be unspent uncommitted funds from its 2015-2016

budget. SCE will propose disposition of that funding consistent with its applicable balancing

account tariffs. Category 7 also includes local marketing for AutoDR, which SCE is not

proposing to change from the average annual authorized amount for 2015-2016. Table V-7

33

shows the budget change for Category 7 from 2015-2016 authorized amount to 2017 proposed

amount. Table V-7

DR Budget Category 7: Budget Change from 2015-2016 Authorized to 2017 Proposed $ ‘000s

ME&O Category

Average Annual

Authorized 2015-2016


Local Marketing – DBP $92 $-- $(92)

Local Marketing – Circuit Savers $333 $-- $(333)

Local Marketing – SDP $1,950 $1,293 $(657)

Local Marketing – PTR $3,333 $297 $(3,036)

Local Marketing - PLS $83 $-- $(83)

Local Marketing – AutoDR $73 $73 $--

Total Budget for Category 7 $5,865 $1,663 $(4,202)

8. Category 8: DR System Support Activities


$1,467,000, or 25 percent, from the average annual 2015-2016 authorized amount. D.14-05-025

authorized 2015-2016 funding for DR system support activities at the same levels approved in

D.12-04-045. In the 2015-2016 bridge funding period, the average annual amount for DR

systems support consisted of approximately $2,000,000 for System License and Hosting

activities conducted by external vendors, $2,000,000 for system enhancements, and $2,000,000

for SCE labor. The $1,467,000 cost reduction for Category 8 is a result of two factors: (1) the

budget for SCE labor for DR technology-related efforts will be reduced by approximately

$500,000; and (2) SCE will reduce by nearly $1,000,000 its efforts for system enhancement and

technology upgrades because many of the system enhancements approved in D.12-04-045 to

enable wholesale market integration have been completed.

34

9. Category 9: Integrated Programs and Activities

Category 9 covers DR-related IDSM programs, which will be funded through Energy

Efficiency in 2017. As in the 2015-2016 bridge period, there is no budget in this category.

10. Category 10: Special Projects

SCE proposes no budget for Category 10 in 2017, which is a decrease of $4,667,000, or

100 percent, from the average annual 2015-2016 authorized amount. This category is made up

of “special projects,” of which the only current one is the PLS program. SCE is not requesting

any incremental funding for PLS in 2017 because at current reservation and costs incurred to

date, SCE anticipates there will be unspent and uncommitted PLS funding from its 2015-2016

authorization. SCE will propose disposition of that funding consistent with its applicable

balancing account tariffs.

11. Category 11: Dynamic Pricing

These activities are funded through the GRC in 2017. Therefore, similar to the 2015-

2016 bridge period, SCE does not seek any funding for this category.

12. Rate Recovery Proposal

SCE requests that the 2017 DR bridge period revenue requirement of $44.283 million

become effective on January 1, 2017,41 which is a $41.871 million decrease over the annual

average 2015-2016 authorized funding level. SCE will record the revenue requirement approved

for 2017, and the authorized expenditures incurred in 2017, in SCE’s existing authorized

ratemaking mechanisms for DR.42 If SCE has any unspent and uncommitted funds remaining at

41 This amount will be grossed up for Franchise Fees and Uncollectibles expense when reflected in rate levels.

42 SCE recovers authorized DR costs through three balancing accounts: (1) the Demand Response Program Balancing Account (DRPBA); (2) Purchase Agreement Administrative Costs Balancing Account (PAACBA); and (3) Base Revenue Requirement Balancing Account (BRRBA).

35

the end of 2016, SCE will use those funds to offset the revenue requirement for 2017. This

proposal results in a decrease in the DR revenue requirement currently reflected in rates.

C. Anticipated 2017 MW

The Ruling directs the IOUs to include “the anticipated 2017 megawatts for each

proposed demand response program.”43 These program level “ex ante” forecasts are more

appropriately identified in the forthcoming April 1st Demand Response Load Impact Compliance

Filing (Load Impact Report) for program year 2015, pursuant to the load impact filing

requirements adopted in D.08-04-050, as modified by D.10-04-006. In the Load Impact Report,

SCE identifies the load impacts from 2015 events (ex post load impacts) and load reduction

capabilities for 2016 through 2026 under normal (1-in-2 year) and extreme (1-in-10 year) system

conditions (ex ante load impacts). Ex ante load impacts are summarized for each program and

for SCE’s DR portfolio as a whole, with the portfolio impacts summarizing the load reduction

that can be expected from all of SCE’s DR programs if jointly dispatched. In other words, they

avoid double counting load impacts from dually-enrolled customers. Ex ante load impacts are

forward-looking and are designed to reflect the load reduction capability of a DR resource under

a standard set of conditions, under normal and extreme weather conditions.

These ex ante forecasts change each program year, varying over a ten year span as well

as by season. The forecasts also take into account the most recent actual DR event performance

and up-to-date participation forecasts based on customer enrollments, as well as specific weather

conditions. The results of the analyses are based on individual customer time series regressions,

aggregate time series regressions, and panel regressions to increase the accuracy of impact

estimates for the average customer. The regression models used to predict the reference load

were developed with the primary goal of accurately predicting average customer load given the

time of day, day of week, temperature, and location of each customer and predicting load

43 Ruling, p. 13.

36

reductions under different temperature conditions. These estimates are the most valid forecasts

for 2017 anticipated MW for each DR program, and the draft forecasts will be available for

review in late March, 2016, with formal filing on April 1, 2016.

Because the Load Impact Reports are not yet available for 2015, and to meet the Ruling’s

requirement to include anticipated 2017 MW for each DR programs, SCE has included Table V-

4, which identifies the load impact forecasts for its DR programs for the 2017 program year

(based on 2014 program performance).44

44 Southern California Edison Company’s Compliance Filing Pursuant to Load Impact Protocol Filing Requirements (Load Impact Filing), filed April 1, 2015.

37

Table V-8 2017 Portfolio Aggregate Ex Ante Load Impact Estimates

for 1-in-2 SCE-specific System Conditions45

D. List of Programs External to 2012-2014 Application

The Ruling requests that SCE include a list identifying “all programs and incentives

provided through demand response but established external to the 2012-2014 demand response

application proceeding.”46 SCE’s funding for the 2012-2014 DR portfolio was authorized in

D.12-04-045. Much of that funding was continued for the 2015-2016 bridge period in D.14-05-

025 in Phase 1 of this proceeding. In this section, SCE identifies three categories of incentives

and programs that were not authorized in the 2012-2014 DR application proceeding: (1) Tariff

program incentives, (2) IDSM, and (3) AMP Contracts.

45 The MW in Table V-8 are as filed in SCE’s April 1, 2015 Load Impact Filing, and do not take into account SCE’s proposed program changes. SCE will file an updated Load Impact Filing on April 1, 2016.

46 Ruling, p. 13.

38

1. Tariff program incentives

Incentive levels for SCE’s tariff programs (BIP, AP-I, SDP, and PTR,) are typically

determined in Phase 2 of SCE’s General Rate Case (GRC) proceedings. The current incentive

levels were approved in SCE’s 2012 GRC Phase 2 proceeding through D.13-03-031. Incentives

for the tariff programs, listed above, do not require incremental funding request, as these

incentives are funded through surcharges embedded within the retail rate. SCE currently has a

Settlement Agreement pending in its 2015 GRC Phase 2 (A.14-06-014), which will continue the

current incentive levels for SDP and PTR, and adjust incentive levels for BIP and AP-I upward

by 10%.

2. IDSM Programs

The August 2010 Guidance Ruling for the 2012-2014 DR Applications directed the IOUs

to request DR IDSM bridge funding in the 2012-2014 DR application for only one year (2012).47

This one year request for 2012 DR IDSM activities was ultimately approved in D.12-04-045. In

that Decision, the Commission also directed that future requests for DR IDSM pilots and

programs conducted jointly with EE programs should be submitted in the EE proceeding for the

2013-2104 EE Transition Application. Funding for the activities that only pertain to DR were to

be requested in the 2012-2014 DR applications.

In compliance with this requirement, SCE requested IDSM funds for joint DR and EE

efforts in its 2013-2014 EE Application (A.12-07-001). That funding was approved in D.12-04-

015, adopting both the 2013-2014 EE programs and the DR IDSM programs. Funding for the

2013-2014 DR IDSM activities were continued in the 2015 EE bridge funding decision (D.14-

10-046), which adopted funding at 2015 levels each year until SCE files a new EE Application

under the new Rolling Portfolio process.

47 See Administrative Law Judge’s Ruling Providing Guidance for the 2012-2014 Demand Response Applications, issued August 27, 2010, p. 14.

39

3. AMP Contracts

In D.12-04-045, the Commission directed SCE to maintain, at a minimum, the current

level (in MW) of AMP contracts through the end of 2014. In 2012, SCE renegotiated the

contracts with third-party aggregators and filed application (A.)12-09-007, for approval of five

DR contacts that were approved in D.13-01-024 for a total of $49,300,000 for 2013 and 2014.

