2021 General Rate Case Rebuttal Testimony · 4 $859,000 for Solar by escalating costs to 2023...

Application No.: A.19-08-013 Exhibit No.: SCE-16 Vol. 01 Witnesses: J. Buerkle

T. Champ T. Condit

(U 338-E)

2021 General Rate Case Rebuttal Testimony

Generation

Before the

Public Utilities Commission of the State of California

Rosemead, California June 12, 2020

SCE-16 Vol. 01 Generation

Table of Contents

Section Page Witness

-i-

I. INTRODUCTION .............................................................................................1 J. Buerkle

A. Summary Of Rebuttal Position ..............................................................1

1. O&M Forecast Summary ...........................................................5

2. Capital Expenditure Summary ...................................................6

II. HYDRO .............................................................................................................7 T. Condit

A. O&M Expenses ......................................................................................7

1. SCE’s Application .....................................................................7

2. Intervenors’ Positions ................................................................8

a) Cal Advocates’ Position .................................................8

b) TURN’s Position ............................................................8

3. SCE’s Position ...........................................................................8

B. Capital Expenditures ..............................................................................9 J. Buerkle

1. SCE’s Application .....................................................................9

2. Intervenors’ Positions ................................................................9

a) Cal Advocates’ Position .................................................9

b) TURN’s Position ............................................................9

3. SCE’s Position .........................................................................10

a) 2019 Recorded Expenditures Forecast Update ..........................................................................10

b) SCE’s Forecast Is Valid ...............................................10

(1) Recorded San Gorgonio Decommissioning Costs to Date Are Necessary And Reasonable ..............................11


Table of Contents (Continued)


-ii-

(2) TURN’s Allegation That SCE Has Engaged In “Bad Forecasting” That Justifies A Permanent Disallowance Is Based On Its Inaccurate And Incomplete Perception Of Events ....................13

(3) TURN Applies An Incorrect Reasonableness Standard .................................15

(4) TURN Misconstrues SCE’s San Gorgonio Forecasts In The GRC .....................16

(5) Conclusion .......................................................17

III. FOSSIL FUEL GENERATION ......................................................................18

A. Mountainview ......................................................................................18

1. O&M Expenses ........................................................................18 T. Condit

a) SCE’s Application .......................................................18

b) Intervenors’ Position ....................................................19

(1) Cal Advocates’ Position ...................................19

(2) TURN’s Position ..............................................19

c) SCE’s Position .............................................................20

2. Capital Expenditures ................................................................20 J. Buerkle




(2) TURN’s Position ..............................................21

c) SCE’s Position .............................................................21

(1) 2019 Recorded Expenditures Forecast Update ...............................................21




-iii-

(2) Removal Of Mountainview Rotor Replacement Project ........................................21

B. Peakers .................................................................................................21 T. Condit

1. O&M Expenses ........................................................................21




(2) TURN’s Position ..............................................22

c) SCE’s Position .............................................................22





(2) TURN’s Position ..............................................23

c) SCE’s Position .............................................................23

C. Catalina ................................................................................................23

1. O&M Expenses ........................................................................23 T. Condit



(1) Cal Advocates Position ....................................24

(2) TURN’s Position ..............................................24

c) SCE’s Position .............................................................25

(1) Rebuttal To TURN ...........................................25





-iv-




(2) TURN’s Position ..............................................26

c) SCE’s Position .............................................................27

(1) 2019 Recorded Capital Expenditures Forecast Update ...............................................27

(2) The Catalina Repower Project Should Be Approved In The 2021 GRC, As SCE Has Presented Evidence Demonstrating The Reasonableness Of The Project And Forecast, And The Preliminary Feasibility Study Supports SCE’s Conclusion That The Proposed Project Is The Most Commercially Reasonable Option ...........................................27

(3) Feasibility Study ..............................................30

(4) The Preliminary Feasibility Study Results Support SCE’s Determination That Diesel Engines Are Appropriate To Meet The Urgent Emissions Compliance Deadlines..........................................................33

d) Conclusion ...................................................................35

D. Fuel Cells .............................................................................................35 T. Condit

1. O&M Expenses ........................................................................35







-v-

(2) TURN’s Position ..............................................36

c) SCE’s Position .............................................................36

(1) Rebuttal to TURN ............................................36

IV. SOLAR ............................................................................................................37

1. O&M Expenses ........................................................................37




(2) TURN’s Position ..............................................37

c) SCE’s Position .............................................................38




(1) Cal Advocates Position ....................................38

(2) TURN’s Position ..............................................38

c) SCE’s Position .............................................................39

d) 2019 Recorded Expenditures Forecast Update ..........................................................................40

V. PALO VERDE .................................................................................................41 T. Champ

A. O&M Expenses ....................................................................................41

1. SCE’s Application ...................................................................41

2. Intervenors’ Positions ..............................................................42

a) Cal Advocates’ Position ...............................................42

b) TURN’s Position ..........................................................42




-vi-

(1) TURN Recommends That SCE’s Test Year O&M Non-Labor Forecast Be Reduced for Lower APS Budgets...............43

(2) TURN Recommends That SCE’s Share of Palo Verde’s Annual NEI Membership Dues Be Reduced by 50% ..................................................................43

(3) TURN Recommends That Palo Verde Water Sales Revenues Be Removed From Non-Tariffed Products And Services (NTP&S) And Included In This GRC for Ratemaking ......................................................43

3. Rebuttal To TURN’s Positions ................................................44

a) SCE’s Corrected Palo Verde O&M Non-Labor Forecast In 2018 Constant Dollars Was Developed Based On The Best Information Available At The Time It Was Developed, Whereas TURN’s Recommended Reduction Is Based On Previously Unavailable Information ............................44

(1) TURN’s Recommended Reduction Of $139,000 For Palo Verde NEI Membership Dues Is Excessive And Unjustified........................................................45

(2) Palo Verde Water Sales Revenues Are Correctly Classified As Non-Tariffed Products And Services (NTP&S) And Should Not Be Included As OOR For Ratemaking As TURN Recommends ..................................47

4. Conclusion ...............................................................................48

B. Capital Expenditures ............................................................................48

1. SCE’s Application ...................................................................48




-vii-

2. Intervenors’ Positions ..............................................................49

3. SCE’s Rebuttal To Cal Advocates And TURN’s Positions ...................................................................................49

4. Conclusion ...............................................................................49

Appendix A Generation Data Request Responses ...........................................................

Appendix B Workpapers ..................................................................................................

Appendix C Errata ...........................................................................................................

1

I. 1

INTRODUCTION 2

In this volume, Southern California Edison (SCE) provides additional support for its Test Year 3

(TY) 2021 forecast of operations and maintenance (O&M) expenses and 2019-2023 capital expenditures 4

forecast for Generation activities, which are managed by the Generation organization. If approved, this 5

funding request will allow SCE to continue its efforts to operate and maintain approximately 2,600 MW 6

of generating facilities and plants. The following BPEs will be discussed within this volume: 7

Chapter II - Hydro 8

Chapter III – Fossil Fuel Generation 9

Chapter IV – Solar 10

Chapter V – Palo Verde 11

This rebuttal testimony addresses the various recommendations raised by California Public 12

Advocates Office (Cal Advocates) and The Utility Reform Network (TURN) regarding SCE’s O&M 13

expenses and capital expenditures forecasts for Generation. 14

A. Summary Of Rebuttal Position 15

A summary of Generation O&M expenses and capital expenditures forecasts proposed by SCE, 16

Cal Advocates, and TURN are shown in the following tables. Table I-1 below provides a summary of 17

Generation’s 2021 O&M expense forecast for SCE, Cal Advocates, and TURN, identifies the variances 18

from SCE’s forecasts and Cal Advocates’ and TURN’s respective recommended forecasts, and provides 19

SCE’s rebuttal position. 20

2

Table I-1 Generation

2021 O&M Forecast Summary of SCE, Cal Advocates, and TURN’s Positions and SCE’s Rebuttal

Position (2018 Constant $000)

Table I-2 provides a summary of Generation’s 2019-2021 capital forecast by SCE, Cal 1

Advocates, and TURN, along with the variance from SCE’s forecast, and SCE’s rebuttal forecast. 2

Table I-2 Generation

Capital Expenditures 2019-2021 Forecast Summary of SCE, Cal Advocates, and TURN’s Positions

(Nominal $000)

Summary of Cal Advocates recommendations:1 3

SCE’s forecast of generation-related O&M expenses be adopted. 4

SCE’s forecast of generation-related capital expenditures for 2019 be adopted. 5

1 Exhibit PAO-09 Generation, Energy Procurement & Wildfire Management Capital, p. 2, lines 2-16.

SCECal

AdvocatesTURN

Cal Advocates

TURN

1 Hydro 42,028 42,028 41,786 - (242) 41,757

2 Fossil Fuel Generation(1) 42,847 43,005 41,905 158 (942) 41,905

3 Solar 3,755 3,755 3,755 - - 3,755

4 Nuclear(2) 73,340 73,340 71,686 - (1,654) 73,331

5 Total 161,970 162,128 159,132 158 (2,838) 160,748 1 Fossil Fuel Generation includes an errata for Mountainview O&M forecast.2 Nuclear O&M forecast includes errata for SCE and Cal Advocates.

Line No.

Business Planning Element2021 Forecast Variance from SCE SCE

Rebuttal Position

SCECal

Advocates TURNCal

Advocates TURN1 Hydro 131,163 131,163 126,013 - (5,150) 125,789 2 Fossil Fuel Generation 91,878 75,478 37,878 (16,400) (54,000) 41,912 3 Solar 300 300 300 - - 4,078 4 Nuclear 111,074 111,074 111,074 - - 110,707 5 Total 334,415 318,015 275,265 (16,400) (59,150) 282,486

Line No.

