BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF … · 2017. 9. 8. · (MEC) price forecast developed using its “PLEXOS” production simulation model, which includes all

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE

STATE OF CALIFORNIA

Application of Southern California Edison Company (U 338-E) for Approval of its 2016 Rate Design Window Proposals.

Application No. 16-09-003 (Filed September 1, 2016)

SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E) OPENING BRIEF

FADIA R. KHOURY RUSSELL A. ARCHER

Attorneys for SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-2865 Facsimile: (626) 302-3990 E-mail: [email protected]

Dated: September 8, 2017


TABLE OF CONTENTS

Section Page

-i-

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

II. TIME-OF-USE ................................................................................................................................2

A. Marginal Costs .....................................................................................................................2

1. 2024 is the Appropriate Reference Year ..................................................................2

2. Generation Energy ...................................................................................................3

3. Generation Capacity .................................................................................................4

4. Distribution ..............................................................................................................6

5. Transmission ............................................................................................................8

B. TOU Periods (On, Mid, Off, Super Off) ............................................................................10

C. Day Type Differentiation (Weekday/Weekend) ................................................................13

D. Seasonal Definitions ..........................................................................................................13

E. TOU Period Grandfathering ..............................................................................................15

F. Other Mitigation Measures ................................................................................................16

G. Implementation ..................................................................................................................16

III. CRITICAL PEAK PRICING .........................................................................................................17

IV. REAL-TIME PRICING (RTP) ......................................................................................................17

V. MARKETING, EDUCATION, AND OUTREACH (ME&O) .....................................................18

VI. DISTRIBUTED ENERGY RESOURCES ACTION PLAN ........................................................18

VII. OPTION R CAP ............................................................................................................................19

VIII. CONCLUSION ..............................................................................................................................20


TABLE OF AUTHORITIES

Page

-ii-

CPUC Decisions D.17-08-030 ....................................................................................................................................... passim D.17-01-006 ....................................................................................................................................... passim D.14-12-048 ...............................................................................................................................................19 D.91-05-029 ...............................................................................................................................................19 D.88-12-083 ...............................................................................................................................................19

CPUC Rules of Practice and Procedure 13.11.............................................................................................................................................................1

-1-


STATE OF CALIFORNIA


Application No. 16-09-003 (Filed September 1, 2016)


I.

INTRODUCTION

Pursuant to California Public Utilities Commission (CPUC or Commission) Rule of

Practice and Procedure 13.11 and the March 21, 2017 Scoping Memo of Assigned

Commissioner Michael Picker (Scoping Memo), Southern California Edison Company (SCE)

respectfully submits this Opening Brief in support of its 2016 Rate Design Window (RDW)

Application (A.) 16-09-003.

California’s current time-of-use (TOU) periods have existed essentially unchanged for

three decades. During that period, California’s electric grid and the ways that customers use

electricity have dramatically changed. What was once a one-way grid with large central station

generation sources serving customers is now a dynamic, multifaceted network of millions of

electricity users and hundreds of thousands of central station and distributed generation (DG)

electricity producers. This fundamental shift has contributed to a total misalignment between the

existing TOU periods and the underlying economics of today’s electricity costs and grid needs.

This phenomenon – long-since identified by the California Independent System Operator

(CAISO), this Commission, the California Energy Commission (CEC), the Investor-Owned

Utilities (IOUs), other energy market participants, consumer interest groups, and academics – is

undisputed. The peak TOU period must be set materially later in the day to send appropriate

-2-

price signals to customers and ameliorate stress on the grid. The only disputes on this issue here

are around the margins (e.g., how late in the day), and about what mitigation options will be

given to certain customers who may be negatively impacted by transitioning to updated TOU

periods (e.g., grandfathering for solar photovoltaic (PV) generators).

SCE respectfully submits that as to the former, its comprehensive showing in this

proceeding identified the most appropriate TOU periods, day types (i.e., weekend/weekday

periods), and seasonal definitions when objectively considering underlying marginal costs (for

energy, capacity and distribution costs), grid needs, and customer acceptance.1 As to the latter,

the Commission has already adopted significant mitigation measures for solar PV customers on a

statewide basis,2 and it would be inappropriate to adopt additional ones here. For additional

mitigation-type measures, Administrative Law Judge (ALJ) Roscow has appropriately ruled

those out of scope,3 and they will be examined in SCE’s open 2018 General Rate Case (GRC)

Phase 2 proceeding (A.17-06-030).

II.

TIME-OF-USE

A. Marginal Costs

1. 2024 is the Appropriate Reference Year

The Commission has determined that new TOU periods should be maintained for at least

six years.4 As such, the analysis underlying the determination of new TOU periods must be

sufficiently forward-looking so as to allow customers to make economic long-term investment

decisions and provide appropriate stability. Following this guidance, SCE proposed using 2024

1 SCE also demonstrated that its TOU proposals are appropriate even when including the time-variant

component of transmission costs. See Exhibit SCE-03, p. 23. 2 D.17-01-006, p. 74 (TOU OIR Decision) (Findings of Fact Nos. 31 and 32). 3 See August 9, 2017 Administrative Law Judge’s Ruling on Motion to Strike, p. 9. 4 D.17-01-006, p. 73 (Finding of Fact No. 26).

-3-

expected grid conditions and marginal costs, but also included analysis that used 2021 data.

First, 2024 is the appropriate “test” year, as the conditions that have led to the current mismatch

between the existing TOU periods and current economics, specifically the impact on IOU load

profiles due to the statutory mandates of increasing Renewables Portfolio Standard (RPS)

penetration and DG, will only intensify going forward.5 Second, 2024 is also five years after

SCE’s proposed implementation date for the updated TOU periods (now, February 2019),6 which

is consistent with Commission guidance in the TOU OIR Decision.7 Third, as SCE witness

Russell Garwacki testified during evidentiary hearings, the RPS mandates may be accelerated

under Senate Bill (SB) 100 which, if adopted, will only exacerbate and accelerate the “duck

curve” impacts on IOU cost and net load profiles.8 Fourth, the differences in the marginal cost

studies for 2021 and 2024 for the purposes of TOU-period determination are not significant,9 and

both indicate the reasonableness of SCE’s proposed periods.10 For all these reasons, the

Commission should adopt 2024 as the appropriate year for analyzing the data underlying SCE’s

proposed TOU periods.