Funding to continue the AMP contracts in the 2015-2016 bridge period was authorized in D.14-

05-025 and pursuant to that decision, SCE made additional modifications to its AMP contracts in

2014 via Advice Letter 3078-E, which were approved in Resolution E-4695.

4. Proposed Schedule for Consolidating Programs

The Ruling indicated that the IOUs should include “a proposed schedule to consolidate

all demand response programs and incentives into one demand response portfolio.”48 SCE

proposes that no consolidation occur for its DR portfolio at this time, as SCE’s program funding

requests and incentives are already considered in the appropriate proceedings. Currently, DR

program funding is sought through periodic DR funding applications, while most DR incentives

are set through Phase 2 of SCE’s GRC filing, and certain IDSM programs are sought through the

EE proceeding. DR incentives not recovered through DR funding filings are properly sought

through Phase 2 of the GRC because they result in surcharges that are then allocated to rate

groups based on the allocation factors determined through the Phase 2 marginal cost and revenue

allocation process. In addition, DR incentives for BIP, SDP, AP-I and PTR are determined

through an avoided capacity valuation methodology, similar to the method used for cost-

effectiveness valuation, in order to determine the proper incentive level with respect to capacity

related charges. Through this process SCE is able to align the capacity payments made through

DR incentives with the capacity charges assessed through time-related-demand charges. This

process is effective and should not be changed at this time. To the extent that the Commission

48 Ruling, p. 13.

40

decides to consider consolidating SCE’s DR filings, it should first identify what issues are

argued in all relevant proceedings with respect to funding request, cost-effectiveness, incentive

levels, and revenue allocation.

As IDSM activity funding has already been authorized through 2026, SCE will continue

to propose funding for IDSM activities that are joint EE and DR efforts through EE funding

applications, unless the Commission orders otherwise.

E. Miscellaneous Issues

Per the Ruling, this section provides a discussion of the customer protection rules related

to Senate Bill (SB) 1414, as well as whether studies designed to advance the Commission’s DR

goals should continue to be funded in 2017.

1. Customer Protection

The utilities are required to include in their 2017 proposal recommendations regarding

SB 1414, which added Section 380.5 to the Public Utilities (PU) Code and went into effect in

January 2015.49 SCE has determined that existing customer protection rules meet the criteria of

PU Code § 380.5(a)(3) and (b) based on a plain language reading of the statute, the legislative

history of the evolution of the language, and the legislative intent stated in the bill itself.

The plain language of the statute says that utilities should not impose a charge on

residential customers “for not enrolling in the program.”50 Imposition of charges for not

enrolling means a separate charge levied on the customer for non-participation. The charge

described in the plain language of the statute does not refer to the costs spread to customers

through ordinary utility rate design, which works by spreading the costs of programs across

customer classes even if they do not participate in a particular program and derive program

benefits because the program itself provides overall benefits. It is also not related to the charges

49 See Ruling, p. 14. 50 Cal. Pub. Util. Code § 380.5(a) (3).

41

that participating customers may be liable for because those customers are enrolled in the

program and deriving benefits directly from it.

The evolution of this statutory language supports the idea that the legislature is concerned

only with specific charges for non-participating customers beyond ordinary rate design. When

the bill was first introduced in February 2014, it did not include Section 380.5.51 Later, in the

amendment process, the proposed (and rejected) language was: “A residential customer who opts

out of the program shall lose eligibility for rebates, discounts, and other incentives offered to

customers who participate in the program. The commission shall prohibit the imposition of

charges on a residential customer for opting out of the program. A residential customer who opts

out of the program shall still be eligible for time-variant pricing.”52 The section was further

amended on August 20, 2014 to substitute the word “opt-out” with the phrase “not enroll in.”53

Therefore, the legislature has stated that charges for opting out are not their concern; their

concern is for those customers who do not enroll at all.

Finally, the legislative intent of SB 1414 supports the sufficiency of existing customer

protection rules. SB 1414 Section 1(C) states: “It is further the intent of the Legislature, in

enacting this act, to ensure that the procurement, programmatic, tariff-based, and other options

that the Commission is pursuing or may pursue in furtherance of DR are in no way hindered or

superseded by the provisions in this act.”54 Thus, no additional rules are needed because SCE

does not levy a non-participation charge on customers. While it is true that DR program costs

are shared among all customers, this is not at issue in the statute for the reasons described below.

Neither are the program penalties for participating customers who fail to perform under the terms

of their agreement in a program.

51 See 2013 Legis. Bill. Hist., CA SB 1414, Bill Text as Introduced, February 21, 2014. 52 2013 Legis. Bill Hist., CA SB 1414, Bill Text as Amended, August 6, 2014, p. 8. 53 2013 Legis. Bill Hist., CA SB 1414, Bill Text as Amended, August 20, 2014, p. 7. 54 Stats 2014 ch 627 § 3 (SB 1414), enacted September 26, 2014.

42

For these reasons, SCE’s DR programs comply with the customer protections described

in this new statute. Interpreting the statute in any other way will lead to unintended

consequences for utility rate design. It would also violate the stated intent of the statute that the

Commission pursue DR unhindered or superseded by this Act.

2. DR Study Funding

In D.12-04-045, the Commission authorized $1 million per fiscal year, through 2015, in

Evaluation, Measurement and Validation (EM&V) funds for “DR Potential, Market Assessment

and Technology Studies, and Policy and Planning Support Studies” (Research Studies) that the

Commission viewed as “important to the success of DR programs” and that will “inform

Commission policies on DR programs”.55 D.12-04-045 stated that “the Executive Director may

hire and manage one or more contractors to perform tasks as described in this decision for the

purpose of performing studies that advance the goals of the Commission’s Demand Response

activities.”56 Subsequently, the Commission extended the expenditure authorization of the

Executive Director through 2016 in D.15-02-007.57 The Ruling requires the Utilities to “provide

an explanation of why the Commission should or should not continue funding during the 2017

bridge funding year.”58 At this time, SCE sees no compelling reason to ask the Commission to

discontinue funding for the 2017 bridge period, as that may interrupt ongoing studies (such as the

DR Potential Study) that are necessary for DR policy analysis..

SCE is unclear of the overall research agenda and specific objectives for the funding for

these Research Studies. SCE is aware of one research study (2015 California DR Potential

Study)59 in which SCE is an active participant and there may be others in progress or in planning

that are unknown to SCE at this time. While the Commission’s goal to conduct research to

55 D.12-04-045, p. 168. 56 D.12-04-045, OP 72 at p. 228. 57 D.15-02-007, OP 6 at p. 13. 58 Ruling, p. 14. 59 As authorized in D.14-12-024, OP 3.

43

inform DR policy is important, any expenditures of ratepayer funds for these Research Studies

should undergo both a technical needs assessment and reasonableness review at the project level,

as well as peer review by the IOUs and other stakeholders in the planning phase. The research

goals for these expenditures should reflect valid and reasonable study plans that details such as

scope, timing, and research intent for each study being planned.

As a condition of their continued expenditure authorization, the Executive Director

should engage stakeholders in a collaborative process to ensure that the Research Studies are as

transparent and inclusive for stakeholders as the IOUs’ DR EM&V activities. Similar to the

processes that are inherent to quality control of the load impact and process evaluation reports as

overseen by the DR Measurement and Evaluation Committee (DRMEC), the Research Studies

should engage stakeholders at the foundational planning level. This will increase the likelihood

that the Research Studies are performed when necessary and that funds are spent reasonably,

while reducing the chance that policy issues or important research goals are overlooked.

3. AB 793

At the DR Market Integration workshop on January 12, 2016, ALJ Hymes requested that

the IOUs discuss in this filing the education plan envisioned in AB 793. On October 8, 2015,

Governor Brown signed AB 793 into law, which amended Section 2790, and added Section 717,

of the California Public Utilities Code and obligated the Commission to order electrical and gas

corporations to:

Develop a program, no later than January 1, 2017, to provide incentives to a

residential or small or medium business customer to acquire energy management

technology for use in the customer’s home or place of business;

Develop a plan, by September 30, 2016, to educate residential customers and small

and medium business customers about that incentive program, and

Annually report to the Commission on actual customer savings resulting from the

incentive program in a manner consistent with Commission-adopted protocols.

44

While awaiting Commission guidance on AB 793 implementation, SCE’s work to

identify ideas that could inform the program and education plan is just getting underway. As the

Commission considers how to implement this new statute, recommends these issues be resolved:

Determination of which Commission proceeding will implement the statute;

Definition of an “energy management technology;”

How the program costs and incentives will be funded;

Requirements for program design; and

Metrics, parameters, and scope of the education plan.

VI.

CONCLUSION

SCE appreciates the opportunity to provide its 2017 Demand Response Bridge Funding

proposal.

Respectfully submitted, JANET S. COMBS ANGELICA M. MORALES

/s/ Angelica M. Morales By: Angelica M. Morales Attorneys for SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-4435 Facsimile: (626) 302-6962 E-mail: Angelica.Morales @sce.com

Dated: February 1, 2016

Appendix A

Barriers and Challenges SCE Experienced Integrating DR into the CAISO Markets

A-1

In this Appendix, SCE identifies the challenges it experienced when integrating DR

programs into the CAISO market. For some of these challenges, SCE has been able reach a

temporary resolution with the CAISO, but permanent solutions are still needed. SCE also

discusses issues that are barriers to achieving further integration. In some cases, SCE has

proposed a means of mitigating these challenges and barriers. This Appendix also includes

lessons learned from the DRAM pilot program.