Business Planning Element

2019 - 2021 Forecast Variance from SCE SCE Rebuttal Position

3

SCE’s forecast of generation-related capital expenditures for 2020 and 2021 be reduced by 1

$10.4 million and $6.0 million respectively to remove SCE’s planned diesel generator 2

installations at Catalina Island in 2020 and 2021 from SCE’s forecast. 3

Summary of TURN’s recommendations:2 4

Reduce Hydro O&M expenses by $242,000 to reduce costs to operate the retired Borel plant 5

from a five-year average to the much lower expenses in the last recorded year. 6

Reduce Hydro capital expenses by $6,565,000 to permanently disallow recovery of the San 7

Gorgonio decommissioning cost, given that ratepayers have largely paid for it already 8

through SCE’s requests for funding of this project in five consecutive rate cases. 9

Reduce Mountainview O&M expenses by $980,000 to reflect lower plant operations due to 10

increasing renewable resource use and to correct an improper escalation rate. 11

Reduce Mountainview capital expenses by $54 million because SCE will not be purchasing 12

two spare rotors in 2020-2021. 13

Require SCE to bring forward a plan for repowering the remainder of Catalina Island (after 14

the 2021 plants) in the next rate case and consider a disallowance in the next GRC unless 15

SCE can affirmatively demonstrate that it fully considered all options and made a decision. 16

Reduce Fuel Cell O&M expenses by $18,000 to remove double-counted costs. 17

Reduce Palo Verde O&M expenses by $7,210,000 to reflect the fact that the primary owner 18

and operator’s most recent budget is considerably lower than SCE’s request, and to remove 19

50% of Nuclear Energy Institute dues consistent with Commission precedent.3 20

Increase Other Operating Revenue by $475,000 to move SCE’s share of revenues from sales 21

made by Palo Verde to the APS-owned Redhawk combined cycle plant from Non-Tariffed 22

Products and Services to an above-the-line account for ratemaking. 23

Reduce Participation Charges (for A&G and payroll taxes at Palo Verde, included in Ex, 24

SCE-6 Vol. 2) by $2,227,000, a change that is consequential to TURN’s reduction in O&M 25

expenses.4 26

2 Exhibit TURN-09 Generation Marcus page 1, line 17, thru page 2, line 33.

3 Note, after SCE’s forecast errata correction, the remaining difference is $1.647M ($7.210M - $5.563M).

4 Exhibit SCE-18, Vol. 3.

4

Reduce Hydro decommissioning expense by $19,830,000 to depreciate only the Borel and 1

Rush Creek (Agnew Lake Dam) plants.5 2

Reduce decommissioning by $265,000 for Mountainview, $196,000 for Peakers, and 3

$859,000 for Solar by escalating costs to 2023 consistent with the Commission’s decision in 4

the 2018 TY general rate case.6 5

Reduce depreciation for Palo Verde by $1,767,000 (end of 2018) and reduce the depreciable 6

percentage for Palo Verde from 0.99% to 0.90% (for use in the RO model), by reducing the 7

amount of interim retirements.7 8

Reduce rate base by $31 million by increasing accumulated depreciation to reflect the Borel 9

condemnation settlement.8 10

Reduce rate base for Palo Verde Materials and Supplies inventory by $3,367,000 to reflect 11

the 2020 Palo Verde budget. (SCE-7 Vol. 2).9 12

Recover the cost of the Perris solar photovoltaic plant, which closed prematurely, over six 13

years with no return.10 14

Require SCE to conduct a new decommissioning study for Mountainview, a representative 15

Peaker, and a representative solar plant in its next rate case.11 16

After reviewing Cal Advocates’ and TURN’s recommendations, SCE agrees to the following: 17

Reduce the 2021 TY Hydro O&M forecast by $0.271 million to reduced cost of operations at 18

the retired Borel plant ($0.242 million) and remove incorrect charges of Catalina Gas and 19

Water personnel in 2018 ($0.029 million). 20

Reduce Mountainview TY O&M expenses by $980,000 to reflect lower plant operations due 21

to increasing renewable resource use ($0.822 million) and to adjust the escalation rate 22

($0.158 million) utilized for a forecast component. 23

5 Id.

6 Id.

7 Id.

8 Id.



11 Id.

5

Remove the $54 million Mountainview Rotor Replacements project (2020 - $18.0 million 1

and 2021 - $36.0 million) from SCE’s Capital forecast for the Fossil Fuel BPE. 2

Reduce the Catalina Diesel 2021 non-labor O&M by $0.103 million for non-recurring outage 3

costs, after new diesel installation. 4

Retain the Catalina Repower Capital project capital forecast as the project evaluation study to 5

be issued by June 30, 2020 confirms the planned project as the best solution to meet 6

environmental compliance and lowest cost objectives. 7

Reduce Fuel Cell 2021 non-labor forecast by $0.018 million for costs that were double 8

counted. 9

Adopt Palo Verde’s O&M forecast with errata correcting the forecast from nominal dollars to 10

2018 constant dollars and an adjustment to remove non-customer costs of $9,000. 11

Reject TURN’s request to change to Palo Verde’s water sales that are correctly accounted for 12

as Non-Tariffed Products & Services into Other Operating Revenue (OOR) for above-the-13

line ratemaking. 14

1. O&M Forecast Summary 15

Table I-3 provides 2014-2018 recorded O&M expenses and the respective 2021 O&M 16

forecast proposed by SCE, Cal Advocates, and TURN; variances between the forecasts; and SCE’s 17

rebuttal position. TURN proposed a small reduction to SCE’s O&M forecast. SCE addresses TURN’s 18

proposed reduction to the O&M forecast below. 19

6

Table I-3 Generation O&M Expenses

2014-2018 Recorded/2021 Forecast Summary of SCE, Cal Advocates and TURN’s Positions

(2018 Constant $000)

2. Capital Expenditure Summary 1

Table I-4 provides 2014-2018 recorded capital expenditures and the respective 2019-2

2021 capital expenditure forecasts proposed by SCE, Cal Advocates, and TURN; variances between the 3

forecasts; and SCE’s rebuttal position. Cal Advocates and TURN proposed various reductions to SCE’s 4

capital expenditure forecast in several BPEs. SCE addresses Cal Advocates’ and TURN’s proposed 5

reductions in the below corresponding chapters. 6

Table I-4 Generation Capital Expenditures

2014-2018 Recorded/2019-2021 Forecast Summary of SCE, Cal Advocates and TURN’s Positions

(Nominal $000)

2014 2015 2016 2017 2018 SCECal

AdvocatesTURN

Cal Advocates

TURN

1 Hydro 43,501 45,160 43,158 43,512 44,347 42,028 42,028 41,786 - (242) 41,757

2 Fossil Fuel Generation(1) 41,491 36,445 41,198 45,432 38,367 42,847 43,005 41,905 158 (942) 41,905 3 Solar 4,563 4,381 4,379 3,974 3,968 3,755 3,755 3,755 - - 3,755

4 Nuclear(2) 79,044 84,798 86,136 83,054 77,619 73,340 73,340 71,686 - (1,654) 73,331 5 Total 168,599 170,784 174,872 175,972 164,302 161,970 162,128 159,132 158 (2,838) 160,748

1 Fossil Fuel Generation includes an errata for Mountainview O&M forecast.2 Nuclear O&M forecast includes errata for SCE and Cal Advocates.

Line No.

Business Planning Elements

SCE Recorded SCE Rebuttal Position

2021 Forecast Variance from SCE

2014 2015 2016 2017 2018 SCECal

Advocates TURNCal

Advocates TURN1 Hydro 53,770 27,174 28,822 38,441 39,169 131,163 131,163 126,013 - (5,150) 125,789 2 Fossil Fuel Generation 7,488 80,711 73,973 31,139 24,382 91,878 75,478 37,878 (16,400) (54,000) 41,912 3 Solar 933 627 67 (7) - 300 300 300 - - 4,078 4 Nuclear 36,900 36,536 36,116 34,857 37,824 111,074 111,074 111,074 - - 110,707 5 Total 99,091 145,047 138,978 104,431 101,376 334,415 318,015 275,265 (16,400) (59,150) 282,486

Line No.


SCE Recorded 2019 - 2021 Forecast Variance from SCE SCE Rebuttal Position

7

II. 1

HYDRO 2

A. O&M Expenses 3

1. SCE’s Application 4

SCE operates and maintains thirty-three hydroelectric (Hydro) generating facilities, 5

including thirty-three dams, forty-three stream diversions, and approximately 143 miles of tunnels, 6

conduits, flumes, and flow lines.12 SCE’s 2021 Test Year forecast is $42.028 million (constant 2018 7

dollars) for O&M expenses, and is necessary to maintain safe operations for employees and the public, 8

provide reliable service at low cost, and comply with applicable laws and regulations. SCE used the last 9

recorded year as our basis for estimating 2021 Test Year labor expenses, yielding a labor Test Year 10

forecast of $22.486 million.13 For non-labor, the five-year average (i.e., the average annual expense of 11

2014 through 2018) best reflects historical and future non-labor expenses yielding a non-labor Test Year 12

2021 forecast of $19.543 million.14 13

Table II-5 below provides a summary of the Hydro Test Year O&M expense forecast 14

proposed by SCE, Cal Advocates, and TURN, respectively. The table also identifies the variances 15

between SCE’s forecast and Cal Advocates’ and TURN’s respective recommended forecasts, and 16

provides SCE’s rebuttal position. 17

12 Exhibit SCE-05, p. 27.

13 Id., p. 37.

14 Id., p. 38.

8

Table II-5 Hydro O&M Expense

2021 Forecast Summary of SCE, Cal Advocates, and TURN’s Position


2. Intervenors’ Positions 1

a) Cal Advocates’ Position 2

Cal Advocates recommends that SCE’s forecast of Hydro-related O&M expenses 3

be adopted without any reductions.15 4

b) TURN’s Position 5

TURN recommends removing the five-year average forecast expenses for non-6

labor costs of $261,000 for operating the retired Borel plant, and instead suggests utilizing 2018 last 7

recorded year non-labor costs of $19,000, a reduction, resulting in a forecast reduction of $242,000 to 8

non-labor.16 The proposed reduction also removes a project that was written off by SCE in 2017 as a 9

result of the retirement.17 10

3. SCE’s Position 11

As SCE indicated in response to a TURN data request (TURN-SCE-072),18 SCE and 12

other parties are in the process of executing a stipulated judgment that will be submitted to federal court 13

in the Eastern District of California, requesting that the court enter judgment/decision for Borel’s 14

decommissioning. Following receipt of the final decision, SCE will commence with decommissioning 15

activities and begin charging costs to the decommissioning work order. SCE anticipates the court’s 16

decision will likely occur in late-2020/early-2021. In light of the decision to decommission the Borel 17


16 Exhibit TURN-09 Generation Marcus page 15, lines 4-7.

17 TURN-09 Generation Marcus page 15, lines 4-7.

18 Appendix A, Data Requests, TURN-SCE-072, Question 07.

SCECal

AdvocatesTURN

Cal Advocates

TURN

1 Hydro 42,028 42,028 41,786 - (242) 41,757

Line No.