2. Generation Energy

SCE’s direct testimony demonstrated that it used a wholesale marginal energy cost

(MEC) price forecast developed using its “PLEXOS” production simulation model, which

includes all relevant inputs when determining future marginal energy prices.11 Those results,

which no party contested, result in 2024 forecast MECs as shown in Exhibit SCE-01, Figure III-

5 Exhibit SCE-01, p. 15. 6 Exhibit SCE-03, p. 71. 7 D.17-01-006 provided guidance that TOU periods should be set based on data “at least” three years

after the base TOU periods will go into effect. D.17-01-006, p. 7 (Guiding Principle No. 4). 8 SCE, Garwacki, Evidentiary Hearing Tr. 1:85. 9 Exhibit SCE-01, p. 15, FN 30. 10 Exhibit SCE-03, pp. 42-43 (including Figures III-23 and III-24). 11 Exhibit SCE-01, pp. 17-18.

-4-

3.12 These MECs were incorporated in SCE’s overall cost analysis supporting its proposed TOU

periods.13

3. Generation Capacity

In determining marginal generation capacity costs (MGCCs), SCE used the net14 long-run

value of capacity of a new combustion turbine (CT) generating unit as determined in the CEC’s

March 2015 report.15 This resulted in a MGCC value of $147.26/kW-year. CTs have

historically been the generator to provide marginal system capacity, and as the need for flexible

“ramping” resources due to increasing intermittent RPS resources increases, will likely continue

to be for the foreseeable future.16

The Solar Energy Industries Association (SEIA) challenged SCE’s MGCC value,

claiming that SCE has not demonstrated that new CTs will be needed in 2024, and that Pacific

Gas and Electric Company (PG&E) proposes using a lower number in its pending GRC Phase 2

proceeding. SEIA also argued that battery storage technology may become economic in the

future. None of these arguments is availing. First, it is irrelevant that California in the aggregate

currently has excess capacity. The point of a utility-specific marginal cost analysis is to estimate

the cost of a marginal unit to meet a utility-specific loss-of-load expectation (LOLE), should that

unit become necessary in the long-run. Second, PG&E’s estimate of the cost of an existing

combined cycle unit is irrelevant to SCE’s determination of the marginal cost of a new CT unit;17

no party has contested that a CT will be the marginal capacity resource for SCE in 2024.18

Finally, as confirmed by SEIA witness Tom Beach during evidentiary hearings, SEIA’s proposed

12 Exhibit SCE-01, p. 20. 13 Exhibit SCE-01, pp. 44-45 (including Figure III-18). 14 The total cost minus the energy rents. See Exhibit SCE-01, pp. 21-22. 15 Exhibit SCE-01, p. 23. 16 Exhibit SCE-01, p. 22. 17 D.17-01-006 makes clear that TOU periods are to be based on utility-specific marginal costs. D.17-

01-006, p. 7 (Guiding Principle No. 2). 18 SEIA, Beach, Evidentiary Hearing Tr. 2: 140-41.

-5-

alternative MGCC value of $86 kW-year was derived by simply taking SCE’s number plus

PG&E’s number and dividing by two.19

The Commission should reject SEIA’s arbitrary MGCC proposal and instead consider the

careful analysis in the rebuttal testimony of the California Large Energy Consumers Association

and the California Manufacturers Association (CLECA/CMTA). There, CLECA/CMTA

demonstrated that SEIA ignored the fact that SCE is adding local capacity resources, that

existing combined cycle plants are becoming less economic, and that the CAISO has recognized

the need for additional flexible capacity resources after 2019.20 CLECA/CMTA support SCE’s

proposed annualized capacity value,21 which should be adopted.

SEIA also challenges SCE’s proposal to allocate the cost of ramping (“flex”) capacity to

the latter two hours of the ramp, and instead would allocate those costs to four hours (of a three-

hour ramp). First, SEIA’s proposal contradicts CAISO’s definition of the evening ramp as being

three hours, not four.22 Second, SEIA’s proposal could send the wrong incentives for customer

behavior. The first hour of the evening ramp is close to the “belly of the duck;” accordingly,

additional incentives to conserve should not be provided to customers in that hour.23 Similarly,

the second and third hours of the evening ramp are close to the “head of the duck;”24

accordingly, it is appropriate during those hours to provide additional incentives to customers to

conserve.

As SCE noted in rebuttal testimony: “Excluding the [flex] capacity [cost] in the first

hour, and aligning most of the [flex] capacity [cost] closest to the peak, simultaneously achieves

two objective[s]: first, it mitigates the capacity signal in the hour closest to the belly of the duck,

19 SEIA, Beach, Evidentiary Hearing Tr. 2: 139-40. 20 Exhibit CLECA/CMTA-02, pp. 15-17. 21 Exhibit CLECA/CMTA-01, Question and Answer No. 15. 22 Exhibit SCE-03, p. 40, FN 64 (citing to May 1, 2017, CAISO Revised Straw Proposal – Short Term

Solutions” in the FRACMOO2 stakeholder initiative “maintaining the current three-hour ramp evaluation.”).

23 Exhibit SCE-03, p. 40, Figure III-18. 24 Id.

-6-

therefore allowing customers to modify consumption in a manner that raises the belly of the

duck; and, second, it inflates the price signal in the hour closest to the peak hour, therefore

allowing customers to modify consumption in a manner that lowers the head of the duck.”25

Although allocating the flexible capacity costs to three ramping hours instead of two does

not materially impact the determination of TOU periods in this proceeding,26 it is appropriate to

adopt SCE’s proposal to allocate 30 percent of these costs to the second hour, and 70 percent to

the final, third hour of the evening ramp, in order to set the right incentives for customer

electricity consumption behavior.

4. Distribution

SCE incorporated the “peak-load-driven” portion of its forecast distribution costs in a

time-differentiated manner in SCE’s overall cost analysis supporting its proposed TOU periods.27

The time-differentiation was done pursuant to the peak load risk factor (PLRF) methodology,

which essentially mirrors how system planners identify specific capacity constraints on the

distribution grid.28 This led to SCE’s hourly allocation of marginal distribution costs shown on

the “heat map” in Figure III-17 of Exhibit SCE-01.29

SEIA challenged SCE’s PLRF methodology on four grounds: First, SEIA argued that

SCE should not assume that future DG will be sited in the same location as existing DG.