A. Issues and Barriers Related to Integration of DR into the CAISO Markets

1. CAISO Minimum Size Requirement

The CAISO has a minimum capacity requirement for a resource to qualify as a PDR or

RDRR. Those minimum requirements are 100 kW for PDR and 500 kW for RDRR. This

disaggregation of the programs into many small resources is primarily driven by the CAISO

requirement that resource registrations be unique by both LSE and Sub-LAP, which leads to

partitioning of the DR programs into several groups of customers called “Aggregate Locations”

(ALOCs) for purposes of registration with CAISO. Some LSEs serve small customer

populations that result in certain ALOCs being too small to meet the CAISO’s minimum size

requirement. As stated previously in this filing, this requirement has prevented SCE from being

able to integrate approximately 4 MW from its integrated DR programs.

2. Transition to new DR Registration System (DRRS)

As discussed in SCE’s Response to PG&E’s November 9, 2015 Motion, the CAISO’s

transition to a new DRRS locational registration update, currently anticipated for April 2016,

presents some challenges.60 SCE is working with internal stakeholders and the CAISO to

implement and manage a smooth transition, but concerns remain about the operational

60 SCE agreed with PG&E’s Motion that there are certain concerns and risks associated with CAISO’s system transition. See SCE’s Response to PG&E Motion dated November 24, 2015.

A-2

complexity of both re-registering over 300,000 currently integrated SAs into the new system and

of updating SAs in registered resources.

3. Telemetry waiver for two PDR resources

The CAISO provided SCE a waiver until October 29, 2015 to install telemetry for two

affected resources61 that belong to an AMP contract. After investigating with the aggregator

whether telemetry can be provided for customers that make up the two resources, SCE

determined that it is not possible to cost-effectively install, nor does it have authorized funding to

install, telemetry for those resources. Thus, SCE has decided to distribute the two existing

resources that were greater than 10 MW into six smaller resources with capacities under 10 MW

for the purposes of CAISO market registration. As part of the adopted recommendations from

the Supply Integration Working Group, CAISO agreed to relax the telemetry requirements for

the resources participating in its energy markets. Specifically, CAISO plans to allow 5-minute

scan rates for the telemetry in energy markets (the current requirement is one minute), which

would make it possible for the market participants to use KYZ pulse devices62 that are already

available for many larger customers that participate in the DR programs. While this will not

address the telemetry issue for all customers and programs, as well as for participating in the

ancillary services market, SCE supports this modification as a move in the right direction.

SCE has identified several long-term solutions to address telemetry for all DR customers,

including raising the threshold for the telemetry requirement beyond the current 10 MW resource

size, implementing telemetry based on statistical sampling, achieving reductions in the cost of

telemetry devices, or some combination of these solutions. SCE plans to include telemetry

61 CAISO requires telemetry for PDR resources above 10 MW. 62 KYZ pulse devices are a data communication feature that provide a real-time digital measurement of

the energy consumed at an electric meter. When incorporated into an electrical meter, the KYZ relay changes state with each rotation (or half rotation) of the meter disc. Each state change is called a "pulse.” When connected to external equipment, rate of use (kW) as well as total usage (kWh) can be determined from the rate and quantity of pulses.

A-3

requirements in its 2017 AMP contracts, if the Commission authorizes an extension of these

contracts for the 2017 bridge year.

4. Use of 60-minute metering interval data for RDRR settlement

At the time of SCE’s RDRR integration, CAISO gave SCE a waiver until December 31,

2015 to use 60-minute metering data instead of 15-minute intervals for the settlement of RDRR

resources and then extended the waiver until July 31, 2016. Concurrently, SCE investigated: (1)

the number of customer meters already programmed at 15‐minute intervals; (2) the cost of

reprogramming additional customer meters from hourly to 15‐minute intervals; and (3) the

possibility of implementing statistical sampling as an alternative to reprogramming all customer

meters to 15‐minute intervals.

Based on the initial analysis of the cost-effectiveness of the alternatives, SCE decided to

request an extension of the waiver, which CAISO granted until July 31, 2016. SCE is currently

in the process of modifying its information technology (IT) systems to enable the submittal of

15-minute interval meter data to the CAISO for the settlement of SCE’s RDRRs for which the

underlying customer usage is already metered in 15-minute intervals (i.e., those representing

non-residential DR programs such as BIP, AP-I, and SDP – Commercial). This system

modification is expected to be completed in the first quarter of 2016. Once the system

modification is complete, SCE will modify its waiver request to reflect only the remaining

RDRRs that have the underlying individual customer usage metered in 60-minute intervals (i.e.,

those representing residential DR programs, currently only SDP – Residential).

In addition, SCE will continue to investigate the feasibility of: (1) reprogramming the

remaining SDP – Residential customer meters fully, or to the extent needed for statistical

sampling implementation; and (2) implementing an alternative analytical approach for profiling

hourly intervals into 15-minute. SCE plans to work with the CAISO in 2016 to determine the

most appropriate methodology for statistical sampling of SCE’s SDP – Residential customers

A-4

and utilize it for settlement purposes with CAISO. If necessary, SCE will request a further

extension of the existing waiver beyond July 31, 2016.

5. CAISO Settlement Accuracy

SCE recommends that the CAISO timely resolve errors in settlement calculations for DR

resources bid into the CAISO market. SCE has not received a properly calculated settlement for

any of its dispatches even though it has been more than six months since SCE integrated its

initial batch of DR resources. The settlement statements provided do not accurately calculate

DR resource performance. For example, the CAISO calculated SCE’s DR resource performance

using the metered usage data during the hours of the event, rather than using a baseline minus the

meter data (i.e., the resource was credited for total MW used, rather than the net MW reduction).

Improper settlement from the CAISO creates a financial uncertainty for SCE and makes it more

difficult to evaluate SCE’s DR resource performance against the CAISO market awards for the

purpose of forecast and bidding improvement (as a check on SCE’s own calculations). The

CAISO has acknowledged the settlement issues and states they plan to address them and

recalculate SCE’s DR resource settlement statements back to June of 2015.

6. Specifying Integrated DR Resource Capacity That Counts Towards Meeting

Local Capacity Requirements

The CAISO has recently updated its Business Process Manual (BPM) for Reliability

Requirements to include the requirement for Local RA resources to support 20-minute or less

response time, or have sufficient “pre-dispatches” available. However, there is not a clear

process by which an IOU can specify the amount of DR resources, whether integrated or not, that

meet the 20-minute response requirement. The typical avenue for describing a resource

capability to the CAISO is via the Resource Data Template (RDT). The RDT is supposed to

have all the data to sufficiently describe the integrated resource for CAISO modelling and market

purposes. However, the current RDT format lacks input fields to specify what portion of a DR

A-5

resource is located in the Local Capacity Area and can meet the 20-minute response time

requirement. Thus, SCE plans to work with the CAISO staff to update the RDT files and

functionality to address this issue. In 2015, based on the information available in the existing

RDT, the CAISO was unable to estimate SCE’s DR LCA capabilities and initially assumed that

those capabilities were zero. SCE had to communicate to the CAISO about the SCE DR

program capabilities in the Local Capacity Area via an emergency letter.

7. Need for Custom Baseline Methodology for performance calculation for the

residential programs

The CAISO’s standard methodology for calculating the baseline performance of a DR

resource is a 10-in-10 baseline with a “day of adjustment” limit of +/- 20 percent. Based on

SCE’s experience, that methodology is not appropriate for SDP-Residential resources. The key

reason is that there is a significant increase in customer consumption during event days when

compared to consumption on non-event days (which enters the calculation of the baseline) but

the “day of adjustment” limit of 20 percent prevents the baseline from being accordingly

adjusted upwards. Thus, SCE observed that even on the event days when customers drop their

consumption significantly during the hours of the event (in comparison to the hours prior to the

event), the baseline is so low that the settlement performance calculation used by the CAISO

shows very little or no performance at all by the customers. SCE recommends that the CAISO

determine a more appropriate baseline methodology for calculating performance of residential

programs such as SDP – Residential and add them to the CAISO Tariff, if appropriate.

8. RDRR and RTM Participation

SCE suggests evaluating whether CAISO’s RDRR product could allow RTM

participation on an economic basis to increase DR opportunities. For example, this would allow

BIP customers to offer some of their DR load into the RTM for economic dispatch. Unlike the

DAM, the RTM is more likely to reach energy prices at or above $0.50/kWh--which is the

A-6

incentive available to BIP customers for economic dispatch on a day-ahead basis via dual

enrollment in the DBP.