2021 Forecast Variance from SCE SCE Rebuttal Position

9

facility and expectation that the court’s decision will be issued within the next several months, SCE 1

accepts TURN’s recommendation of a $0.242 million reduction in Hydro O&M non-labor expenses. 2

SCE also recommends an additional reduction of $0.029 million to its Hydro O&M labor 3

forecast. This reduction is the result of incorrect timecard entries made to the Hydro O&M labor 4

accounts by Catalina Water & Gas employees in 2018. 5

B. Capital Expenditures 6


SCE’s planned 2019-2023 capital expenditures for its Hydro generating facilities are 8

necessary to maintain safe operations for employees and the public; provide reliable service at 9

reasonable cost; and comply with applicable laws and regulations. Table II-6 below provides the 10

respective 2019-2021 Hydro capital expenditures forecast proposed by SCE, Cal Advocates, and TURN; 11

variances between the forecasts; and SCE’s rebuttal position. 12

Table II-6 Hydro Capital Expenditures

2019-2021 Forecast Summary of SCE, Cal Advocates, and TURN’s Positions

(Nominal $000)



Cal Advocates recommends that SCE’s 2019-2021 forecast of Hydro-related 15

capital expenditures be adopted without any reductions.19 16


TURN states that it “agrees that this plant is a prime candidate for 18

decommissioning, and, at a price of $6,565,000 relatively costly for its small size because of the 19

19 Exhibit PAO-09 Generation, Energy Procurement & Wildfire Management Capital page 2, lines 7-16.

SCECal

Advocates TURNCal

Advocates TURN1 Hydro 131,163 131,163 126,013 0 (5,150) 125,789

SCE Rebuttal Position

Line No.


2019 - 2021 Forecast Variance from SCE

10

complex need to assure water supplies to various entities.”20 Yet TURN urges the Commission not to 1

grant cost recovery for this item on the sole basis that SCE has allegedly received funding for this 2

unfinished project in several past GRCs and not spent the authorized funds as intended. TURN thus 3

recommends a permanent disallowance of future expenditures for the San Gorgonio Decommissioning 4

project.21 (In addition, TURN calculates that SCE’s customers have paid approximately $4 million for 5

this project since 2009.22) 6

3. SCE’s Position 7

a) 2019 Recorded Expenditures Forecast Update 8

SCE proposes to update its original 2019 forecast of $44.642 million to reflect 9

2019 recorded, which is $39.268 million. For additional information on the company-wide use of 2019 10

capital recorded expenditures as the rebuttal forecast, please see SCE-12, Vol. 1. 11

b) SCE’s Forecast Is Valid 12

SCE’s forecast for decommissioning San Gorgonio is properly in this rate case, 13

and TURN’s recommendation for a permanent disallowance should be rejected as factually and legally 14

defective for several reasons.23 15

First, TURN fails to understand that the decommissioning costs SCE has incurred 16

are necessary to maintain the San Gorgonio facility in a safe condition and fulfill regulatory and 17

contractual requirements. Such costs should be deemed reasonable, consistent with Commission 18

precedent in other decommissioning review proceedings. 19

Second, TURN incorrectly faults SCE for decommissioning delays, failing to 20

consider the complexities involved in the decommissioning of a Hydro facility and the fact that the 21

delays are due to third-party events beyond SCE’s control. 22

20 Exhibit TURN-09, p. 16, lines 5-7. This $6.5M figure is the total estimated capital cost for decommissioning

over this GRC cycle.

21 Exhibit TURN-09, p. 16.

22 Id., p. 18, line 5.

23 In addition to the four reasons discussed in this volume why TURN’s recommendation should be rejected, TURN’s premise that SCE’s shareholders have been unfairly enriched misunderstands the impact of variances between authorized and recorded capital. For a discussion of this issue and why TURN’s proposal to make shareholders responsible for San Gorgonio and other previously approved projects is improper, see the ratemaking testimony of Mr. Doug Snow in Exhibit SCE-18, Volume 1, Chapter II.

11

Third, TURN seeks to apply an incorrect reasonableness review standard. By 1

arguing in this GRC that SCE’s prior forecasts are unreasonable based on how events have unfolded, 2

TURN impermissibly seeks to relitigate final Commission decisions regarding San Gorgonio in each of 3

the past four GRCs that found the prior forecasts to be reasonable. Moreover, to the extent the 4

Commission reviews the reasonableness of SCE’s forecasting in prior GRCs as a basis for considering 5

TURN’s proposed disallowance, it should be based on what SCE knew at the time the forecasts were 6

developed, not how events subsequently unfolded. 7

Fourth, TURN misunderstands the scope of SCE’s forecast for San Gorgonio 8

decommissioning, as TURN mistakenly believes the $6.565 million capital forecast for San Gorgonio 9

decommissioning in this GRC covers the entire project. Although SCE provided an estimate for San 10

Gorgonio decommissioning in prior GRCs, SCE never indicated the project would be completed in five 11

years, nor that the GRC forecast covered the entirety of the San Gorgonio decommissioning project. 12

SCE only forecasted costs for a five-year period, as SCE does for all of its capital projects. San 13

Gorgonio decommissioning activities will take longer than five years to complete, and recent internal 14

estimates indicate that the remaining costs of San Gorgonio decommissioning activities will exceed $48 15

million. It would be wholly unreasonable to permanently disallow decommissioning costs of this 16

magnitude. 17

(1) Recorded San Gorgonio Decommissioning Costs to Date Are 18

Necessary And Reasonable 19

As shown in Table II-7 below, SCE over the last 12 years has been 20

required to incur various costs for the San Gorgonio decommissioning project, spending on average 21

$0.408 million annually and inception-to-date $5.307 million;24 approximately $1.3 million higher than 22

the $4.0 million that TURN calculates SCE’s customers have paid SCE (i.e., $5.3 - $4.0 million).25 23

24 Inception thru April 2020.

25 Exhibit TURN-09 Generation Marcus, p. 18, line 5.

12

Table II-7 San Gorgonio Decommissioning

Capital Expenditures Recorded 2009 - April 2020 Year-to-Date

(Nominal $000)

TURN’s assertion that customers have paid these costs for “non-existent 1

work” is not true. TURN fails to recognize that the costs incurred to date by SCE were necessary to shut 2

down the facility and maintain it in a safe, regulatory-compliant lay-up condition pending further 3

decommissioning activities. In particular, the costs incurred for the past several years were utilized, 4

among other things, to maintain the facility in a safe condition, meet regulatory requirements, pay 5

required taxes and fees, meet contractual commitments, etc. The Commission has previously determined 6

that these types of required costs are reasonable in connection with SCE’s maintaining SONGS 1 and 7

SONGS 2&3 in safe condition post-retirement prior to full decommissioning, which in those cases is a 8

process that is expected to take several years.26 The same uncontroversial determination should be 9

26 See, for example, D.18-10-010 (2015 Nuclear Decommissioning Cost Triennial Proceeding Phase 1 Decision)

and D.18-11-034 (2015 Nuclear Decommissioning Cost Triennial Proceeding Phases 2 & 3 Decision).

Line Year Total1 2008/Prior 685 2 2009 22 3 2010 293 4 2011 778 5 2012 639 6 2013 185 7 2014 284 8 2015 308 9 2016 207

10 2017 257 11 2018 568 12 2019 795 13 2020 YTD 286 14 TOTAL 5,307

15Estimated

avg spend/yr.408

13

reached here (albeit at much lower expenditure levels given the relative sizes of the respective 1

generation facilities). Indeed, it would be unreasonable for SCE to not maintain the facility in a safe 2

condition, ignore regulatory requirements, and fail to pay required taxes and fees, while SCE waits for 3

various third-party reviews and actions to be completed prior to proceeding with active 4

decommissioning activities. 5

(2) TURN’s Allegation That SCE Has Engaged In “Bad Forecasting” 6

That Justifies A Permanent Disallowance Is Based On Its Inaccurate 7

And Incomplete Perception Of Events 8

TURN fails to understand the complexities of Hydro decommissioning 9

and the divergent environmental and community interests that must be resolved prior to SCE being able 10

to proceed with active decommissioning activities. The timing and manner in which these issues are to 11

be resolved are beyond SCE’s control. While the physical decommissioning of Hydro powerhouses and 12

associated auxiliary equipment can in some cases be a straightforward dismantlement process, removal 13

of the ancillary water storage and/or conveyance facilities is an extremely complex process involving 14

water rights issues between local Participating Entities.27 For San Gorgonio decommissioning, the water 15

storage/conveyance and water rights issues are further complicated by the fact that the San Gorgonio 16

water conveyance facilities are located on land owned by the United States Forest Service (USFS), 17

which is not dissimilar to the SONGS facilities’ geographical location on land owned by the federal 18

government. 19

In the case of San Gorgonio, many sections of the water conveyance 20

facilities (diversion structures and flowlines) existed prior to the powerhouse being constructed and 21

operated. SCE has contractual agreements with the Participating Entities to: 1) continue performance of 22

repairs and maintenance of the water conveyance infrastructure until FERC approves the license 23

surrender and the USFS issues a special-use permit or easement to the Participating Entities; and 2) 24

transfer this infrastructure to the Participating Entities following surrender of the FERC license. As 25

shown in Figure II-1, the FERC license surrender and transfer process has been protracted and 26

adversarial. 27

27 Participating entities include: the City of Banning, Banning Heights Mutual Water Company, and the San

Gorgonio Pass Water Agency.