Second, SEIA contended that SCE should have considered load increases from non-DG

distributed energy resources (DERs) as an offset to load reductions from DG resources. Third,

SEIA argued that instead of PLRF, SCE should have used a peak capacity allocation factor

(PCAF) methodology, which weights hours that exceed the distribution planning trigger

25 Exhibit SCE-03, p. 39 (emphasis in original). 26 Exhibit SCE-03, pp. 40-42 (including Figures III-19, III-20, III-21, and III-22). 27 See generally, Exhibit SCE-01, pp. 33-43. 28 Exhibit SCE-01, p. 38. 29 Exhibit SCE-01, p. 43.

-7-

threshold by how much they exceed that threshold. Fourth, SEIA posited that SCE should have

used 2021 PLRFs, not 2024 PLRFs. SCE responds to each of these arguments below.

First, SCE appropriately assumed that future siting of DG will continue to remain

generally consistent with current patterns.30 SCE also believes that the economics and site-

specific drivers of DG penetration will generally hold true during the forecast period.31

Moreover, since 82 percent of SCE’s circuits have existing interconnected DG, the impact is

appropriately disbursed across SCE’s entire service territory.32 Finally, SEIA provides no

alternative methodology to forecast future DG siting.

Second, although other DERs could theoretically partially offset DG load reductions

during the mid-day period, it is unlikely that these resources will have a material effect on the

relative profile of the PLRF results by 2024 given expected levels of penetration of those

resources.33 Accordingly, it was appropriate for SCE to exclude them from the analysis. This

conclusion is further bolstered by the fact that even excluding DG from the analysis – which

constitutes the vast majority of all DERs -- does not materially change the PLRF cost profile.34

Third, using a PCAF methodology is not necessary, as SCE’s existing PLRF

methodology already captures the relative “weight” of the hours that exceed the planning

thresholds.35

Fourth, in light of SEIA’s observation about using 2021 PLRFs, SCE developed 2021

PLRFs and compared them to its previously-developed 2024 PLRFs. That analysis

demonstrated that the resulting heat maps were generally consistent.36 Further, while SEIA is

critical about SCE’s future distribution cost allocations, SEIA’s cost analysis used historical 30 Exhibit SCE-03, p. 31. 31 Exhibit SCE-03, p. 31. 32 Exhibit SCE-03, p. 31, Table III-7. 33 Exhibit SCE-03, p. 33. 34 Exhibit SCE-03, pp. 33-34 (including Figure III-15). Given its impact on grid conditions and the

duck curve phenomenon, SCE maintains it is appropriate to continue to include the impact of DG on system load in determining all marginal costs.

35 Exhibit SCE-03, pp. 34-37 (including Tables III-8 and III-16). 36 Exhibit SCE-03, pp. 37-38 (including Table III-17).

-8-

static 2014/2015 circuit load data,37 and made no attempt to even account for the impacts of

DERs on the system since then, let alone on a future test year.

5. Transmission

SCE’s original TOU analysis did not include the time-differentiation of long-run

transmission costs; SEIA challenged that decision because, in SEIA’s view, including such costs

would shift the “on-peak” period earlier in the day. Transmission costs are Federal Energy

Regulatory Commission (FERC)-jurisdictional, and the CPUC lacks jurisdiction to set rates for

recovery of transmission costs. And although the CPUC has indicated that TOU information

filed or adopted in FERC proceedings should be considered in setting future base CPUC TOU

periods,38 FERC has never adopted the time-differentiation method for transmission costs that

SEIA proposes. For that reason, and for the other reasons detailed below, SEIA’s

recommendation should be rejected.

First, FERC does not use a marginal cost analysis as SEIA asks the CPUC to adopt here.

Instead, FERC uses a coincident peak (CP) embedded cost-allocation framework, which assigns

costs based on revenue requirements across the twelve months of the year to balance seasonal

supply and demand constraints.39 If the CPUC were to allocate transmission costs on a CP basis

(following FERC guidance), it would provide additional support for SCE’s proposed 4-9 p.m.

peak period, not SEIA’s earlier-in-the-day proposal.40

Second, in creating its $87/kW-yr value for “marginal” transmission costs, SEIA

erroneously assumes that all transmission costs are both peak-load driven and time-

differentiated. But the transmission system functions both as a peak-capacity-, load-growth-

driven resource (time-differentiated), and as a grid, or network, resource (non-time-

37 Exhibit SEIA-01, p. 21. 38 D.17-01-006, p. 7. 39 Exhibit SCE-03, p. 19. 40 Exhibit SCE-03, p. 20, Figure III-6.

-9-

differentiated).41 Inappropriately including the non-time-differentiated transmission costs

inflates SEIA’s final marginal transmission cost value by a factor of more than three.42 Indeed,

SCE demonstrated that the vast majority of its future transmission costs are primarily related to

non-peak-capacity-related projects (e.g., renewable energy delivery,43 replacement of

transmission poles, line remediation, reliability, and infrastructure replacement).44

Third, SEIA’s transmission analysis, like its distribution analysis, is backward-looking

instead of forward-looking, which is directly contrary to the Commission’s guidance in the TOU

OIR Decision.45 Such an impermissible backwards look inappropriately excludes DG from the

analysis, which CAISO considers for net load curves and which is a material driver of the duck

curve. When DG is considered, the CEC estimates that peak transmission loads will shift to 6

p.m. by 2024.46

Finally, SEIA’s simplistic analysis ignores the effect of diversity on SCE’s transmission

network. SCE’s transmission facilities peak at markedly-different times, and a complete analysis

must take that into effect.47 SEIA failed to do so.

After correcting for these errors, a more appropriate marginal transmission cost value,

which SCE calculated to be $26/kW-yr, would not materially impact SCE’s proposed TOU

period, as demonstrated in SCE-03, Figures III-9 through III-12.48

41 Exhibit SCE-01, pp. 43-44; Exhibit SCE-3, pp. 13-14. 42 Exhibit SCE-03, p. 13. 43 As confirmed by Mr. Beach, RPS resources are delivered by the transmission system year-round and

the RPS requirement is not a peak-load requirement. See SEIA, Beach, Evidentiary Hearing Tr. 2: 137-38.

44 Exhibit SCE-03, pp. 16-19 (including Figure III-4). 45 Exhibit SCE-03, pp. 20-21. 46 Exhibit SCE-03, p. 21. 47 Exhibit SCE-03, pp. 21-22 (including Figure III-7). 48 Exhibit SCE-03, pp. 23-26.