As an alternative to a real-time option within RDRR, it is worth considering whether

Rule 24 should be modified to allow simultaneous participation by a customer in more than one

resource registration, provided they follow the Commission’s dual participation rules (e.g., not

participating in two capacity programs). This could allow customers to join a BIP RDRR

resource via their LSE, and also directly participate in the energy RTM without the aid of their

LSE or a third-party Demand Response Provider (DRP). Customers could then earn the BIP

capacity credit for being available in emergency situations, while at the same time earning an

energy incentive for RTM participation when their load is not needed for emergency dispatch.

Rule 24’s current dual participation rules do not allow BIP customers to directly participate in

the CAISO energy market if they are already registered in SCE’s BIP resource.

9. Resource Adequacy (RA) Cap on Reliability DR

SCE recommends that the Commission sponsor new discussions on the relevance of the

Settlement Agreement adopted in D.10-06-034.63 This decision placed a ceiling on the amount

of RA that the IOUs can claim from reliability-based DR capacity. The Commission should

consider whether reliability DR that is CAISO-integrated as an RDRR resource should be

exempt from the reliability cap adopted in D.10-06-034. This would support the expansion of

RDRR as an increased number of parties enter the market through both utility programs and

pilots such as DRAM. It will also mitigate the effects of the potential retirement of price-

responsive programs that currently provide a credit against the DR RA cap, as discussed in

Section III.B.

63 Decision Adopting Settlement Agreement on Phase 3 Issues Pertaining to Emergency Triggered Demand Response Programs, issued June 25, 2010.

A-7

10. CAISO Deployment Schedules do not Incorporate Integration Testing with

Market Participants

SCE was unable to fully integrate its DR programs until the CAISO developed the new

Application Programming Interface (API) for the bulk registration of customers in 2015. The

registration problem was particularly significant for large residential programs such as SDP -

Residential. This was the primary reason for SCE having to postpone the integration of its DR

programs from summer 2014 to summer 2015. CAISO deployed the API at the end of March

2015, but SCE was not able to register all of its DR resources until the end of May 2015. This

was in part due to SCE not being able to fully develop and test its complementary systems to

work with the new API until after the API was deployed. SCE recommends that future CAISO

system deployment timelines incorporate time for market participants to develop complementary

systems that work with new applications or software.64

A similar situation could occur with the CAISO’s new DRRS. The current timeframe for

implementation of the DRRS is the end of April 2016. However, SCE does not expect that the

DRRS will have been fully tested with market participants at the time of its deployment, so the

DRRS will likely not be fully operational when it is put into production in April. This can

potentially cause delays in SCE’s ability to review and approve 3rd party DRP registrations (such

as those of DRAM participants) in the months following the DRRS production release.

11. Update Frequency of Resource Registrations

Due to the current limitations in the CAISO’s DRRS, re-registration to reflect changes to

the SA composition of a DR resource cannot begin until the previous registration is terminated.

Because the re-registration process can last up to 10 days (due to the required Utility Distribution

64 While the CAISO has more recently provided information to market participants during the development cycle of new systems, the implementation deadlines remain unrealistic because CAISO applications need to be finished and in place to enable testing and compatibility with market participant software.

A-8

Company (UDC), LSE, and CAISO approvals) and the DR resource cannot be offered in the

CAISO market during this process, the resource could be out of the market for a significant

time65. For this reason, SCE notified CAISO that it plans to re-register its DR resources only

when the SA composition of the resources changes significantly enough to affect the resource

performance but not more frequently than monthly. In addition, SCE stated that it plans to self-

dispatch those resources outside of the market (as before the integration of the resource) for the

duration of the re-registration process if the program dispatch criteria are met. CAISO

responded that it finds SCE approach to re-registration to be reasonable given the identified

DRRS issues, and it has since worked on making improvements to the DRRS to minimize the re-

registration issues. The two new features of the CAISO’s DRRS that are planned for the release

in April 2016 that will lessen the re-registration issues include (1) allowing re-registration

process for a resource to begin before the termination of the existing registration and (2) not

requiring UDC and LSE re-approval of the registrations for the SAs that move between two

registrations. While the improvements to the DRRS are expected to enable more frequent re-

registrations of the resources in order to more properly reflect the SAs that belong to the

resources, SCE expects that the gap between the actual and registered SA composition of the DR

resources will not be completely eliminated. This is expected to be the case because, for some

programs and situations the customers will join or leave DR programs (and thus DR resources)

on a daily basis, but the CAISO registrations will not be able to be updated and approved the

same day (for example, in the case when the resource change results in the need to update the

RDT, CAISO will need to approve the re-registration and it will take them a minimum of 5 days

to complete it).

65 This issue has been discussed by many parties in the DR OIR proceeding and is referred to as the “registration gap.”

A-9

12. Discrete Dispatch and Granularity of Dispatch

Discrete dispatch66 resource classification is not currently allowed by CAISO for PDRs

and for RDRRs in the Day-Ahead market. In addition, SCE is required to register DR resources

in the CAISO market disaggregated by UDC, LSE, and Sub-LAP. However SCE is only able to

dispatch those resources by UDC and Sub-LAP, as SCE’s LCGs are not differentiated by LSE.

While SCE bids all resources belonging to the same LCG at the same bid price, CAISO may at

times award only a subset of those resources fully or partially. If that occurs, SCE notified

CAISO that it plans to fully dispatch all the resources belonging to the same LCG. CAISO

responded to SCE that any differences in performance of the awarded SCE DR resource from its

CAISO awarded level will be subject to the CAISO settlement charges (i.e., the under-

performance/over-performance will be charged/credited at the applicable RTM prices). SCE is

currently investigating potential costs to modify its DR dispatch (load control) systems to allow

more granular dispatch of customers such as at the level of possible CAISO awards (i.e., partial

resource dispatch and dispatch below the LCG level). Because those costs may be significant,

alternative approaches to be considered are (1) CAISO allowing discrete dispatch for PDRs and

RDRRs in the DAM, or (2) CAISO eliminating the requirement for resource registration by LSE.

13. Self-Dispatch of Day-of Resources Outside of RTM

The CPB and AMP programs SCE integrated into the CAISO markets are available for

dispatch in the DAM and the Day-Of (DO) time frame (i.e., for a load reduction during the same

day as the dispatch decision) but are not flexible enough to be offered as resources in the CAISO

RTM. For example, a program that can run for a range of hours may require a customer

notification about the end time of the dispatch at the commencement of the dispatch and thus

could be bid and utilized optimally in the DA energy market but not in the RTM. For those

66 Discrete dispatch refers to a resource being dispatched either at full capacity or not at all i.e. the dispatch cannot occur at some partial capacity level between zero and the full capacity.

A-10

resources, if there are changes in market conditions between the times of CAISO’s DA and

RTM, the resource award (or lack of award) in the DA energy market may be no longer optimal.

Because the resource could still be re-dispatched close to real-time but not by CAISO due to the

lack of the resource bid in RTM, SCE notified CAISO that it plans to re-dispatch such a resource

by itself (i.e., out-of-the-market) given the new market conditions if the resource economics

support it (especially if the resource is significantly energy limited). CAISO has stated that that

any deviation from awards will be subject to the applicable settlement charges and furthermore

that SCE is expected to notify CAISO Real-Time Operations of any planned dispatch deviations

exceeding 50 MW. While SCE has received accommodation from CAISO on this issue thus far,

the best course of action to prevent the issue from persisting is to modify the existing DO

programs that cannot meet the CAISO RTM participation requirements such that they would be

able to do so in the future.

B. Observations and Lessons Learned from DRAM Pilot

ALJ Hymes requested that the utilities discuss in this filing the lessons learned while

implementing the DRAM Pilot design.67 Per D.14-12-024, a statewide stakeholder working

group was convened to develop the DRAM Pilot design. The 2016 DRAM design was filed in

Advice Letter 3208-E et al. on March 20, 2014. The Commission approved the DRAM Pilot

design and Standard Contract with modifications via Resolution E-4728.68 SCE completed the

2016 DRAM Pilot Solicitation, signing contracts for 20.32 MW of DR contracts with System RA

value, and submitted them for Commission review via Advice Letter 3340-E on January 8, 2016.

For the 2017 program year, the DRAM Pilot design was modified to allow for: 1)

inclusion of Local and Flexible RA products; and 2) inclusion of RDRR. The IOUs filed Advice

67 Verbal instruction from ALJ Hymes at Commission DR Market Integration Workshop, January 12, 2016.

68 On August 10, 2015, the Commission issued Resolution E-4737, Executive Director Resolution Instituting Editorial Corrections in Resolution E-4728.