14

Figure II-1 San Gorgonio FERC License Surrender and Transfer Process

As noted in the timeline above, in 2014, FERC referred the matter to its 1

Dispute Resolution Service (DRS) to act as mediator, based on the lack of progress and slow pace of 2

negotiations between USFS and the Participating Entities. The mediation process is ongoing and in 3

October 2019, U.S. Congressman Raul Ruiz attended the FERC DRS meeting while members of his 4

staff toured the San Gorgonio site. 5

At issue is the USFS’s recommended environmental flow requirements 6

and the PEs’ demands for increased water delivery to account for what their calculated water lost due to 7

surface diversion and seepage from the re-routing of the existing water conveyance system through 8

Burnt Canyon. The Burnt Canyon Diversion and Flowline by-pass (non-FERC Facility) was built in 9

2002 to provide a new conveyance path for a failed flowline caused by major storm damage in 1998. A 10

portion of the flowline is still considered temporary and future permanent improvements are necessary 11

for fulfillment of the license transfer and for the water conveyance system to be deemed complete. 12

In response to recent environmental studies conducted by SCE, the USFS 13

has reduced its recommended environmental flow requirements. The USFS and the PEs are currently 14

negotiating a long-term easement for the continued operation of the water conveyance system upon 15

SCE’s completion of repairs to the facilities and license surrender. Once an agreement between the 16

USFS and the Participating Entities is reached, SCE will be contractually obligated to perform a variety 17

of additional repairs to the San Gorgonio water conveyance system before transferring ownership to the 18

Participating Entities. 19

15

In short, while it is unfortunate that physical decommissioning activities at 1

San Gorgonio have taken longer to commence than expected, SCE, through no fault of its own, has been 2

caught in the middle of a water rights dispute between the USFS and Participating Entities. 3

(3) TURN Applies An Incorrect Reasonableness Standard 4

TURN recommends disallowance of San Gorgonio decommissioning 5

costs simply because SCE “forecast completion of this project four times . . . when [SCE] turned out to 6

be unable to do the project for over a decade.”28 In making this recommendation, TURN inappropriately 7

seeks to apply an incorrect reasonableness review standard based on hindsight. 8

As a threshold matter, the Commission approved various San Gorgonio 9

decommissioning forecasts in each of the past four GRCs. By now arguing in this GRC that SCE’s prior 10

forecasts are unreasonable just because they turned out not to be accurate, TURN impermissibly seeks to 11

relitigate final Commission decisions regarding San Gorgonio in each of the past four GRCs and to do 12

so based on subsequent event – a violation of the first principle on avoiding hindsight. The Commission 13

should not only note that events described above have presented unforeseeable and unavoidable 14

challenges entirely outside of SCE’s control, the Commission should also reject TURN’s current 15

objection to the prior, approved forecasts as untimely and foreclosed by the Commission’s prior GRC 16

decisions. 17

Even if the Commission were to reconsider the reasonableness of SCE’s 18

forecasting in prior GRCs as a basis for considering TURN’s proposed disallowance (which should not 19

happen), it should be based on what SCE knew at the time the forecasts were developed, not how events 20

subsequently unfolded. For example, the Commission has held that: (1) a utility’s actions “may be found 21

to be reasonable and prudent, if the utility shows that its decision making process was sound, . . . even if 22

it turns out not to have led to the best outcome;”29 (2) the reasonableness of a particular management 23

action does not depend on “how the decision holds up in the light of future developments;”30 and (3) a 24

reasonable and prudent act can include “a spectrum of possible acts.”31 Thus, under this well-established 25

standard, the Commission reviews the reasonableness of a utility’s actions based upon what the utility 26

28 Exhibit TURN-09 Generation Marcus, p. 16.

29 D.05-08-037 at 10-11.

30 D.16-12-063 at p. 10.

31 Id. at p. 9.

16

knew or should have known at the time the utility took the actions, not based upon subsequent events 1

and the utility’s response to those events viewed with the benefit of hindsight.32 In contrast to this 2

precedent, TURN’s recommendation is plainly based on how San Gorgonio decommissioning events 3

have unfolded over the past decade, not the reasonableness of SCE’s forecasting at the time each 4

forecast was completed and approved in each of the past four GRCs 5

Finally, the implicit alternative that TURN suggests is that SCE should 6

have not provided any forecast for San Gorgonio decommissioning in any GRC until the above-7

described water storage/conveyance and water rights dispute were resolved. The Commission should not 8

view this as serious argument, and such a result cannot possibly be within the “spectrum of possible 9

acts” that could be deemed reasonable. Had SCE taken this approach there would have been insufficient 10

funding for the activities needed to complete to maintain the San Gorgonio facility is a safe condition, 11

complete repairs and maintenance of the water conveyance infrastructure, and meet other regulatory and 12

contractual requirements. In addition, SCE would not have had funding available to commence physical 13

decommissioning activities in the event the disputed issues between USFS and the Participating Entities 14

were timely resolved. 15

(4) TURN Misconstrues SCE’s San Gorgonio Forecasts In The GRC 16

It is also important to clarify that TURN misunderstands the scope of 17

SCE’s GRC capital forecasts for San Gorgonio decommissioning. TURN incorrectly suggests that in 18

each of the past five GRC capital forecasts (which necessarily covered only a five-year period consistent 19

with the GRC plan), SCE has promised to decommission the San Gorgonio power plant at a cost in the 20

range of $6 to $7 million. While SCE has forecasted San Gorgonio costs in the past five GRCs, SCE 21

never indicated the project would be completed in five years, nor that the GRC forecast covered the 22

entirety of the San Gorgonio decommissioning project. SCE only forecasted costs for a five-year period, 23

as required by the GRC plan. Given that SCE has been unable to commence major activities as it 24

continues to wait for the third-party water storage/conveyance and water issues to be resolved, SCE has 25

continued to forecast about the same spending for the initial five-year period. But San Gorgonio 26

decommissioning activities will take longer than five years to complete. In addition, in line with the 27

substantial decommissioning estimates provided in Table II-38 of Exhibit SCE-05, Vol. 1, recent 28

32 D.17-05-020, p. 9; see also In re San Diego Gas & Electric Company, D.05-08-037, pp. 9-11; In the Matter of

the Application of Golden State Water Company, D.09-05-025, p. 8.

17

internal estimates indicate that the remaining costs of San Gorgonio decommissioning activities will 1

exceed $48 million, which include the mitigation costs from the anticipated agreement between the 2

USFS, PEs and SCE. 3

It would be wholly unreasonable to permanently disallow 4

decommissioning costs of this magnitude. The costs are not caused by any imprudence by SCE, and a 5

disallowance violates established ratemaking principles that customers, not shareholders, should be 6

responsible for decommissioning costs. 7

(5) Conclusion 8

For these reasons, the Commission should not disallow any of the 9

approximate $5.3 million of work that has already been performed, nor adopt TURN’s recommended 10

permanent disallowance of San Gorgonio decommissioning costs going forward. The Commission 11

should approve SCE’s current capital expenditure forecast of $6.565 million, as well as allow SCE to 12

make future requests, subject to further review in GRCs. 13

18

III. 1

FOSSIL FUEL GENERATION 2

SCE owns and operates the gas-fired Mountainview Generating Station (Mountainview) 3

combined cycle power plant with a capacity of 1,104 MW (nominal); five combustion turbine Peaker 4

power plants (Peakers) with an aggregate capacity of 245 MW; six diesel engine generators at SCE’s 5

Pebbly Beach Generating Station (PBGS) with a capacity of 9.4 MW, twenty-three 65 kilowatt (kW) 6

propane-fueled micro turbines, and one 1.0 MW energy storage battery; and two Fuel Cell generating 7

plants with a combined total capacity of 1.5 MW.33 SCE’s 2021 Test Year (TY) Fossil Fuel O&M 8

expense forecast consists of $29.251 million (constant 2018 dollars) for Mountainview, $7.624 million 9

for the Peakers, $5.481 million for Catalina, and $0.491 million for Fuel Cell. This funding request is 10

necessary to maintain safe operations for employees and the public, provide reliable service at low cost, 11

and comply with applicable laws and regulations. 12

SCE also forecasts 2019-2023 capital expenditures of $66.618 million (nominal dollars) for 13

Mountainview, $4.900 million for the Peakers and $40.160 million for Catalina. 14

A. Mountainview 15

1. O&M Expenses 16

a) SCE’s Application 17

SCE’s 2021 O&M expense forecast for Mountainview is $29.409 million and is 18

necessary to maintain safe operations for employees and the public, provide reliable service at low cost, 19

and comply with applicable laws and regulations. Table III-8 below provides the Mountainview Test 20

Year O&M expense forecasts proposed respectively by SCE, Cal Advocates, and TURN; variances from 21

SCE’s forecast; and SCE’s rebuttal position. 22


19

Table III-8 Mountainview Generation

2021 O&M Expense Forecast Summary of SCE, Cal Advocates, and TURN’s Positions


b) Intervenors’ Position 1

(1) Cal Advocates’ Position 2

Cal Advocates recommends that SCE’s forecast of Mountainview-related 3

O&M expenses be adopted as proposed by SCE.34 4

(2) TURN’s Position 5

TURN proposes two adjustments to the Mountainview O&M expense 6

forecast. First, TURN proposes applying a 7.3 percent escalation rate to the 2013 major inspection cost 7

used to calculate the 2021 TY forecast for Non-Labor: Major Inspection that results in a forecast 8

decrease of $158,000.35 Second, TURN notes that the operations of the plant are changing and the 9

payments to GE are declining as a result. Instead of using a four-year average (2015-2018), TURN 10

recommends using $2.616 million, a reduction of $0.822 million, based on recent data reflecting the 11

changes to the operations of Mountainview.36 The sum of these two adjustments (respectively $0.158 12

million and $0.822 million) results in a total $0.980 million reduction to the 2021 TY O&M expense 13

forecast for Mountainview. 14


35 Exhibit TURN-09 Generation Marcus page 20.

36 Id. at p. 22, lines 9-10.

SCECal

AdvocatesTURN

Cal Advocates

TURN

1 Fossil Fuel - Mountainview(1) 29,251 29,409 28,429 158 (822) 28,429 1 Fossil Fuel Generation includes an errata for Mountainview O&M forecast.