-10-

B. TOU Periods (On, Mid, Off, Super Off)

SCE’s TOU period proposal is as follows:49

SCE’s proposal is based on marginal costs, as mandated by the TOU OIR Decision,50 is

consistent with recent CAISO guidance for peak period hours,51 and is identical to the

Commission’s adoption last month of San Diego Gas & Electric’s (SDG&E) TOU summer on-

peak period (SDG&E TOU Decision).52

In their respective testimonies, SEIA and ORA propose different TOU periods. But

SEIA’s and ORA’s recommendations are not consistent with the underlying cost data and should

not be accepted.53 SEIA proposes a 2-8 p.m. (six-hour) on-peak period; ORA proposes a 3-8

p.m. on-peak period. Both proposals inappropriately include relatively low-price hours (2-4 p.m.

and 3-4 p.m., respectively), and both inappropriately exclude a relatively high-price hour (8-9

p.m.). As demonstrated in SCE’s rebuttal testimony at Table II-1, for 2024 summer weekdays

49 Exhibit SCE-01, p. 2, Table I-1. 50 D.17-01-006, p. 7 (Guiding Principle No. 2). 51 Exhibit SCE-03, p. 3, FN 8 (citing to CAISO’s May 16, 2017 Market Notice regarding proposed

changes to its business practice manuals). 52 D.17-08-030, p. 25. 53 SCE’s Opening Brief does not address ORA’s customer bill impact argument because, in light of the

August 9, 2017 Administrative Law Judge’s Ruling on Motions to Strike, SCE believes that issue is more appropriately addressed in SCE’s open GRC Phase 2 proceeding. SCE also respectfully directs the Commission to Exhibit SCE-03, pp. 48-49 for additional information on this issue.

-11-

the 3-4 p.m. hour is only 77 percent as expensive as the average weekday hour.54 That cannot

logically be considered a “peak” hour. Unsurprisingly, the 2-3 p.m. hour compares even lower

(68 percent). Correspondingly, the 8-9 p.m. hour is 288 percent as expensive as the average

weekday hour.55 That cannot logically be considered a “non-peak” hour.

Additionally, SEIA’s six-hour on-peak proposal is inconsistent with that same decision.

In the SDG&E TOU Decision, the Commission modified a Proposed Decision that would have

instituted a six-hour on-peak period in favor of a five-hour, 4-9 p.m. on-peak period, holding:

In response to comments we have modified the on-peak period to 4 p.m. to 9 p.m. While the record can support either a 3 p.m. or 4 p.m. start to the on-peak period, for policy reasons we select 4 p.m. This will allow for a five hour on-peak period rather than a six hour on-peak period which will be easier for customers to manage as we transition to default TOU rates.56

SEIA’s and ORA’s advocacy for more “moderate” proposals has no place in defining

base TOU periods. TOU periods should be defined for stability,57 so that customers can make

informed long-term investment choices and not be subject to constantly-changing and confusing

price signals. As SCE noted in its rebuttal testimony, “[i]n a constantly evolving environment, a

moderate shift only increases the likelihood for another change in the near future, which may, in

turn, have a detrimental impact on customers’ investment decisions.”58 This is especially true if

SB 100 is adopted, where the future duck curve will likely materialize sooner than previously

anticipated. The more appropriate way to “moderate” the impact of new TOU periods is through

rate design implementation in SCE’s 2018 GRC Phase 2 proceeding.59

SEIA’s proposal that the Commission not accept SCE’s proposed mandatory winter

super-off-peak (SOP) period in lieu of an optional “Discount Days” program should likewise be

rejected. First, a “Discount Days” program is a rate design issue outside the scope of this 54 Exhibit SCE-03, p. 5, Table II-1. 55 Exhibit SCE-03, p. 5, Table II-1. 56 D.17-08-030, p. 24. 57 D. 17-01-006, p. 46. 58 Exhibit SCE-03, pp. 9-10. 59 See, e.g., California Farm Bureau Federation (CFBF), Mills, Evidentiary Hearing Tr. 2: 121-23.

-12-

proceeding and more appropriately considered in SCE’s pending 2018 GRC Phase 2. Second,

SCE has put forth conclusive evidence demonstrating that costs align with its SOP proposal.60

Because setting base TOU periods is fundamentally a cost-based exercise, the Commission

should adopt an SOP period during the winter. Adopting SOP periods is also consistent with the

recent SDG&E TOU Decision.61

Finally, SEIA’s proposed summer mid-peak periods do not align with marginal costs62

and would likely result in customer confusion. SEIA proposes two mid-peak periods on summer

days (12-2 p.m. and 8-10 p.m.). But 12-2 p.m. is close to the belly of the duck (especially in

May, which SEIA proposes to be a summer month),63 when renewable production is highest, and

not a period when customers should be getting a price signal to reduce consumption. Moreover,

SEIA’s proposal would have customer rates change four times over the course of every summer

day, including two sets of brief two-hour increments. As confirmed by Mr. Beach:

Q: So, just for example, if there was a restaurant subject to these TOU rates, when they open for breakfast at 11:00, they would be on one rate under your proposal. And then when they started serving lunch at noon, they’d be on a different rate. The rate would again change at 2:00 p.m., and then it would change finally for dinner at 8:00 p.m.? Is that consistent with your proposal?

A Yes. That’s basically the way it would work. …64

Such fragmented TOU periods are likely to cause customer confusion and interfere with

customers’ ability or willingness to respond to price signals.65

60 Exhibit SCE-01 at pp. 58-65, 73. 61 D.17-08-030 at pp. 25-26. 62 Exhibit SCE-03, p. 47. 63 See Exhibit SCE-01, p. 3 (showing historic low duck belly value on May 15, 2016); see also SEIA,

Beach, Evidentiary Hearing Tr. 2: 143-144. 64 SEIA, Beach, Evidentiary Hearing Tr. 2: 142. 65 Exhibit SCE-03, p. 47.

-13-

C. Day Type Differentiation (Weekday/Weekend)

As shown above, SCE has proposed TOU period differentiation between weekdays and

weekends during the summer. SEIA has opposed such a differentiation “based on the simplicity

for the customer of having a consistent set of TOU periods on all days of the week.”66 To start, it

is somewhat puzzling that SEIA apparently believes customers would prefer the “simplicity” of

not having to distinguish Mondays from Saturdays, but somehow would also be amenable to

having their rates change four times, over the course of every single day, for 180 days in a row,

every year.67 More importantly, however, SEIA’s proposal is flatly inconsistent with the

underlying cost data, which is the fundamental basis for TOU-period determination. As

conclusively demonstrated in SCE’s rebuttal testimony, summer weekday and weekend costs

vary dramatically.68 Moreover, using SEIA’s own cost data, and SEIA’s preferred use of 2021

data instead of 2024 data, SCE has demonstrated that same unsurprising phenomenon to be

true.69 Finally, SEIA made the same non-differentiation proposal in SDG&E’s recently-

adjudicated GRC Phase 2 proceeding, and the Commission correctly rejected it.70

D. Seasonal Definitions

SCE proposes to maintain its historical four-month summer season (June-September).