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Letter 3292-E et al, detailing the proposed changes, consistent with direction in OP 11 and OP 12

of Resolution E-4728. The changes to the DRAM design and to the Standard Contract focused

on the implementation of the modifications for Local Capacity, Flexible Capacity and RDRR

resources. The design was approved via Resolution E-4754 on January 28, 2016. The IOUs

intend to launch the 2017 DRAM Pilot solicitation in late February 2016.69

SCE observed the following aspects of the 2016 DRAM solicitation:

There was a significant interest in the 2016 DRAM from an array of parties, as

evidenced by the large number of participants in the bidders’ conference. Many of

the parties expressing interest, and eventually bidding in the auction, appeared new to

the IOU solicitation processes as well as the CAISO market participation rules;

The wide interest was further confirmed by a larger than expected volume of

counterparties, number of offers and total MW offered. While the offers were

relatively small compared to major DR programs, the DRAM solicitation resulted in

SCE contracting for double the minimum required MW target;

The submitted bids displayed a wide range of prices. Procuring additional contracts

would have resulted in much higher incremental prices;

Having a rigid selection process can lead to unintended and potentially uneconomic

consequences. This could be mitigated if greater flexibility was afforded to the

utilities in determining which contracts to select;

Residential bids were competitive with non-Residential ones and represented a

significant portion of the total MW offered. The residential set-aside was met by

following the bid ranking (economic) order;

69 The DRAM solicitation launch is expected 30 days after Advice Letter 3292-E approval, and after Commission Disposition of any Supplemental Advice Letter filing that may be required to comply with the terms of Resolution E-4754.

A-12

Under the Commission guidance and direction and with the Independent Evaluator

oversight, the IOUs worked collaboratively with stakeholders to address the

uncertainties and challenges of this new program and the CAISO market integration.

The next test of the 2016 DRAM will be the Sellers’ ability to recruit and register

customers, and deliver the contracted resources. SCE is looking forward to working with the

Sellers through Rule 24 processes and facilitating the success of the DRAM Pilot.

If the DRAM program is to continue beyond the Pilot period, the Commission, the IOUs

and the stakeholders will have to work on the DRAM design in 2016, and receive timely

Commission approval by early 2017. In order to meet RA program timelines and enable MW

quantities procured to count toward the year-ahead RA compliance showing, the IOUs would

need to launch the 2018 DRAM solicitation in early 2017. This would allow sufficient time to

run the solicitation, submit the contracts for Commission review, obtain RA credit for the

contracts, allocate the MW to LSEs, and submit timely year-ahead RA compliance showings.

Appendix B

Status of CPP Integration

B-1

Critical Peak Pricing (CPP) is an overlay on existing time-of-use (TOU) rates. CPP charges higher

prices for consumption of electricity during peak hours on selected days, referred to as CPP event days.

CPP provides discounted demand charges or discounted energy rates during non-event periods during

summer months, depending on the customer’s rate schedule. CPP event days occur from 2 PM to 6 PM and

are dispatched twelve times per year. Customers who sign up for notifications receive a CPP event notice

the day before an event. Since 2009, CPP has been the default rate option for business customers above 200

kW demand. CPP is available to all customers currently on a TOU rate.

Due to a variety of issues related to cost, CAISO requirements, and upcoming program changes,

SCE does not recommend integrating CPP into the CAISO markets at this time. SCE’s current focus for

CPP is to successfully default small business customers onto CPP, which will affect approximately 550,000

customers. This is a major effort in terms of scope, scale, and complexity for both SCE and the affected

customers. In A.14-06-014, as modified by the proposed settlement agreement in that proceeding, SCE

proposed for the default of small business customers to CPP rates to occur in 2018. Adding market

integration to the major changes already taking place at this time would not be ideal.

In evaluating the costs and benefits to CPP market integration, SCE considered the following key

issues:

A. Timing Considerations

In order to integrate CPP into the CAISO market, SCE must make changes to allow for Sub-LAP

dispatch, notification changes, telemetry, and dual enrollment changes. The funding request for these

activities should occur, at the earliest, in the 2018 GRC Phase 2 filing. However, due to the issues discussed

above, SCE’s recommendation is to wait to request these funds until the 2018 CPP default is complete and

there are at least 12 months of CPP event participation data to analyze.

B. Sub-LAP Dispatch

Currently, SCE can only dispatch CPP by default load aggregation point (i.e., territory-wide).

Enabling Sub-LAP-level dispatch would require an update to SCE’s billing system and notification system

B-2

to be able to dispatch and settle event performance by Sub-LAP and by LSE. For the other DR programs

that were integrated, SCE did not run into this issue because they were already able to be dispatched by

subgroups/blocks, and they only required a change in the configuration of the grouping. The costs of such a

major change are unknown at this time.

C. Telemetry

As of September 2015, there were 39.8 MW enrolled in CPP, resulting in a high likelihood that one

or more resource groups will need telemetry if SCE integrated this program into the CAISO market. This is

due to the current CAISO requirement that PDR resources above 10 MW must have telemetry. Even if

telemetry is not needed now, the 2018 default of approximately 550,000 customers to CPP is likely to raise

the available MW and trigger the telemetry requirement. At this time, SCE has not requested funding for

telemetry costs, and it is unreasonable to hold customers responsible for telemetry costs given that

approximately 75 percent of the enrolled customers were defaulted onto this rate option. This percentage

will increase significantly after the 2018 CPP default.

D. Event Notification

Under CPP, customers must be notified by 3:00 PM the day before an event occurs. When the

CAISO awards are released after 2:30 PM, as happened 29 times in 2015, SCE is unable to meet the

notification deadline. When the 2018 CPP default occurs, SCE will have a larger volume of contacts to

notify, so the notices will have to begin significantly earlier than 2:30 PM. For example, Peak Time Rebate

notices are currently sent in batches beginning around 10:00 AM to ensure event notifications are received

by customers the day before the event, due to the high volume. Therefore, in the future, even if SCE

receives a timely award from the CAISO, SCE may still not be able to meet the communication deadline

due to the growth in the program volume. Also, it is not ideal for customers if SCE were to push back the

notification deadline to accommodate the CAISO’s award time, because that gives the customer less time to

plan schedules or operations for the following day’s event. With SCE’s other integrated programs,

associated changes were less disruptive to customers because existing notification processes could

B-3

accommodate the timing of the CAISO market awards. Due to the frequency of CPP notifications, CPP is

not able to easily accommodate afternoon CAISO notifications.

E. Dual Enrollment

For CPP, dual enrollment is allowed with all other existing integrated programs. For example, a

customer may participate in both CPP and BIP. Below is the breakdown of dual-enrolled customers.

Although the population of dual-enrolled customers is only 6 percent of the total enrolled population, they

account for approximately 34 percent of the load reduction during CPP events. The CAISO does not

currently allow the same SA to be in more than one resource registration, which means that CPP cannot be

integrated at a level fully in line with its load reduction potential. Table B-1

Total Number of SAs Enrolled in CPP that Dual-Participate With Other DR Programs, 2015

BIP 40 CBP 14

AP-I 0 SDP 101

AMP 61 Total Dual-Participating SAs 216 Total SAs Enrolled in CPP 3,580

Market integration for CPP should be re-evaluated after the 2018 default of approximately 550,000

customers to CPP has occurred. This will allow SCE to analyze and predict how this substantially increased

population of customers respond to events, as many of the defaulting customers have never before

participated in a DR program.

Appendix C

Complete 2017 DR Portfolio Budget

C-1

Table C-1

2017 Proposed DR Portfolio Budget $ ‘000s

Program

2015‐2016 Annual

Authorized Requested 2017 Change Percentage Decrease

Category 1 ‐ Reliability Programs

Agricultural Pumping Interruptible $ 514 $ 302 $ (211) 41%

Base Interruptible Program $ 802 $ 322 $ (480) 60%

Optional Binding Mandatory Curtailment (OBMC) $ 12 $ 12 $ ‐ N/A

Rotating Outages $ 107 $ 107 $ ‐ N/A

Scheduled Load Reduction (SLR) $ 5 $ 5 $ ‐ N/A

Category 1 Total $ 1,441 $ 749 $ (691) 48%

Category 2 ‐ Price Responsive Programs

Capacity Bidding Program (CBP) $ 220 $ 198 $ (22) 10%

Demand Bidding Program (DBP) $ 494 $ ‐ $ (494) 100%

Summer Discount Plan Program (AC Cycling) $ 21,463 $ 4,507 $ (16,956) 79%

Peak Time Rebates (Save Power Day) $ 1,569 $ 1,723 $ 154 10%

Category 2 Total $ 23,748 $ 6,429 $ (17,318) 73%

Category 3 ‐ Aggregator Managed Portfolio (AMP)