Line No.

GRC Activity

2021 Forecast Variance from SCE

20

c) SCE’s Position 1

SCE does not oppose TURN’s forecast adjustment recommendation of $0.822 2

million and corrected the escalation rate error with errata.37 SCE and GE are in active negotiations on 3

the future of the Mountainview CSA, which may impact future expenses. 4

2. Capital Expenditures 5


SCE’s forecast of Mountainview capital expenditures totaled $66.618 million for 7

2019-2023 and is required to support reliable service, compliance with applicable laws and regulations, 8

and safe operations for employees and the public. Table III-9 below provides the Mountainview capital 9

expenditures forecast for 2019- 2021 proposed respectively by SCE, Cal Advocates, and TURN; 10

variances between the forecasts; and SCE’s rebuttal position. 11

Table III-9 Mountainview Capital Expenditures

2019-2021 Forecast Summary of SCE, Cal Advocates, and TURN’s Position and SCE’s Rebuttal

Position (Nominal $000)



Cal Advocates recommends that SCE’s forecast of Mountainview 14

generation-related capital expenditures for 2019-2021 be adopted as initially proposed by SCE.38 15

37 Appendix C- Errata.


SCECal

Advocates TURNCal

Advocates TURN1 Fossil Fuel Generation - Mountainview 66,618 66,618 12,618 - (54,000) 14,382

Line No.

GRC Activity2019 - 2021 Forecast Variance from SCE SCE

Rebuttal Position

21


TURN requests adjustment of SCE’s Mountainview capital forecast by 2

$54 million because SCE no longer plans to purchase new turbine rotors that it forecast in its rate case 3

filing, $18 million in 2020 and $36 million in 2021.39 4


(1) 2019 Recorded Expenditures Forecast Update 6

For SCE’s rebuttal position, the 2019 recorded expenditures of $2.992 7

million was used to update the original 2019 forecast of $1.228 million resulting in an increase of 8

$1.764 million. For additional information on the company-wide use of 2019 capital recorded 9

expenditures as the rebuttal forecast, please see SCE-12, Vol. 1. 10

(2) Removal Of Mountainview Rotor Replacement Project 11

While negotiations between SCE and GE regarding the purchase of three 12

spare combustion turbine rotors as required by the GE CSA are on-going, SCE believes that due to 13

changes in the generation operating profile at Mountainview, it is highly unlikely that their purchase will 14

need to occur during this GRC cycle.40 SCE thus does not oppose TURN’s recommendation to remove 15

the Mountainview Rotor Replacement project from SCE’s forecast - $18 million in 2020 and $36 16

million in 2021. 17

B. Peakers 18

1. O&M Expenses 19


SCE’s 2021 Test Year forecast for the Peaker Generation activity is $7.624 21

million, including $3.188 million labor expense, $3.910 million non-labor expense and $0.526 million 22

for other, all needed to operate and maintain its five Peaker plants safely and reliably.41 Table III-10 23

below provides the Peaker Generation Test Year O&M expense forecast proposed respectively by SCE, 24

Cal Advocates, and TURN; variances from SCE’s forecast; and SCE’s rebuttal position. 25

39 Exhibit TURN-09 Generation Marcus, p. 19, lines 3-5.

40 Appendix A - Data Requests, TURN-SCE-073, Question 21.

41 Exhibit SCE-05 Vol. 01, p. 149, lines 2-4.

22

Table III-10 Peaker Generation

2021 O&M Forecast Summary of SCE, Cal Advocates, and TURN’s Positions




Cal Advocates recommends that SCE’s forecast of Peaker generation-3

related O&M expenses for 2019-2021 be adopted as proposed by SCE.42 4


TURN was silent on the Peakers (i.e., no recommendations were made for 6

adjustments for this GRC Activity). 7


SCE maintains its position as filed in application, with 2021 Test Year forecast 9

for the Peaker Generation activity at $7.624 million. The forecast should be adopted as unopposed. 10



SCE’s total Peaker Generation capital expenditure forecast is $2.100 million 13

(nominal) for 2019-2021.43 Table III-11 below provides the Peaker Generation capital expenditures 14

forecast for 2019- 2021 proposed respectively by SCE, Cal Advocates, and TURN; variances from 15


42 Exhibit PAO-09 Generation, Energy Procurement & Wildfire Management Capital, p. 7, lines 22-23, p. 2,

line 5-6.

43 Exhibit SCE-05, Vol. 01, p. 152, lines 18-19.

SCECal

AdvocatesTURN

Cal Advocates

TURN

1 Fossil Fuel - Peakers 7,624 7,624 7,624 - - 7,624

Line No.

GRC Activity2021 Forecast Variance from SCE SCE

Rebuttal Position

23

Table III-11 Peaker Generation

Capital Expenditures 2019-2021 Forecast

Summary of SCE, Cal Advocates, and TURN’s Position (Nominal $000)



Cal Advocates recommends that SCE’s 2019-2021 forecast of Peaker-3

related capital expenditures be adopted without any reductions.44 4


TURN was silent on the Peakers (i.e., no recommendations were made for 6

adjustments in this GRC Activity). 7


For SCE’s rebuttal position, the 2019 recorded expenditures of $2.044 million 9

was used to update the original 2019 forecast of $2.100 million resulting in a small reduction of $0.056 10

million. For additional information on the company-wide use of 2019 capital recorded expenditures as 11

the rebuttal forecast, please see SCE-12, Vol. 1. 12

C. Catalina 13

1. O&M Expenses 14


SCE provides electric service to approximately 4,000 permanent residents and 16

over one million annual visitors on Santa Catalina Island. SCE’s total Catalina Test Year O&M expense 17

44 Exhibit PAO-09 Generation, Energy Procurement & Wildfire Management Capital page 2, lines 7-16.

SCECal

Advocates TURNCal

Advocates TURN

1Fossil Fuel Generation - Peaker 2,100 2,100 2,044 - (56) 2,044


Line No.

GRC Activity2019 - 2021 Forecast Variance from SCE

24

is $5.481 million including $2.880 million labor expense and $2.601 million non-labor expense. Non-1

labor costs include repair parts, chemicals, supplies, contracts and various miscellaneous expenses 2

needed to operate and maintain Catalina’s generation units safely and reliably.45 Table III-12 below 3

provides the Catalina Generation Test Year O&M expense forecast proposed respectively by SCE, Cal 4

Advocates, and TURN; variances from SCE’s forecast; and SCE’s rebuttal position. 5

Table III-12 Catalina Generation 2021 O&M Forecast

Summary of SCE, Cal Advocates, and TURN’s Position (2018 Constant $000)


(1) Cal Advocates Position 7

Cal Advocates recommends that SCE’s forecast of Catalina’s generation-8

related O&M expenses for 2021 be adopted as proposed by SCE.46 9


TURN recommends reducing the non-labor O&M forecast by $0.103 11

million, to remove an atypical outage that is unlikely to occur with repowered or renewable generation 12

after 2021. The total cost of this outage was $0.516 million (2018 dollars). TURN asserts that new 13

generators proposed by SCE will not have this type of failure because they are new and have additional 14

design features to prevent this kind of outage.47 Therefore, TURN recommends reducing the non-labor 15

expense by $0.103 million, (averaging the outage cost over the five year forecast method) for a forecast 16

of $2.498 million, instead of SCE’s $2.601 million Test Year forecast.48 17

45 Exhibit SCE-05 Vol.-01, p. 155, lines 21-22 and 25-27.


47 Appendix A - Data Requests, TURN-73, Question 06.


25


(1) Rebuttal To TURN 2

SCE does not oppose TURN’s recommendation to reduce the 2021 Test 3

Year O&M by $0.103 million for the removal of the atypical outage. 4



SCE’s forecast for Catalina’s Pebbly Beach Generating Station capital 7

expenditures total $40.160 million for 2019-2023, and is required to support reliable service, compliance 8

with applicable laws and regulations, and safe operations for employees and the public. The forecast 9

includes the Catalina Repower project, with an overall project forecast of $34.300 million, comprised of 10

$17.300 million in forecast expenditures in 2019-2021 and $17.000 million in 2022-2023. The 11

remaining $5.860 million includes expenditures for the Pebbly Beach Generating Station resurface 12

paving and a 2.4 kV Switchyard Upgrade projects.49 13

Table III-13 below provides the Catalina capital expenditures forecast for 2019- 14

2021 proposed respectively by SCE, Cal Advocates, and TURN; variances from SCE’s forecast; and 15

SCE’s rebuttal position. 16

Table III-13 Catalina Generation Capital Expenditures


(Nominal $000)