SEIA proposes a new six-month “summer” (May-October). SEIA’s proposal should be rejected

(as it was by the Commission in the recent SDG&E TOU Decision) because the underlying cost

data supports the continuation of SCE’s four-month summer definition.71 SEIA’s weather-

related arguments are beside the point. 66 Exhibit SEIA-01, p. iii. 67 See also CLECA rebuttal testimony, pp. 22-23 (noting limitations to customer survey SEIA used in

support of its “simplicity” argument). 68 Exhibit SCE-03, pp. 44-46 (including Table III-9 and Figure III-25). 69 See Exhibit SCE-100 at p. 1; see also SEIA, Beach, Evidentiary Hearing Tr. 2: 136 (confirming

accuracy of data). 70 See D.17-08-030, pp. 19; 25-26. 71 In addition, maintaining SCE’s current four-month summer will be one less change for customers

when adjusting to new TOU periods.

-14-

Primarily, it is undisputed that TOU periods must first be defined based on underlying

marginal costs.72 While loads should act as a “secondary check” on a TOU marginal cost

analysis,73 in the end, it is the costs that primarily matter if TOU periods are to serve their

purpose. SEIA’s proposal to shoehorn May and October in with the actual summer months is

inconsistent with the underlying cost data. For example, SCE demonstrated that the costs for

May and October are more similar to the winter months than to the actual summer months, using

both its own data,74 and using SEIA’s data.75 In fact, May is a less expensive month on both

weekdays and weekends than are November, December, January, February, and March.76 It is

hard to conceive how May could be considered a “summer” month when considering cost-based

criteria, other than its circumstantial placement on the calendar adjacent to June. Moreover, as

SEIA’s own data demonstrates, May and October cost data combined is actually less expensive

than November and March cost data combined, and the May/October cost profile is starkly

different than SCE’s current –and proposed – summer months of June-September.77 If anything,

the underlying cost data supports a shorter summer, not a longer one.78

Even if the Commission were to prioritize the consideration of loads over costs (which

would be contrary to its own precedent), SEIA’s “climate” analysis serves as a poor proxy for

loads, at best. Accepting at face value that Mr. Beach’s climate predictions79 about May

becoming hotter in the future are true, hotter weather is only roughly correlated with higher

loads. SCE’s rebuttal testimony demonstrated that while hot weather helps to drive peak loads, it

tends to do so in conjunction with humidity, solar illumination, and the number of consecutive

72 D.17-01-006, p. 12 (Guiding Principle No. 2). 73 D.17-01-006, p. 12 (Guiding Principle No. 3). 74 Exhibit SCE-03, p. 28, Figure III-13. 75 See Exhibit SCE-100, p. 2; see also SEIA, Beach, Evidentiary Hearing Tr. 2: 136 (confirming

accuracy of data). 76 Exhibit SCE-03, p. 28. 77 Exhibit SCE-100, p. 2; see also SEIA, Beach, Evidentiary Hearing Tr. 2: 136 (confirming accuracy

of data). 78 See, e.g., Exhibit SCE-01, p. 56, Table IV-5. 79 Mr. Beach confirmed he is not a climate scientist. See Beach, SEIA, Evidentiary Hearing Tr. 2: 134.

-15-

hot days.80 In light of those relevant factors, it is not surprising that, from 2012-2016, the vast

majority of SCE’s peak load days occurred during the months of July-September (and very few

in May or October).81

E. TOU Period Grandfathering

Agricultural Energy Consumers Association (AECA, and together with CFBF, the Ag

Parties); and Castaic Lake Water Agency, Rancho California Water District, and Renewable

Energy Water District (collectively, Water Districts) all submitted testimony requesting that the

Commission adopt extended grandfathering on legacy TOU periods for certain customers,

including for Renewable Energy Self-Generation Bill Credit Transfer (RES-BCT) customers. As

a threshold matter, the Commission has already addressed grandfathering for eligible solar

customers, including those participating on RES-BCT82 in the TOU OIR Decision. For those

customers, any request for additional grandfathering must be made through petitions for

modification (PFM) to that final Commission decision, not in this utility-specific RDW.83 As

stated by the Commission in the SDG&E TOU Decision: “[W]e do not revisit the TOU

grandfathering duration adopted [in the TOU OIR Decision].”84

Nor is additional grandfathering warranted. As the Commission correctly decided:

Importantly, the Commission recognizes that use of grandfathering as a mechanism for mitigating negative impacts from TOU period changes has two significant weaknesses: (i) [it] results in “inaccurate price signals that incent customer to use more power during high-cost periods” and (ii) it is not transparent to customers. Although today’s decision adopts grandfathering for a specific situation, we expect that going

80 Exhibit SCE-03, pp. 28-29. 81 Exhibit SCE-03, p. 30, Table III-6. 82 It would be particularly inappropriate to extend grandfathering provisions to a few, or maybe all,

RES-BCT projects solely in SCE’s service territory, considering it is a statewide program. See House, Water Districts, Evidentiary Hearing Tr. 2: 237-38.

83 A PFM of D.17-01-006 is pending. 84 D.17-08-030, p. 26.

-16-

forward the IOUs, customers, and DER technology providers will develop mitigation measures that are more transparent and more narrowly tailored than grandfathering.85

F. Other Mitigation Measures

The other mitigation measures proposed by the Water Districts are contrary to the spirit

of the August 9, 2017 Administrative Law Judge’s Ruling on Motions to Strike, which held that

testimony should be “stricken if the testimony proposes specific rate design changes or other

‘mitigation’ measures, so that those proposals could be considered with all other rate design

proposals in SCE’s GRC Phase 2 application, A.17-06-030.”86

SCE and the Agricultural Parties have stipulated that the Agricultural Parties’ mitigation

concerns will be addressed in SCE’s pending 2018 GRC Phase 2 proceeding.87 The same is true

for the Small Business Utility Advocates (SBUA) (and also including expanded and modified

education, marketing, and outreach efforts).88

G. Implementation

In rebuttal testimony, SCE responded to various parties’ concerns about a “dual”

implementation of its new TOU periods followed shortly thereafter by new GRC Phase 2 rates.