AMP Contracts – Admin $ 700 $ 560 $ (140) 20%

AMP Contracts – Capacity & Energy $ 23,950 $ 16,765 $ (7,185) 30%

Demand Response Auction Mechanism $ ‐ N/A

Category 3 Total $ 24,650 $ 17,325 $ (7,325) 30%

Category 4 ‐ Emerging & Enabling Technologies

Auto‐DR Technology Incentives $ 14,358 $ 7,158 $ (7,200) 50%

DR Emerging Markets & Technologies $ 2,922 $ 2,922 $ ‐ N/A

Category 4 Total $ 17,280 $ 10,080 $ (7,200) 42%

Category 5 Pilots

Smart Charging Pilot $ ‐ $ ‐ N/A

Workplace Charging Pilot $ ‐ $ ‐ N/A

Over Generation Pilot N/A $ 1,000 $ 1,000 Increase of $1,000

Category 5 Total $ ‐ $ 1,000 $ 1,000 Increase of $1,000

Category 6 Evaluation, Measurement & Verification

DRMEC $ 2,134 $ 2,134 $ ‐ N/A

DR Research $ 400 $ 400 $ ‐ N/A

Category 6 Total $ 2,534 $ 2,534 $ ‐ N/A

Category 7 Marketing, Education and Outreach

Statewide Marketing $ ‐ $ ‐ $ ‐ N/A

Local Marketing – Circuit Savers $ 333 $ ‐ $ (333) 100%

Local Marketing – DBP $ 91 $ ‐ $ (91) 100%

Local Marketing – SDP $ 1,950 $ 1,293 $ (657) 34%

C-2

Local Marketing – PTR $ 3,333 $ 297 $ (3,036) 91%

Local Marketing – Auto‐DR $ 73 $ 73 N/A

Local Marketing – PLS $ 83 $ ‐ $ (83) 100%

Category 7 Total $ 5,864 $ 1,663 $ (4,201) 72%

Category 8 DR System Support Activities

DR Systems $ 5,966 $ 4,500 $ (1,466) 25%

Category 8 Total $ 5,966 $ 4,500 $ (1,466) 25%

Category 9 Integrated Programs and Activities

IDSM $ ‐ $ ‐ $ ‐ N/A

Category 9 Total $ ‐ $ ‐ $ ‐ N/A

Category 10 Special Projects

Permanent Load Shifting (PLS) $ 4,666 $ ‐ $ (4,666) 100%

Category 10 Total $ 4,666 $ ‐ $ (4,666) 100%

Category 11 Dynamic Pricing

Real‐Time Pricing (RTP) $ ‐ $ ‐ $ ‐ N/A

Critical Peak Pricing (CPP) $ ‐ $ ‐ $ ‐ N/A

Category 11 Total $ ‐ $ ‐ $ ‐ N/A

TOTAL $ 86,153 $ 44,283 $ (41,870) 49%


STATE OF CALIFORNIA


R.13-09-011


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) PROPOSAL FOR APPROVAL OF ITS 2017 DEMAND RESPONSE PROGRAM AND BRIDGE FUNDING AUTHORIZATION on all parties identified on the attached service list(s) R.13-09-011. 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 hand or by overnight courier to the offices of the Commissioner(s) or other addressee(s).

ALJ Kelly A. Hymes CPUC 505 Van Ness Avenue San Francisco, CA 94102

Executed on February 1, 2016, at Rosemead, California.

/s/ Edith Leon____________ Edith Leon Legal Administrative Assistant SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770

PROCEEDING: R1309011 - CPUC - OIR TO ENHANC FILER: CPUC LIST NAME: LIST LAST CHANGED: FEBRUARY 1, 2016

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DAVID P. LOWREY DANIEL W. DOUGLASS DIRECTOR, REGULATORY STRATEGY COUNSEL COMVERGE, INC. DOUGLASS & LIDDELL 8105 CALMOSA AVENUE 4766 PARK GRANADA, STE. 209 WHITTIER, CA 90602 CALABASAS, CA 91302 FOR: COMVERGE, INC. FOR: NEST LABS, INC., WESTERN POWER TRADING FORUM

ANGELICA MORALES DON C. LIDDELL ATTORNEY ATTORNEY SOUTHERN CALIFORNIA EDISON COMPANY DOUGLASS & LIDDELL 2244 WALNUT GROVE AVENUE / PO BOX 800 2928 2ND AVENUE ROSEMEAD, CA 91770 SAN DIEGO, CA 92103 FOR: SOUTHERN CALIFORNIA EDISON COMPANY FOR: CALIFORNIA ENERGY STORAGE ALLIANCE (CESA)

SACHU CONSTANTINE THOMAS R. BRILL DIR. OF POLICY SR COUNSEL & DIRECTOR CENTER FOR SUSTAINABLE ENERGY SAN DIEGO GAS & ELECTRIC COMPANY 9325 SKY PARK COURT, SUITE 100 8330 CENTURTY PARK CT., CP32E SAN DIEGO, CA 92123 SAN DIEGO, CA 92123-1530 FOR: CALIFORNIA CENTER FOR SUSTAINABLE FOR: SAN DIEGO GAS & ELECTRIC COMPANY ENERGY (CCSE)

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PIERSON STOECKLEIN MEGAN M. MYERS ETAGEN, INC. ATTORNEY 186 CONSTITUTION DRIVE LAW OFFICES OF SARA STECK MYERS MENLO PARK, CA 94109 122 - 28TH AVENUE FOR: ETAGEN, INC. SAN FRANCISCO, CA 94121 FOR: CENTER FOR ENERGY EFFICIENCY AND RENEWABLE TECHNOLOGIES (CEERT)

SARA STECK MYERS MATTHEW BARMACK ATTORNEY AT LAW DIR. - MARKET & REGULATORY ANALYSIS 122 28TH AVENUE CALPINE CORPORATION SAN FRANCISCO, CA 94121 4160 DUBLIN BLVD., SUITE 100 FOR: JOINT DR PARTIES (ENERNOC, INC.; DUBLIN, CA 94568 JOHNSON CONTROLS, INC.) FOR: CALPINE CORPORATION

BETH REID GERALD LAHR OLIVINE, INC. ENERGY PROGRAMS MGR. 2010 CROW CANYON PLACE, STE. 100 ASSOCIATION OF BAY AREA GOVERNMENTS SAN RAMON, CA 94583 101 8TH ST. FOR: OLIVINE, INC OAKLAND, CA 94607 FOR: ASSOCIATION OF BAY AREA GOVERNMENTS (ABAG)

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SYNAPSE ENERGY ECONOMICS, INC. IPKEYS POWER PARTNERS, LLC 485 MASSACHUSETTS AVE., SUITE 2 12 CHRISTOPHER WAY, SUITE 301 CAMBRIDGE, MA 02139 EATONTOWN, NJ 07724

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CLARK E. PIERCE MICHAEL PANFIL LANDIS & GYR ENVIRONMENTAL DEFENSE FUND 246 WINDING WAY 257 PARK AVENUE SOUTH, FLOOR 16 STRATFORD, NJ 08084 NEW YORK, NY 10010

MARIE PIENIAZEK GLEN E. SMITH 1328 BOZENKILL ROAD PRESIDENT AND CEO DELANSON, NY 12053 ENERGY CURTAILMENT SPECIALISTS, INC. 4455 GENESEE ST., STE.101 BUFFALO, NY 14225-1955

ALICIA R. PETERSEN MONICA S. IINO RHOADS & SINON LLP RHOADS & SINON LLP ONE SOUTH MARKET SQUARE, PO BOX 1146 M&T BUILDING HARRISBURG, PA 17108 ONE SOUTH MARKET SQUARE, PO BOX 1146 HARRISBURG, PA 17108

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KEVIN SIMONSEN KEN SKINNER ENERGY MANAGEMENT SERVICES VICE PRESIDENT, COO 20 KRISTIN CT. INTEGRAL ANALYTICS, INC SANTA ROSA BEACH, FL 32459 312 WALNUT STREET, SUITE 1600 FOR: ENERGY USERS FORUM CINCINNATI, OH 45202

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ANDREW CAMPBELL DANIEL M. VIOLETTE TENDRIL SUMMIT BLUE CONSULTING 2580 55TH ST.,STE. 100 1375 WALNUT ST., STE. 200



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PAUL BECK YVONNE MEJIA ELITE ENERGY SYSTEMS SOUTHERN CALIFORNIA GAS COMPANY 20 INDUSTRIAL PARKWAY 555 W. FIFTH STREET, GT14D6 CARSON CITY, NV 89706 LOS ANGELES, CA 90013

JOYCE LEUNG MARK S. MARTINEZ SOUTHERN CALIFORNIA EDISON COMPANY SOUTHERN CALIFORNIA EDISON 6060 J IRWINDALE AVE. 6060 IRWINDALE AVE., SUITE J IRWINDALE, CA 91702 IRWINDALE, CA 91702

ANDREA HORWATT CARL SILSBEE SOUTHERN CALIFORNIA EDISON COMPANY SOUTHERN CALIFORNIA EDISON 2244 WALNUT GROVE AVENUE GO1, RP&A ROSEMEAD, CA 91770 2244 WALNUT GROVE AVENUE ROSEMEAD, CA 91770

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JANET COMBS, ESQ. JENNIFER M. TSAO SHIGEKAWA SR. ATTORNEY SOUTHERN CALIFORNIA EDISON COMPANY SOUTHERN CALIFORNIA EDISON COMPANY 2244 WALNUT GROVE AVENUE 2244 WALNUT GROVE AVENUE ROSEMEAD, CA 91770 ROSEMEAD, CA 91770

KA-WING MAGGIE POON NATHANAEL GONZALEZ GO1, QUAD 2B SOUTHERN CALIFORNIA EDISON COMPANY 2244 WALNUT GROVE AVE. 8631 RUSH STREET ROSEMEAD, CA 91770 ROSEMEAD, CA 91770

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STEVEN C. NELSON KIM KIERNER ATTORNEY 4475 TIVOLI ST. SAN DIEGO GAS & ELECTRIC COMPANY SAN DIEGO, CA 92107 488 8TH AVENUE, 9TH FLOOR SAN DIEGO, CA 92101-7123