49 SCE-05, Vol. 1, p. 157.

26



Cal Advocates recommends that the Catalina Repower project not be 3

approved at this time, thereby reducing capital expenditures for 2020 and 2021 by $10.4 million and $6 4

million respectively for the planned diesel generator installations at Catalina Island.50, 51 Cal Advocates 5

explains that because the study of options for new and cleaner generation capacity is not expected to be 6

completed until the second quarter of 2020, “the long-term energy supply solution for Catalina Island is 7

currently uncertain.”52 Cal Advocates further states that if SCE does complete the project, SCE may file 8

a separate application to seek cost recovery, but for the purposes of this GRC, Catalina Repower should 9

be removed from the forecast.53 10


TURN makes a non-monetary recommendation that the Commission 12

approve the plants for installation in 2020-2021, but should make no prudence finding on the choice of 13

the diesel units and project costs in the attrition years.54 TURN asserts that the Commission should 14

recognize that a project of some type is required to complete compliance with Rule 1135, but because 15

SCE has presented only one of a number of options for compliance, it must justify the option it chooses 16

in its next general rate case with a cost-effectiveness and environmental analysis recognizing the high 17

cost of diesel oil on the island.55 18

TURN recommends that in the next GRC, SCE bring forward a plan for 19

repowering the remainder of Catalina plants and that the Commission specifically consider a 20

disallowance in the next GRC unless SCE can affirmatively demonstrate that it fully considered all 21

50 Exhibit PAO-09 Generation, Energy Procurement & Wildfire Management Capital, p. 9, lines 18-19. SCE

would like to correct Cal Advocates’ representation of SCE’s forecasts. As presented in Exhibit SCE-05, Vol. 1, page 157, Table III-43, the forecasts for 2020 and 2021 are $5.3 million and $11.5 million respectively, and not the $10.4 million and $6 million.

51 Id., p. 2, lines 9-16.

52 Id., p. 9, lines 17-18.

53 Id., p. 9, lines 19-20.

54 Exhibit TURN-09, p. 23, lines 3-8.

55 Exhibit TURN-09 Generation Marcus p. 25, lines 14-23.

27

options and made a decision that reflected considerations of least cost and lowest environmental 1

impacts.56 2


(1) 2019 Recorded Capital Expenditures Forecast Update 4

SCE’s rebuttal 2019-2021 capital expenditures forecast has been updated 5

for Catalina’s 2019 recorded capital expenditures that were $2.326 million more than forecast. The 6

$2.326 million recorded above forecast was required for costs to complete the Switchyard Upgrade, the 7

Catalina Repower feasibility study and the Resurface Paving projects included in this GRC, as well as 8

other miscellaneous emergent projects.57 The increase to SCE’s original 2019-2021 forecast, originally 9

at $23.160 million, is now presented at $25.486 million in Table III-13 above. For additional 10

information on SCE’s company-wide 2019 capital forecast update, please see SCE-12, Vol. 1. 11

(2) The Catalina Repower Project Should Be Approved In The 2021 12

GRC, As SCE Has Presented Evidence Demonstrating The 13

Reasonableness Of The Project And Forecast, And The Preliminary 14

Feasibility Study Supports SCE’s Conclusion That The Proposed 15

Project Is The Most Commercially Reasonable Option 16

SCE agrees with TURN’s recommendation to approve the plants for 17

installation in 2020-2021. SCE disagrees with Cal Advocates’ recommendation that the Commission 18

defer approval of project funding for the entire project to a separate proceeding after completion and 19

TURN’s recommendation that SCE’s technology choices and capital spending be reviewed in the next 20

GRC. As discussed in further detail below, the project as proposed in this GRC is reasonable and should 21

be approved, based on the evidence presented by SCE. 22

56 Id., p. 23, lines 3-11.

57 Appendix B - Workpapers, 2019 Recorded vs. 2019 GRC forecast summary.

28

(a) Both Cal Advocates And Turn Agree On The Need For The 1

Catalina Repower Project To Comply For Air Quality 2

Regulations 3

SCE presented evidence demonstrating that the project is necessary 4

to meet urgent compliance deadlines under new SCAQMD emission regulations while providing reliable 5

electric services to Island residents, businesses, and visitors. Installation of the new, significantly cleaner 6

diesel engines remains the most feasible and appropriate option available to meet the January 1, 2023 7

SCAQMD compliance deadline for the first NOx reduction target, which states that “[i]f electing to 8

comply with paragraph (d)(2), a minimum of two units, excluding units exempt under paragraph (g)(3), 9

shall meet the emissions limits in Table 2 by January 1, 2023.”58 TURN essentially agrees with this 10

position, noting that it “recogniz[es] that action will need to be taken to reduce nitrogen oxides on 11

Catalina diesel plants.”59 In addition to pursuing this path to help assure compliance, the feasibility study 12

also identified a number of promising locations on the island to site renewable generation 13

(predominately ground-mounted photo-voltaic solar). It is SCE’s intent as a part of this repowering to 14

integrate as much economic renewable energy, demand response and energy efficiency as possible. To 15

this end, SCE has engaged the major landholders on the island to discuss land acquisition, through 16

purchase or lease, to support utility scale renewables projects. To inform these land acquisition 17

discussions, it is also SCE’s intent to solicit through an “All Source” procurement solicitation offers for 18

renewable energy, storage, demand response and energy efficiency to ensure all options to minimize the 19

use of fossil fuel are explored. It is far from certain however whether SCE will be successful in the siting 20

of renewable energy projects, and certainly not on the timing necessary to meet SCAQMD emissions 21

requirements. 22

Therefore, due to the time-sensitive needs to meet SCAQMD 23

emission regulations, SCE determined there is no other reasonable alternative to the project as proposed, 24

a conclusion that is supported by the preliminary feasibility study. SCE must implement the Catalina 25

58 Appendix B – Workpapers, Rule – 1135, p. 1135-7.

59 Exhibit TURN-09 Generation, Marcus, p. 23, lines 3-4.

29

Repower Project, with the first four Diesel Engines forecasted to be in-service by the end of 2022, to 1

meet the January 1, 2023 compliance requirements.60 2

(b) SCE Has Presented Evidence Demonstrating The 3

Reasonableness Of The Project And Forecasted Costs 4

SCE has met its burden to demonstrate the reasonableness of the 5

technology chosen (diesel generators), project plans and schedule, and costs. Both TURN and Cal 6

Advocates recommend the Commission defer approval of the capital spending on this project until a 7

subsequent proceeding. Cal Advocates recommends that the Commission require SCE to submit a 8

separate application identifying generation options, and TURN recommends a requirement for SCE to 9

demonstrate the reasonableness of its technology choices and spending in the next GRC. SCE disagrees 10

with these recommendations. 11

To establish the reasonableness of SCE’s actions and the costs 12

estimated for the project SCE has explained the basis for the project and why it is required. As noted 13

above, SCE must comply with SCAQMD air emissions standards, and it must replace much older 14

generators (dating from 1958, 1963, and 1966) that no longer meet new and increasing clean-air 15

standards. The repowering options SCE considered are summarized below and support SCE’s 16

previously provided project overview regarding: (1) the planned replacement of the existing 9.4 MW 17

six-unit configuration with new and much cleaner diesel generator sets that would be SCAQMD 18

compliant; and (2) an installation schedule over three separate phases (April 2021, April 2022, and April 19

2023). 20

In objecting to approval of the project in this GRC, Cal Advocates 21

and TURN speculate that there may be more reasonable technology alternatives61,62 but offer no 22

evidence to support that speculation. Such speculation is an insufficient basis to withhold approval of 23

this project in this GRC. With a lack of countervailing evidence presented by intervenors, there is no 24

genuine dispute that diesel generator technology meeting SCAQMD air emission requirements is the 25

most technically feasible and commercially reasonable option with the least environmental impacts. 26

60 Exhibit SCE-05, p. 159, Table III-4 Catalina Repower Project Details.


62 Id., p. 9, lines 17-18.

30

In the sections below, SCE discusses additional information from 1

the preliminary feasibility study that supports SCE’s conclusion to execute the proposed repower project 2

and decision to use diesel generators. 3

(3) Feasibility Study 4

As indicated in response to PubAdv-SCE-088-SLJ, Q2,63 SCE partnered 5

with external experts to conduct a comprehensive study to evaluate different options for emissions-6

compliant electricity generation on Catalina Island. The partners were the following: the National 7

Renewable Energy Laboratory (NREL), a national laboratory of the U.S. Department of Energy Office 8

of Energy Efficiency and Renewable Energy; the United States Environmental Protection Agency (EPA) 9

Technology & Partnerships Office Air Division Region 9; and NV5, an engineering consulting firm. 10

The study utilized a quantitative model to evaluate potential candidate 11

technologies, sizes, and dispatch strategies. The model evaluated the life-cycle costs (LCC) of different 12

approaches, which included capital costs, the present value of operating expenses such as fuel costs, 13

operations and maintenance costs, and the present value of any financial incentives and depreciation. 14

The model considered energy demand as well as constraints associated with the different compliance 15

options, such as environmental concerns, land ownership, permitting, constructability and renewable 16

resource availability. SCE is concurrently engaged in negotiations with the island stakeholders towards 17

securing sites for the renewable technologies. Land availability remains a real constraint to the success 18

of the renewable option. 19

(a) Options Evaluated 20

SCE appropriately considered multiple options, as suggested by 21

Cal Advocates and TURN.64, 65 The study evaluated the following approaches: 22

• Interconnection with the mainland via an undersea cable 23

• On-Island Fossil-Fuel Generation, including diesel, propane, 24

and/or liquefied natural gas (LNG) 25

63 Appendix A - Data Requests: PubAdv-SCE-088-SLJ, Q2.


65 Id., p. 9, lines 10-11.

31

• On-Island Renewable Energy (RE) technologies, including 1

solar photovoltaics (PV), wind turbines, and wave energy 2

devices 3

• Battery Energy Storage Systems (BESS) to support renewable 4

technologies 5

Energy Efficiency and Demand Response (EE and DR) 6

(i) Interconnection With The Mainland Via Undersea 7

Cable 8

The undersea cable analysis examined the potential for 9

installing and operating a single 33kV submarine electrical power cable to provide energy from the 10

mainland to Catalina Island. The analysis built upon the previously performed 35.5 mile undersea cable 11

analysis, performed by Padre Associates, Inc. in 2004-2005, as well as the comprehensive land and 12

seafloor surveys conducted by Fugro Pelagos circa 2004 (formerly Thales GeoSolutions Pacific), and 13

the potential land conversion locations and terminal upgrades required at each generating station. 14