In response to that concern, SCE proposed a single February 2019 implementation date for both

proceedings.89 It is crucial to obtain timely decisions in both dockets in order to meet the

deadlines necessitated by the implementation of SCE’s proposed Customer Service Re-

Platform.90

85 D.17-01-006, p. 48. See also Water Districts, House, Evidentiary Hearing Tr. 2: 234 (acknowledging

bill impacts were determined using illustrative rates and that actual rates will be set in SCE’s pending 2018 GRC Phase 2 proceeding).

86 August 9, 2017 Administrative Law Judge’s Ruling on Motions to Strike, p. 9. See also House, Water Districts, Evidentiary Hearing Tr. 2: 236 (acknowledging alternative proposal is a rate mitigation measure).

87 Exhibit SCE-CFBF-AECA-01, ¶3. 88 Exhibit SCE-SBUA-1, Sections I, II and III. 89 Exhibit SCE-03, p. 71. See also Exhibit SCE-CFBF-AECA-01, ¶4. 90 Exhibit SCE-03, pp. 71-72.

-17-

III.

CRITICAL PEAK PRICING

SCE proposed certain changes to its critical peak pricing (CPP) program in its direct

testimony, and explained how it was also proposing an alternative proposal that requests

optional, not default, CPP for SCE’s small commercial and industrial (C&I) customers.91 No

party challenged the general merits of those proposals and they should be adopted in their

entirety, with the following exception and clarification: Pursuant to the Joint Stipulation

Between Southern California Edison (SCE) and the California Farm Bureau Federation (CFBF)

and Agricultural Energy Consumers Association (AECA) (collectively, Ag Parties) Resolving

Issues in SCE’s 2016 Rate Design Window Proceeding (A.16-09-003), SCE supports extending

its alternative proposal (i.e., CPP being offered as an optional rather than a default rate) to TOU-

PA-3 customers as well.92 That result is reasonable given the unique characteristics of

agricultural customers and the relatively small amount of load served under the TOU-PA-3 rate

schedules.93

IV.

REAL-TIME PRICING (RTP)

SCE proposed a change to its RTP rate design to condense the current five-tier summer

weekday prices into three day-types.94 No party opposed SCE’s proposal and it should be

adopted in its entirety.

91 Exhibit SCE-01, pp. 84-107. 92 Exhibit SCE-CFBF-AECA-01, ¶2. 93 See, e.g., Exhibit AECA-01, pp. 19-21. 94 Exhibit SCE-01, pp. 107-115.

-18-

V.

MARKETING, EDUCATION, AND OUTREACH (ME&O)

SCE proposed a ME&O campaign for its new TOU period roll-out in direct testimony.95

While that proposal was challenged in part by SBUA, those differences were resolved through

the Joint Stipulation Between Southern California Edison (SCE) and Small Business Utility

Advocates (SBUA) Resolving Issues in SCE’s 2016 Rate Design Window Proceeding (A.16-09-

003)).96 With the clarifications and additions provided for in that stipulation, SCE’s ME&O plan

should be approved in its entirety.

VI.

DISTRIBUTED ENERGY RESOURCES ACTION PLAN

SCE’s supplemental testimony demonstrated how SCE’s proposals in this proceeding

meet the applicable “vision” and “continuing” elements of the Commission’s November 10,

2016 Distributed Energy Resources Action Plan.97 Among other things, SCE demonstrated that

its TOU proposals reflect the time-variation of marginal costs and, that overall, sending

customers economically-efficient price signals “will help compensate DER customers fairly

while helping to maintain non-DER customer affordability.”98 In addition, Mr. Garwacki

testified that the new proposed TOU periods would encourage certain kinds of DER adoption,

namely energy storage.99 Overall, however, specific rate designs and potential mitigation

measures as they relate to DERs as a result of the new TOU periods adopted in this proceeding

95 Exhibit SCE-01, pp. 79-82. 96 Exhibit SCE-SBUA-1, p. 1. See also pending August 24, 2017, Joint Motion of Southern California

Edison Company (U 338-E) and Small Business Utility Advocates for Adoption of Settlement Agreement.

97 See generally, Exhibit SCE-02. 98 Exhibit SCE-02, p. 9. 99 SCE, Garwacki, Evidentiary Hearing Tr. 1: 92-93.

-19-

have either already been decided in the TOU OIR Decision or will be decided in SCE’s pending

2018 GRC Phase 2 proceeding.100

VII.

OPTION R CAP

The Scoping Memo in this proceeding added consideration of the elimination of the

Option R rate cap to the scope of the proceeding.101 In response to California Solar Energy

Industry Association’s (CALSEIA) and SEIA’s proposals that Option R should be made

available until the implementation of SCE’s 2018 GRC Phase 2 rates (or the cap eliminated in its

entirety), SCE noted that it was appropriate to consider the issue in that proceeding and not here,

consistent with the settlement agreement adopted by the Commission in D.14-12-048. It is the

express policy of this Commission to encourage settlements;102 settlements are only meaningful

to parties if they are respected and upheld.

But CALSEIA’s and SEIA’s arguments fail even if the Commission were to entertain

overturning the settlement. Although the solar parties argue that Option R is “cost neutral,” as

explained by SCE witness Robert Thomas during evidentiary hearings, that does not mean that

costs may not still be shifted to other customers and the solar parties failed to provide analysis

addressing this potential issue.103 In addition, SCE demonstrated that it is unlikely that the

Option R cap will be reached before the implementation of new GRC Phase 2 rates in early

2019, so there is no need for the Commission to reach a determination of the issue here.104

100 See, e.g., SCE, Garwacki, Evidentiary Hearing Tr. 1: 97. 101 Scoping Memo, p. 8. 102 See, e.g., D.88-12-083 (30 CPUC 2d 189, 221-223) and D.91-05-029 (40 CPUC 2d, 301, 326). 103 SCE, Thomas, Evidentiary Hearing Tr. 1: 12-13; see also Exhibit SCE-03, pp. 65-66. 104 See Exhibit SCE-03, pp. 67-68; see also SCE, Thomas, Evidentiary Hearing Tr. 1: 18; Exhibit SCE-

104 at p. 6 (CALSEIA ex parte communication showing its estimate of trends for commercial NEM interconnections).

-20-

VIII.