DONALD KELLY ANNLYN M. FAUSTINO EXE. DIR. REGULATORY CASE ANALYST & SUPPORT UTILITY CONSUMERS' ACTION NETWORK SDG&E/SCGC 3405 KENYON STREET, SUITE 401 8330 CENTURY PARK COURT, CP31E SAN DIEGO, CA 92110 SAN DIEGO, CA 92123

DAVID BARKER KATHRYN SMITH SAN DIEGO GAS & ELECTRIC COMPANY SAN DIEGO GAS AND ELECTRIC COMPANY 8306 CENTURY PARK COURT 8306 CENTURY PARK COURT SAN DIEGO, CA 92123 SAN DIEGO, CA 92123

LISA DAVIDSON LIYING WANG SAN DIEGO GAS AND ELECTRIC COMPANY DEMAND / RESPONSE MANAGER 8330 CENTURY PARK COURT, CP32A SAN DIEGO GAS & ELETRIC COMPANY SAN DIEGO, CA 92123 8326 CENTURY PARK CT. SAN DIEGO, CA 92123

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THOMAS C. SAILE WILLIAM FULLER SAN DIEGO GAS & ELECTRIC COMPANY CALIF. REGULATORY AFFAIRS 8315 CENTURY PARK COURT, CP21D SAN DIEGO GAS & ELECTRIC COMPANY SAN DIEGO, CA 92123-1548 8330 CENTURY PARK COURT, 32CH SAN DIEGO, CA 92123-1548

DAVE HANNA PAUL MARCONI ITRON INC BEAR VALLEY ELECTRIC SERVICE 11236 EL CAMINO REAL 42020 GARSTIN DRIVE, PO BOX 1547 SAN DEIGO, CA 92130-2650 BIG BEAR LAKE, CA 92315

LOGAN OLDS DOUGLAS A. AMES VWRA ATTORNEY AT LAW 15776 MAIN STREET, STE. 3 TRANSPHASE SYSTEMS, INC. HESPERIA, CA 92345 4971 LOS PATOS AVENUE FOR: VICTOR VALLEY WASTEWATER HUNTINGTON BEACH, CA 92649 RECLAMATION AUTHORITY

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PAUL KERKORIAN ADAM SIMPSON REP. FOUNDER UTILITY COST MANAGEMENT LLC ETAGEN, INC. 1100 W. SHAW AVE., STE. 126 186 CONSTITUTION DRIVE FRESNO, CA 93711 MENLO PARK, CA 94025

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TED KO KARI KLOBERDANZ-YU STEM, INC. REGULATORY RELATIONS MANAGER 100 ROLLINS ROAD SEMPRA ENERGY UTILITIES MILLBRAE, CA 94030 601 VAN NESS AVE., STE. 2060 FOR: STEM, INC. SAN FRANCISCO, CA 94102

THERESA MUELLER THOMAS ROBERTS DEPUTY CITY ATTORNEY CALIF PUBLIC UTILITIES COMMISSION CITY AND COUNTY OF SAN FRANCISCO ENERGY SAFETY & INFRASTRUCTURE BRANCH CITY HALL, ROOM 234 ROOM 4108 SAN FRANCISCO, CA 94102 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214

ERIC BORDEN THOMAS LONG ENERGY POLICY ANALYST LEGAL DIR. THE UTILITY REFORM NETWORK THE UTILITY REFORM NETWORK 785 MARKET STREET, STE. 1400 785 MARKET ST., STE. 1400 SAN FRANCISCO, CA 94103 SAN FRANCISCO, CA 94103

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SHERIDAN J. PAUKER, ESQ. STEVEN R. HAERTLE REGULATORY COUNSEL PACIFIC GAS AND ELECTRIC COMPANY WILSON SONSINI GOODRICH & ROSATI 77 BEALE STREET, MC B9A ONE MARKET PLAZA, SPEAR TOWER, STE 3300 SAN FRANCISCO, CA 94105 SAN FRANCISCO, CA 94105

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RICK COUNIHAN BONNIE DATTA NEST LABS, INC. SIEMENS USA 3400 HILLVIEW AVENUE 4000 E. THIRD AVENUE PALO ALTO, CA 94304 FOSTER CITY, CA 94404

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JANIE PAGE JENNIFER POTTER LAWRENCE BERKELEY NATIONAL LABORATORY LAWRENCE BERKELEY NATIONAL LABORATORY



ONE CYCLONE ROAD, MS 90-1121 ONE CYCLOTRON ROAD, MS 90R400 BERKELEY, CA 94720 BERKELEY, CA 94720

KRISTINA S. H. LACOMMARE ANDREW G. CAMPBELL LAWRENCE BERKELEY NATIONAL LABORATORY EXEC.DIR.- ENERGY INSTITUTE AT HAAS ONE CYCLOTRON ROAD, MS 90R4000 UNIVERSITY OF CALIFORNIA, BERKELEY BERKELEY, CA 94720-5104 2547 CHANNING WAY BERKELEY, CA 94720-5180

PHILLIP MULLER JOHN NIMMONS PRESIDENT COUNSEL SCD ENERGY SOLUTIONS JOHN NIMMONS & ASSOCIATES, INC. 436 NOVA ALBION WAY 175 ELINOR AVE., STE. G SAN RAFAEL, CA 94903 MILL VALLEY, CA 94941 FOR: SIERRA CLUB

JAMES BOOTHE JASON SIMON THE ENERGY COALITION DIR - POLICY STRATEGY 9 REBELO LANE ENPHASE ENERGY NOVATO, CA 94947 1420 N. MCDOWELL BLVD. PETALUMA, CA 94954

DAVID WEIDBERG MAHLON ALDRIDGE JOHNSON CONTROLS, INC. VP - STRATEGIC DEVELOPMENT 901 CAMPISI WAY, STE. 260 ECOLOGY ACTION CAMPBELL, CA 95008 877 CEDAR STREET, STE. 240 SANTA CRUZ, CA 95060-3938

L. JAN REID C. SUSIE BERLIN COAST ECONOMIC CONSULTING LAW OFFICES OF SUSIE BERLIN 3185 GROSS ROAD 1346 THE ALAMEDA, STE. 7, NO. 141 SANTA CRUZ, CA 95062 SAN JOSE, CA 95126

JEFF SHIELDS ED FRANCIOSA UTILITY SYSTEMS DIRECTOR MODESTO IRRIGATION DISTRICT SOUTH SAN JOAQUIN IRRIGATION DISTRICT 1231 11TH STREET 11011 E. HWY 120 MODESTO, CA 95354 MANTECA, CA 95336

GREG SALYER ROGER VAN HOY MODESTO IRRIGATION DISTRICT MODESTO IRRIGATION DISTRICT 1231 11TH STREET 1231 11TH STREET MODESTO, CA 95354 MODESTO, CA 95354

JEFFREY NAHIGIAN DOUGLAS M. GRANDY, P.E. JBS ENERGY, INC. CALIFORNIA ONSITE GENERATION 311 D STREET 1220 MACAULAY CIRCLE WEST SACRAMENTO, CA 95605 CARMICHAEL, CA 95608

RICHARD MCCANN JACQUELINE M. DEROSA M.CUBED DIRECTOR OF REGULATORY AFFAIRS - CA 2655 PORTAGE BAY ROAD, SUITE 3 CUSTOMIZED ENERGY SOLUTIONS DAVIS, CA 95616 101 PARKSHORE DRIVE SUITE 100



FOLSOM, CA 95630

JOHN C. ANDERS KARL MEEUSEN, PH.D SR. COUNSEL CALIFORNIA INDEPENDENT SYSTEM OPERATOR CALIFORNIA INDEPENDENT SYSTEMS OPERATOR 250 OUTCROPPING WAY 250 OUTCROPPING WAY FOLSOM, CA 95630 FOLSOM, CA 95630

KEITH G. JOHNSON SAEED FARROKHPAY MANAGER, INFRASTRUCTURE POLICY FEDERAL ENERGY REGULATORY COMMISSION CALIFORNIA INDEPENDENT SYSTEM OPERATOR 1835 IRON POINT RD., STE. 160 250 OUTCROPPING WAY FOLSOM, CA 95630-8771 FOLSOM, CA 95630

CYNTHIA HINMAN JOHN GOODIN CALIFORNIA ISO CALIFORNIA ISO 250 OUTCROPPING WAY 250 OUTCROPPING WAY FOLSOM, CA 95630-8773 FOLSOM, CA 95630-8773

LEGAL AND REGULATORY DEPARTMENT BRIAN THEAKER CALIFORNIA ISO NRG ENERGY 250 OUTCROPPING WAY 3161 KEN DEREK LANE FOLSOM, CA 95630-8773 PLACERVILLE, CA 95667

LON W. HOUSE, PH.D KAREN HERTER ASSN. OF CALIFORNIA WATER AGENCIES 2201 FRANCISCO DRIVE, STE. 140-120 4901 FLYING C RD. EL DORADO HILLS, CA 95762 CAMERON PARK, CA 95682