(ii) On-Island Fossil-Fuel Generation 15

a. Diesel Engines 16

The emissions-compliant fossil fuel generation 17

analysis evaluated generators of varying capacity ratings and fuel types to replace the existing diesel 18

fleet. The emissions of the replacement generators were evaluated to examine compliance with the limits 19

of South Coast Air Quality Management District Rule 1135 for regulated pollutants.66 Additionally, the 20

engines were evaluated to examine compliance with National Emission Standards for Hazardous Air 21

Pollutants for Stationary Reciprocating Engines (NESHAP), which states that stationary compression 22

ignition engines greater than 500 horsepower must limit CO concentration to less than 23 ppmvd at 15% 23

O2 or reduce CO emissions by 70% or more.67 24

In addition to regulatory compliance, the various 25

engine generator sets were evaluated based on generator output in kilowatts, ramp rate (important to 26

support intermittent renewable generation), operational flexibility, fuel consumption, the ability to 27

66 Appendix B – Workpapers, Rule 1135, p. 1135-5, Section 2 (A).

67 Appendix B – Workpapers, eCFR Table 2d.

32

utilize alternative or blended fuels, weight and dimensions (due to limited space availability at the 1

generating plant), the ability to utilize existing infrastructure, procurement cost, and operations and 2

maintenance costs. 3

b. Liquefied Petroleum Gas (LPG) 4

The LPG (propane) option involves either greatly 5

expanding the existing gas plant or creating a new, offsite storage plant to accommodate the large 6

increase in fuel consumption of an all-propane fleet. Eight new 30 thousand-gallon tanks are required to 7

provide reserves necessary for reliability, in addition to the four 30 thousand-gallon tanks that are 8

currently on site (a total of 12 tanks). 9

Additional infrastructure would be required for fire 10

suppression, per the California Fire Code, to include either a separate off-site fire water tank or a new, 11

larger municipal water line from Wrigley reservoir to either the existing gas plant or to the new off-site 12

storage location. Additionally due to the large increase in on-site storage, the facility may be reclassified 13

as a Program 3 site from a Program 1 site, which would require the development of a Risk Management 14

Program (RMP) to comply with the requirements of an OSHA PSM (Process Safety Management) 15

program along with any associated mitigation measures per 40 CFR Part 68. 16

c. Liquified Natural Gas (LNG) 17

Lastly, LNG fueled engine generators were also 18

evaluated as an alternate to propane or diesel generators. The study indicates LNG to be the most 19

expensive generator option evaluated, with an LCC nearly 50% higher than an all-diesel option, largely 20

driven by higher capital costs for generators and infrastructure upgrades. In particular, the entire existing 21

diesel and propane plant and infrastructure would need to be removed to accommodate an LNG plant. It 22

would be costly and complicated to supply the island with propane and electric service during the 23

cutover period. 24

(iii) On-Island Renewable Energy (RE) Technologies And 25

BESS 26

The renewable energy and storage analyses considered the 27

feasibility of powering the island with some amount of renewable energy supplemented with energy 28

storage. A wide range of renewable energy technologies were evaluated to determine if enough 29

renewable resources existed on the island to justify pursuing a given technology. A detailed siting 30

33

analysis was performed, evaluating more than 40 unique sites across the island based on factors 1

including environmental concerns, land ownership, permitting, constructability, and renewable resource 2

availability. 3

Additionally, an electrical load flow analysis was 4

performed to evaluate the potential impacts and recommended mitigation strategies from attempting to 5

interconnect Distributed Energy Resources (DER) across the island. 6

(iv) Energy Efficiency And Demand Response 7

This section of the feasibility study identified opportunities 8

and provided recommendations to cost-effectively reduce energy usage (kWh) via energy efficiency 9

(EE), peak demand (kW) via Demand Response (DR) and equivalent load management measures and 10

associated emissions. EE/DR opportunities were identified through three primary sources: 11

Desktop utility metered data analysis for all Santa 12

Catalina Island (SCI) customers 13

Reports and other documents provided by SCE or SCI 14

customers 15

SCE RFI responses and interviews with SCE personnel 16

The original Scope of Work (SOW) included site visits and 17

Level 1–2 energy audits by the American Society of Heating, Refrigerating and Air Conditioning 18

Engineers (ASHRAE) at up to ten of the largest energy users on Catalina island. Although these efforts 19

were interrupted by the COVID-19 pandemic, SCE expects that additional opportunities for energy 20

efficiency, demand response, and deferrable loads on the island could be identified. 21

The current outcome of the resulting high-level analysis 22

and conservative assumptions indicate that there is potential to reduce SCI’s total electricity 23

consumption by an estimated 21% via investment in energy efficiency improvements. 24

(4) The Preliminary Feasibility Study Results Support SCE’s 25

Determination That Diesel Engines Are Appropriate To Meet The 26

Urgent Emissions Compliance Deadlines 27

SCE does not see a viable alternative to replacing the engines as proposed. 28

An undersea cable presents significant permitting, construction, and cost challenges. It would be a novel 29

project with significant uncertainty as well as project execution and operational risk. The topography of 30

34

the bottom of the Catalina Channel, steep slope concerns, and seismic considerations, including the 1

2,500 feet depth the cable must traverse, the ability to achieve proper burial depths or install appropriate 2

protective coverings at deep sea depths, and the limited availability of ships with capability to pull cable 3

from that depth, in the event of catastrophic failure, present significant challenges. Most undersea power 4

cable projects in the world are at depths of hundreds, not thousands of feet. The undersea cable project 5

would take many years to complete (likely at least five) and would be the most expensive option by far 6

(likely more than $250 million capital cost). It would not necessarily eliminate the need for SCE to 7

install new on-island generation (i.e. diesel generators) to be available in the event of a mainland outage 8

or failure of the cable. 9

Renewable and battery storage technologies also present significant 10

permitting, construction, and cost challenges. In contrast to diesel generators that can be centrally sited 11

at SCE’s operations center on the island at the same location as the existing generators, potential 12

renewable energy sites are located throughout the island. In addition to the permitting, construction, and 13

cost challenges, the siting of renewable technologies would raise various environmental concerns, land 14

ownership, and operational (integration with existing infrastructure) issues. Further, some diesel 15

generation would still be required as renewables and storage alone would not be able to reliably serve 16

anticipated load. 17

As presented in this GRC, installation of emissions-compliant diesel 18

engines as proposed and forecast in this GRC is the lowest estimated cost option that will meet the near-19

term SCAQMD compliance timeline. Diesel generators allow SCE to utilize existing infrastructure and 20

do not raise the permitting, construction, and cost concerns as the alternatives. It is reasonable to 21

anticipate that the new diesel generators planned for the repower project will be long-lived and reliable. 22

As discussed, SCE still contemplates the longer-term potential to 23

supplement the diesel engines with renewables and battery storage, as regulatory bodies such as the 24

SCAQMD may impose future restrictions or goals related to emissions, renewable utilization, or 25

environmental policy. However, the study illustrated the significant challenges and complexities with 26

that approach. To the extent it could be viable, it would be a much long-term option, and would still 27

require diesel engines to meet immediate emissions requirements as well as to reliably meet the full 28

balance of electric load if and when renewables and storage would be implemented. 29

For these reasons, diesel generators are a prudent and reasonable 30

technology choice for the Catalina Repower Project. Neither Cal Advocates nor TURN expressed 31

35

reservations that forecast costs were unreasonable, rather they both suggested a study to confirm that 1

new clean diesels were the best option. SCE has summarized the preliminary feasibility study above, 2

which supports SCE’s determination to use diesel generators for the project.68 3

d) Conclusion 4

Based on the evidence presented by SCE in its opening and rebuttal testimony, the 5

Commission should not require further evidence to be presented in a separate proceeding or subsequent 6

GRC; the Commission should approve SCE’s selection of diesel generators for the Catalina Repower 7

Project as the commercially reasonable solution to meet Catalina’s electric energy needs and to comply 8

with pending environmental requirements, 9

D. Fuel Cells 10

1. O&M Expenses 11


SCE’s 2021 Test Year non-labor forecast of $0.472 million assumes an average 13

level of performance going forward, and is based on a five-year average (i.e., is based on the average 14

annual expense recorded during 2014-2018).69 Table III-14 below provides the Fuel Cell Test Year 15

O&M expense forecast proposed respectively by SCE, Cal Advocates, and TURN; variances from 16


Table III-14 Fuel Cell Generation 2021 O&M Forecast

Summary of SCE, Cal Advocates, and TURN’s Position (2018 Constant $000)

68 The feasibility study is expected to be published by June 30, 2020.


SCECal

AdvocatesTURN

Cal Advocates

TURN

1 Fossil Fuel - Fuel Cell 490 490 472 - (18) 472

Line No.