CONCLUSION

The vast majority of the litigation in this proceeding has come from groups representing a

small fraction of SCE’s customers, for whom changing TOU periods may not be economically

beneficial. SCE has diligently put forward TOU and other rate proposals developed in a neutral

fashion for SCE’s customers at large, and in a way that is consistent with the Commission’s clear

guidance to do so based on forward-looking marginal costs and grid needs. SCE believes that

the data supporting its proposals is compelling and overwhelming, but ultimately it is up to the

Commission to make policy determinations related to tradeoffs between customer groups. SCE

respectfully submits that the Commission has already struck that policy balance through the

grandfathering provisions set forth in the TOU OIR Decision, and has confirmed that

determination very recently in the SDG&E TOU Decision. The Commission can consider other

potential rate design mitigation options in SCE’s pending 2018 GRC Phase 2 proceeding if it so

wishes. In this proceeding, however, SCE respectfully urges the Commission to follow the data

and adopt SCE’s proposals as submitted.

Respectfully submitted, FADIA R. KHOURY RUSSELL A. ARCHER

/s/ Russell A. Archer By: Russell A. Archer

Attorneys for SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-2865 Facsimile: (626) 302-3990 E-mail: [email protected]

September 8, 2017


STATE OF CALIFORNIA


A.16-09-003 (Filed September 1, 2016)

CERTIFICATE OF SERVICE

I hereby certify that, pursuant to the Commission’s Rules of Practice and Procedure, I have this day served a true copy of SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E) OPENING BRIEF on all parties identified on the attached service list(s) for: A.16-09-003. 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 U.S. Mail to the offices of the Assigned ALJ(s) or other addressee(s).

ALJ Stephen C. Roscow CPUC 505 Van Ness Ave. San Francisco, CA 94102

Executed September 8, 2017 at Rosemead, California.

/s/Angelica Gamboa Angelica Gamboa Legal Administrative Assistant SOUTHERN CALIFORNIA EDISON COMPANY 2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770

CPUC Home

CALIFORNIA PUBLIC UTILITIES COMMISSIONService Lists

PROCEEDING: A1609003 - EDISON - FOR APPROVA FILER: SOUTHERN CALIFORNIA EDISON COMPANY LIST NAME: LIST LAST CHANGED: AUGUST 9, 2017

Download the Comma-delimited File About Comma-delimited Files

Back to Service Lists Index

Parties

HOWARD M, CRYSTAL RUSSELL A. ARCHER ATTORNEY AT LAW SR. ATTORNEY LAW OFFICE OF HOWARD CRYSTAL SOUTHERN CALIFORNIA EDISON COMPANY 813 A STREET, N.E. 2244 WALNUT GROVE AVE. / PO BOX 800 WASHINGTON, DC 20002 ROSEMEAD, CA 91770 FOR: SMALL BUSINESS UTILITY ADVOCATES FOR: SOUTHERN CALIFORNIA EDISON COMPANY (SBUA)

NICHOLAS SHER ROBERT FINKELSTEIN CALIF PUBLIC UTILITIES COMMISSION GENERAL COUNSEL LEGAL DIVISION THE UTILITY REFORM NETWORK ROOM 4300 785 MARKET ST., STE. 1400 505 VAN NESS AVENUE SAN FRANCISCO, CA 94103 SAN FRANCISCO, CA 94102-3214 FOR: TURN FOR: ORA

NORA E. SHERIFF EDWARD G. POOLE ALCANTAR & KAHL LLP ATTORNEY 345 CALIFORNIA ST., STE. 2450 ANDERSON & POOLE SAN FRANCISCO, CA 94104 601 CALIFORNIA STREET, SUITE 1300 FOR: CALIFORNIA LARGE ENERGY CONSUMERS SAN FRANCISCO, CA 94108-2818 ASSOCIATION FOR: WESTERN MANUFACTURED HOUSING COMMUNITIES ASSOCIATION

JEANNE B. ARMSTRONG KATY MORSONY ATTORNEY ALCANTAR & KAHL GOODIN, MACBRIDE, SQUERI & DAY, LLP 345 CALIFORNIA STREET, STE. 2450 505 SANSOME STREET, SUITE 900 SAN FRANCISCO, CA 94602

Page 1 of 5CPUC - Service Lists - A1609003

9/8/2017https://ia.cpuc.ca.gov/servicelists/A1609003_83826.htm

SAN FRANCISCO, CA 94111 FOR: ENERGY PRODUCERS AND USERS FOR: SOLAR ENERGY INDUSTRIES COALITION ASSOCIATION (SEIA)

JOSE E. GUZMAN, JR. BRAD HEAVNER ATTORNEY AT LAW POLICY DIR. GUZMAN LAW OFFICES CALIFORNIA SOLAR ENERGY INDUSTRIES ASSN. 288 THIRD STREET, SUITE 306 EMAIL ONLY OAKLAND, CA 94607 EMAIL ONLY, CA 95401 FOR: CALIFORNIA SMALL BUSINESS FOR: CALIFORNIA SOLAR ENERGY INDUSTRIES ROUNDTABLE AND CALIFORNIA SMALL ASSOCIATION BUSINESS ASSOCIATION (CSBA/CSBRT)

LON W. HOUSE, PH.D CAROLYN M. KEHREIN WATER AND ENERGY CONSULTING CONSULTANT 2795 EAST BIDWELL, STE. 100-176 ENERGY MANAGEMENT SERVICES FOLSOM, CA 95630 2602 CELEBRATION WAY FOR: RENEWABLE ENERGY WATER DISTRICTS: WOODLAND, CA 95776 CASTAIC LAKE WATER AGENCY, EASTERN FOR: ENERGY USERS FORUM (EUF) MUNICIPAL WATER DISTRICT, AND RANCHO CALIFORNIA WATER DISTRICT

MICHAEL BOCCADORO SCOTT BLAISING PRESIDENT COUNSEL WEST COAST ADVISORS BRAUN BLAISING SMITH WYNNE P.C. 925 L STREET, SUITE 800 915 L STREET, SUITE 1480 SACRAMENTO, CA 95814 SACRAMENTO, CA 95814 FOR: AGRICULTURAL ENERGY CONSUMERS FOR: CITY OF LANCASTER ASSOCIATION

RONALD LIEBERT KAREN NORENE MILLS ATTORNEY AT LAW ATTORNEY ELLISON SCHNEIDER HARRIS & DONLAN LLP CALIFORNIA FARM BUREAU FEDERATION 2600 CAPITOL AVENUE, STE. 400 2300 RIVER PLAZA DRIVE SACRAMENTO, CA 95816 SACRAMENTO, CA 95833 FOR: CALIFORNIA MANUFACTURERS & FOR: CALIFORNIA FARM BUREAU FEDERATION TECHNOLOGY ASSOCIATION