CAROLYN M. KEHREIN DAN GRIFFITHS ENERGY MANAGEMENT SERVICES ATTORNEY 2602 CELEBRATION WAY BRAUN BLAISING MCLAUGHLIN & SMITH, P.C. WOODLAND, CA 95776 915 L STREET, SUITE 1480 SACRAMENTO, CA 95814

DAVID HUNGERFORD DELANEY HUNTER CALIFORNIA ENERGY COMMISSION MANAGING PARTNER DEMAND ANALYSIS OFFICE GONZALEZ, QUINTANA & HUNTER, LLC 1516 NINTH STREET, MS-22 915 L. ST., STE. 1480 SACRAMENTO, CA 95814 SACRAMENTO, CA 95814 FOR: BLOOM ENERGY COPRORATION

DOROTHY ROTHROCK KEVIN WOODRUFF VP - GOVERNMENT RELATIONS WOODRUFF EXPERT SERVICES CALIFORNIA MANUFACTURERS & TECHNO. ASSN. 1127 - 11TH STREET, SUITE 514 1115 11TH STREET SACRAMENTO, CA 95814 SACRAMENTO, CA 95814

MARGARET SHERIDAN STEVEN KELLY CALIFORNIA ENERGY COMMISSION POLICY DIR. DEMAND ANALYSIS OFFICE INDEPENDENT ENERGY PRODUCERS ASSCIATION 1516 NINTH STREET, MS-22 1215 K STREET, STE. 900 SACRAMENTO, CA 95814 SACRAMENTO, CA 95814



TANYA DERIVI RONALD LIEBERT SO. CALIFORNIA PUBLIC POWER AUTHORITY ATTORNEY AT LAW 915 L STREET, STE. 1410 ELLISON SCHNEIDER & HARRIS LLP SACRAMENTO, CA 95814 2600 CAPITOL AVENUE, STE. 400 SACRAMENTO, CA 95816

ANDREW B. BROWN LYNN HAUG ATTORNEY AT LAW ELLISON, SCHNEIDER & HARRIS L.L.P. ELLISON SCHNEIDER & HARRIS, LLP 2600 CAPITOL AVENUE, SUITE 400 2600 CAPITAL AVENUE, SUITE 400 SACRAMENTO, CA 95816-5931 SACRAMENTO, CA 95816-5905

DAN AUSTIN VIKKI WOOD SR. DEMAND SIDE SPECIALIST SACRAMENTO MUNICIPAL UTILITY DISTRICT SACRAMENTO MUNICIPAL UTILITIY DISTRICT 6301 S STREET, MS A204 6301 S. ST., MS A353 SACRAMENTO, CA 95817-1899 SACRAMENTO, CA 95817

KAREN LINDH ANN L. TROWBRIDGE CALIFORNIA ONSITE GENERATION ATTORNEY 7909 WALERGA ROAD, NO. 112, PMB 119 DAY CARTER & MURPHY LLP ANTELOPE, CA 95843 3620 AMERICAN RIVER DR., STE. 205 SACRAMENTO, CA 95864 FOR: CALIFORNIA CLEAN DISTRIBUTED GENERATION COALITION (CCDC)

ROGER LEVY JACK ELLIS LEVY AND ASSOCIATES 1425 ALPINE WAY / PO BOX 6600 2805 HUNTINGTON ROAD TAHOE CITY, CA 96145-6600 SACRAMENTO, CA 95864

MIKE CADE MARY WIENCKE ALCANTAR & KAHL PACIFICORP 1300 SW 5TH AVENUE, STE. 1750 825 N. E. MULTNOMAH, SUITE 1800 PORTLAND, OR 97201 PORTLAND, OR 97232

JENNIFER HOLMES EVERITT LONG ENERGY MARKET INNOVATIONS INC. DIRECTOR OF INTELLECTUAL PROPERTY 83 COLUMBIA STREET, SUITE 400 ECOBEE, INC. SEATTLE, WA 98104-1416 477 RICHMOND ST. WEST TORONTO, ON M5V 3E7 CANADA FOR: ECOBEE, INC.

ANDY GASSNER SENIOR ANALYST ENBALA POWER NETWORKS 930 WEST 1ST ST., NO. 211 NORTH VANCOUVER, BC V7P 3N4 CANADA



CLARE LAUFENBER GALLARDO DAVID PECK STRATEGIC TRANSMISSION INVESTMNT PROGRAM CALIFORNIA PUBLIC UTILITIES COMMISSION CALIFORNIA ENERGY COMMISSION EMAIL ONLY EMAIL ONLY EMAIL ONLY, CA 00000 EMAIL ONLY, CA 00000

DONALD J. BROOKS DORRIS CHOW CPUC - ENERGY DIV. REGULATORY ANALYST - ENERGY DIV. EMAIL ONLY CALIFORNIA PUBLIC UTILITIES COMMISSION EMAIL ONLY, CA 00000 EMAIL ONLY EMAIL ONLY, CA 00000

JAIME ROSE GANNON JOHN ERICKSON CPUC - ENERGY CPUC - ENERGY EMAIL ONLY EMAIL ONLY EMAIL ONLY, CA 00000 EMAIL ONLY, CA 00000

LEGAL DIVISION LEUWAM TESFAI CPUC CALIFORNIA PUBLIC UTILITIES COMMISSION EMAIL ONLY ENERGY EMAIL ONLY, CA 00000 EMAIL ONLY EMAIL ONLY, CA 00000

MARYAM MOZAFARI NATHAN BARCIC CALIFORNIA PUBLIC UTILITIES COMMISSION CPUC EMAIL ONLY EMAIL ONLY EMAIL ONLY, CA 00000 EMAIL ONLY, CA 00000

NICOLAS L. CHASET NOEL CRISOSTOMO SPECIAL ADVISOR DISTRIBUTED ENERGY RES. PUBLIC UTILITIES REGULATORY ANALYST CPUC CPUC - ENERGY DIV. OFFICE OF GOV. ED. G. BROWN, JR. EMAIL ONLY EMAIL ONLY EMAIL ONLY, CA 00000 EMAIL ONLY, CA 00000

RACHEL MCMAHON WERNER BLUMER CPUC CPUC - ENERGY EMAIL ONLY EMAIL ONLY EMAIL ONLY, CA 00000 EMAIL ONLY, CA 00000

XIAN MING LI BRUCE KANESHIRO ORA - ELECTRICITY PRICING CALIF PUBLIC UTILITIES COMMISSION CALIFORNIA PUBLIC UTILITIES COMMISSION DEMAND RESPONSE, CUSTOMER GENERATION, ANEMAIL ONLY AREA 4-A EMAIL ONLY, CA 00000 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214

CANDACE MOREY CHRISTOPHER CLAY CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION LEGAL DIVISION LEGAL DIVISION ROOM 5031 ROOM 4300

State Service



505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214 FOR: ORA

DIANA L. LEE ELIZABETH DORMAN CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION LEGAL DIVISION LEGAL DIVISION ROOM 4107 ROOM 4300 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

JEAN A. LAMMING JOE COMO CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION DEMAND RESPONSE, CUSTOMER GENERATION, AN ORA - ADMINISTRATIVE BRANCH AREA 4-A ROOM 4201 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

JOHN D. ERICKSON KE HAO OUYANG CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION INFRASTRUCTURE PLANNING AND PERMITTING B UTILITY & PAYPHONE ENFORCEMENT BRANCH AREA 4-A AREA 2-E 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

KELLY A. HYMES MARY CLAIRE EVANS CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION DIVISION OF ADMINISTRATIVE LAW JUDGES EXECUTIVE DIRECTOR ROOM 5111 ROOM 5223 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

MATTHEW TISDALE NATALIE GUISHAR CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION COMMISSIONER FLORIO DEMAND RESPONSE, CUSTOMER GENERATION, ANROOM 5202 AREA 4-A 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

PAMELA NATALONI PAULA GRUENDLING CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION LEGAL DIVISION ENERGY EFFICIENCY BRANCH ROOM 5124 AREA 4-A 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

RACHEL MCMAHON RADU CIUPAGEA CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION DEMAND RESPONSE, CUSTOMER GENERATION, AN ELECTRICITY PLANNING & POLICY BRANCH AREA ROOM 4104 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

REBECCA TSAI-WEI LEE ROSANNE O'HARA



CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION POLICY & PLANNING DIVISION ELECTRICITY PLANNING & POLICY BRANCH ROOM 1250 AREA 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

SARAH R. THOMAS SIMONE BRANT CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION LEGAL DIVISION PROCUREMENT STRATEGY AND OVERSIGHT BRANCROOM 5033 AREA 4-A 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

SUDHEER GOKHALE VALERIE KAO CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION ELECTRICITY PRICING AND CUSTOMER PROGRAM TRANSPORTATION ENFORCEMENT BRANCH ROOM 4102 AREA 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

STEVE GHADIRI, P.E. ASSOCIATE ELECTRICAL ENGINEER CALIFORNIA ENERGY COMMISSION 1516 9TH STREET, MS-43 SACRAMENTO, CA 95814

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