Information Only

BARBARA R. BARKOVICH DIANE I. FELLMAN CONSULTANT VP - WEST, GOV'T AFFAIRS BARKOVICH & YAP, INC. NRG EMAIL ONLY EMAIL ONLY EMAIL ONLY, CA 00000 EMAIL ONLY, CA 00000

MIKE CADE MRW & ASSOCIATES LLC INDUSTRY SPECIALIST EMAIL ONLY ALCANTAR & KAHL, LLP EMAIL ONLY, CA 00000 EMAIL ONLY EMAIL ONLY, OR 00000

BRANDON SMITHWOOD BLAKE ELDER MGR - CALIF STATE AFFAIRS CLEAN ENERGY SPECIALIST



SOLAR ENERGY INDUSTRIES ASSOCIATION EQ RESEARCH 600 14TH STREET, NW, SUITE 400 401 HARRISON OAKS BLVD., STE. 100 WASHINGTON, DC 20005 CARY, NC 27513

LON W. HOUSE, PH.D DANIEL DOUGLASS WATER AND ENERGY CONSULTING ATTORNEY 10645 N. ORACLE RD., STE. 121-216 DOUGLASS & LIDDELL ORO VALLEY, AZ 85737 4766 PARK GRANADA, SUITE 209 CALABASAS, CA 91302

CASE ADMINISTRATION STEVEN C. NELSON SOUTHERN CALIFORNIA EDISON COMPANY ATTORNEY 2244 WALNUT GROVE AVENUE, PO BOX 800 SAN DIEGO GAS & ELECTRIC COMPANY ROSEMEAD, CA 91770 488 8TH AVE., 9TH FL. SAN DIEGO, CA 92101

DONALD C. LIDDELL WILL FULLER ATTORNEY CALIF. & FED. REGULATORY AFFAIRS DOUGLASS & LIDDELL SAN DIEGO GAS AND ELECTRIC COMPANY 2928 2ND AVENUE 8330 CENTURY PARK COURT, CP31F SAN DIEGO, CA 92103 SAN DIEGO, CA 92123-1548

SUE MARA MARCEL HAWIGER RTO ADVISORS L.L.C. STAFF ATTORNEY 164 SPRINGDALE WAY THE UTILITY REFORM NETWORK REDWOOD CITY, CA 94062 785 MARKET ST., STE. 1400 SAN FRANCISCO, CA 94103 FOR: THE UTILITY REFORM NETWORK (TURN)

JAMES BIRKELUND FRANCESCA WAHL PRESIDENT SR. ASSOCIATE, BUS. DEVELOPMENT SMALL BUSINESS UTILITY ADVOCATES TESLA, INC. 548 MARKET STREET, SUITE 11200 444 DE HARO STREET, STE. 101 SAN FRANCISCO, CA 94104 SAN FRANCISCO, CA 94107

MARC KOLB TIMOTHY ALAN SIMON TESLA, INC. ATTORNEY 444 DE HARO STREET, SUITE 101 TAS STRATEGIES SAN FRANCISCO, CA 94107 100 PINE STREET, SUITE 1250 SAN FRANCISCO, CA 94111 FOR: CALIFORNIA SMALL BUSINESS ROUNDTABLE AND CALIFORNIA SMALL BUSINESS ASSOC.

CATHERINE E. YAP RACHEL BIRD BARKOVICH & YAP, INC. DIR - POLICY & BUS. DEVELOPMENT, WEST PO BOX 11031 BORREGO SOLAR SYSTEMS, INC. OAKLAND, CA 94611 360 22ND STREET, SUITE 600 OAKLAND, CA 94612

ALEX MORRIS JIN NOH DIR - POLICY & REGULATORY AFFAIRS SR. CONSULTANT STRATEGEN CONSULTING STRATEGEN CONSULTING 2150 ALLSTON WAY, STE. 210 2150 ALLSTON WAY, STE.210



BERKELEY, CA 94709 BERKELEY, CA 94709

R. THOMAS BEACH RICHARD MCCANN, PH.D PRINCIPAL CONSULTANT M. CUBED CROSSBORDER ENERGY 2655 PORTAGE BAY ROAD, SUITE 3 2560 NINTH STREET, SUITE 213A DAVIS, CA 95616 BERKELEY, CA 94710 FOR: SOLAR ENERGY INDUSTRIES ASSOCIATION

CAMILLE STOUGH, ESQ. DAVID PEFFER BRAUN BLAISING MCLAUGHLIN & SMITH PC BRAUN BLAISING MCLAUGHLIN & SMITH, P.C. 915 L STREET, STE. 1480 915 L STREET, SUITE 1480 SACRAMENTO, CA 95814 SACRAMENTO, CA 95814 FOR: CITY OF LANCASTER

REGULATORY CLERK ANDREW B. BROWN BRAUN BLAISING SMITH WYNNE ATTORNEY AT LAW 915 L STREET, STE. 1480 ELLISON SCHNEIDER & HARRIS LLP SACRAMENTO, CA 95814 2600 CAPITOL AVENUE, SUITE 400 SACRAMENTO, CA 95816-5905

ANN L. TROWBRIDGE ATTORNEY AT LAW DAY CARTER & MURPHY LLP 3620 AMERICAN RIVER DRIVE, STE. 205 SACRAMENTO, CA 95864

State Service

ERIC DURAN JUSTIN H. FONG CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION ELECTRICITY PRICING AND CUSTOMER PROGRAM ELECTRICITY PRICING AND CUSTOMER PROGRAM ROOM 4011 AREA 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

LEE-WHEI TAN MATTHEW A. KARLE CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION ELECTRICITY PRICING AND CUSTOMER PROGRAM ELECTRICITY PRICING AND CUSTOMER PROGRAM ROOM 4102 ROOM 4108 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

RAJAN MUTIALU ROBERT LEVIN CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION POLICY & PLANNING DIVISION ENERGY DIVISION AREA 4-A ROOM 4102 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

STEPHEN C. ROSCOW CALIF PUBLIC UTILITIES COMMISSION DIVISION OF ADMINISTRATIVE LAW JUDGES



ROOM 5109 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214

TOP OF PAGE BACK TO INDEX OF SERVICE LISTS



Documents

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF … · 2017. 9. 8. · (MEC) price forecast developed using its “PLEXOS” production simulation model, which includes all