GRC Activity2021 Forecast Variance from SCE SCE

Rebuttal Position

36



Cal Advocates recommends that SCE’s forecast of Fuel Cells generation-3

related O&M expenses for 2019-2021 be adopted as proposed by SCE.70 4


TURN proposes a small adjustment to prevent double counting the 6

facilities charges for 2014-2017 included in non-labor expenses, which were then averaged. TURN DR 7

62-1771 identified $0.086 million of these costs in nominal dollars, which translates into $0.091 million 8

in constant 2018 dollars. Removing these costs from the five-year average reduces it by $0.018 million. 9


(1) Rebuttal to TURN 11

SCE does not oppose TURN’s recommendation to reduce 2021 Test Year 12

and 2022 and 2023 each by $0.018 million to correct a double counting resulting from SCE including 13

the interconnection fees in the non-labor cost category. 14

70 Exhibit PAO-09 Generation, Energy Procurement & Wildfire Management Capital, p. 7, lines 22-23, p. 8,

lines 1-2.

71 Appendix A - Data Requests, TURN 62, Question 17.

37

IV. 1

SOLAR 2

1. O&M Expenses 3


SCE owns and operates twenty-five solar generating plants constructed as part of 5

the SCE Solar Photovoltaic Program (SPVP) with a combined total capacity of 67.5 MW (AC). SCE 6

proposed an SPVP Test Year O&M expense of $3.755 million to cover base labor O&M, non-labor 7

O&M, cost of leases and interconnection fees.72 Table IV-15 below provides the Solar Test Year O&M 8

expense forecast proposed respectively by SCE, Cal Advocates, and TURN; variances from SCE’s 9

forecast; and SCE’s rebuttal position. 10

Table IV-15 Solar

2021 O&M Forecast Summary of SCE, Cal Advocates, and TURN’s Position




Cal Advocates recommends that SCE’s forecast for Solar Generation-13

related O&M expenses for Test Year 2021 be adopted as proposed by SCE.73 14


TURN makes no recommendation to change the Solar Generation O&M 16

expenses. 17


73 Exhibit PAO-09 Generation, Energy Procurement & Wildfire Management Capital, p. 7, lines 22-23, p. 8 lines 1-2.

38


SCE’s forecast of $3.755 million for the Test Year 2021 should be adopted. 2



The total SPVP plant capital expenditure forecast is $0.500 million for 2019-5

2023, with $0.100 million forecast for each year.74 Table IV-16 below provides the Solar capital 6

expenditures forecast for 2019- 2021 for SCE, Cal Advocates, and TURN, variances from SCE’s 7

forecast and SCE’s rebuttal position. 8

Table IV-16 Solar Capital Expenditures

2019-2021 Forecast Summary of SCE, Cal Advocates, and TURN’s Position

(Nominal $000)


(1) Cal Advocates Position 10

Cal Advocates recommends that SCE’s forecast for Solar generation-11

related capital expenditures for 2019-2021 be adopted as proposed by SCE.75 12


TURN was silent on the Solar capital expenditures, i.e., no 14

recommendations were made for adjustments in this BPE.76 15


75 Exhibit PAO-09 Generation, Energy Procurement & Wildfire Management Capital, p. 3, Table 9-2.

76 Exhibit TURN-09, p. 1-2. TURN separately recommended that the cost (net book value plus decommissioning) of the Perris SPVP be recovered over six years with no return, truncating SCE’s recovery of Perris SPV capital costs so that SCE’s shareholder would bear approximately 20% of the project’s cost. SCE responds to this recommendation in Exhibit SCE-18, Vol. 3. As explained in further detail in that volume, TURN’s recommendation relies on an incorrect review standard based on hindsight. Under the

(Continued)

39


In early 2019, SCE was notified by the building owner of its intent to replace the 2

entire roof due to leaks that threatened the structural integrity of the building and contents inside. 3

Pursuant to a contractual obligation in the lease to clear the roof for re-roofing at the owner’s request, 4

SCE initiated and completed the removal of the solar system located on the roof. Due to the high cost of 5

re-installation relative to the forecast of market revenue, SCE determined that it did not make economic 6

sense to re-install the panels.77 SCE was able to sell the panels, avoiding additional costs associated with 7

the disposal of the panels had SCE been unable to find a buyer. Table IV-17 below provides the 8

summary of decommissioning expenditures to remove the panels for this project. 9

Continued from the previous page correct review standard, SCE’s actions and decision making in connection with the Perris SPVP facility were reasonable – both when it installed the facility and when it decommissioned the facility.

77 Exhibit SCE-05, Vol. 1, pp. 166, footnote 175.

40

Table IV-17 Perris Facility Decommissioning

Summary of Expenditures (Nominal $000)

d) 2019 Recorded Expenditures Forecast Update 1

For SCE’s rebuttal position, the 2019 recorded expenditures of $3.878 million 2

was used to update the original 2019 forecast of $0.100 million resulting in an increase of $3.778 3

million. For additional information on the company-wide use of 2019 capital recorded expenditures as 4

the rebuttal forecast, please see SCE-12, Vol. 1. 5

41

V. 1

PALO VERDE 2

A. O&M Expenses 3

SCE owns 15.8 percent of Palo Verde Nuclear Generating Station (Palo Verde) Units 1, 2, and 3; 4

the nation’s largest nuclear installation. Palo Verde is located approximately 50 miles west of Phoenix. 5

Arizona. Arizona Public Service Company (APS) is the operating agent for Palo Verde. The rated 6

electrical generating capacities of Palo Verde Units 1, 2, and 3 are approximately 1,346 net MW per 7

unit. SCE’s share of Palo Verde has provided SCE customers with a safe, clean, reliable, and economic 8

source of baseload generation since the mid-1980s.78 9


SCE records all invoiced O&M costs from Palo Verde as non-labor costs. Palo Verde’s 11

corrected Test Year 2021 O&M non-labor forecast of $73.105 million is based on APS’ 2021 budget for 12

Palo Verde that had been prepared by APS in July 2018. After receiving TURN’s testimony, SCE 13

determined that it inadvertently had presented the 2021 Palo Verde O&M non-labor forecast in nominal 14

dollars instead of 2018 constant dollars. The Palo Verde’s O&M forecast in nominal dollars is $78.699 15

million and is $73.105 million in constant 2018 dollars79 SCE has prepared errata to correct Palo 16

Verde’s 2019-2021 O&M non-labor forecast in 2018 constant dollars and has additionally corrected the 17

related testimony. A copy of the errata is in Appendix C. 18

Table V-18 below provides the corrected 2021 Palo Verde O&M forecast; forecasts 19

proposed respectively by Cal Advocates and TURN; the variance compared to SCE’s corrected forecast; 20

and SCE’s rebuttal position. 21


79 $78.699 million (2021$, SCE share) divided by 1.0761 (2018$ to 2021$ Escalation Factor) equals $73.105 million (2018$, SCE share).

42

Table V-18 Palo Verde

2021 O&M Forecast Summary of SCE, Cal Advocates, and TURN’s Positions




Cal Advocates recommends no changes to for Palo Verde’s 2021 O&M expense 3

forecast.80 4


TURN makes multiple recommendations for Palo Verde. The three that are 6

addressed in this testimony are TURN’s recommendations regarding: 1) SCE’s Test Year Palo Verde 7

O&M non-labor forecast; 2) SCE’s share of Palo Verde’s annual NEI membership dues; and 3) Palo 8

Verde water sales revenues. SCE’s rebuttal for these three recommendations follow. TURN’s other Palo 9

Verde related recommendations are addressed in other sections of SCE’s rebuttal testimony.81 10

80 Exhibit PAO-09, p. 3.

81 Other TURN Palo Verde recommendations are address as follows: Participant Credits – see Exhibit SCE-18, Vol. 2, Palo Verde depreciation – see Exhibit SCE-18, Vol. 3, and Palo Verde reduced rate base – see Exhibit SCE-18, Vol. 3.

SCE1 Cal

Advocates1 TURNCal

Advocates TURN2

1 Labor 235 235 235 - - 235 2 Non-Labor 73,105 73,105 71,451 - (1,654) 73,096 3 Other - - - - - - 4 Total 73,340 73,340 71,686 - (1,654) 73,331

1 The application forecast has been corrected from nominal to 2018 constant dollars.2 TURN issues: $1.515M ($5.880M+$1.199M‐$5.564M) O&M non‐labor forecast; $0.139M NEI dues.3 SCE rebuttal O&M non‐labor forecast: $73.105M ‐ $0.009M for NEI dues.

Line No.

Description

2021 Forecast Variance from SCESCE

Rebuttal

Position3

43

(1) TURN Recommends That SCE’s Test Year O&M Non-Labor 1

Forecast Be Reduced for Lower APS Budgets 2

TURN proposes that O&M non-labor spending at Palo Verde be reduced 3

by 7.59% from 2018 actual spending or a reduction of $5,880,00082 resulting in a forecast of $71.590 4

million.83 TURN basis its forecast on its analysis of the APS’ budget issued in July of 2019 covering the 5

years 2019, 2020 and 2021.84 TURN calculates the 7.59% reduction based on the APS budget (in 6

constant 2018 dollars) issued in July, 2020, divided by the 2018 recorded amount, and then applies the 7

percentage reduction to Palo Verde’s 2018 recorded non-labor expenses to calculate their recommended 8

forecast of $71.590 million.85 9

(2) TURN Recommends That SCE’s Share of Palo Verde’s Annual NEI 10

Membership Dues Be Reduced by 50% 11

TURN asserts that, “[t]the Commission has consistently removed half of 12

the costs of the Nuclear Energy Institute for California utilities in recent rate cases, recognizing that the 13

organization has a dual role in promoting nuclear power through public relations and lobbying, while 14

also working to cut costs in the nuclear industry. Edison’s share of NEI costs in the base year 2018 was 15

$278,000. Consistent with Commission precedents, [TURN] recommend[s] removing $139,000 (half of 16

those costs.)”86 17

(3) TURN Recommends That Palo Verde Water Sales Revenues Be 18

Removed From Non-Tariffed Products And Services (NTP&S) And 19

Included In This GRC for Ratemaking87 20

TURN makes three arguments why Palo Verde water sales should be 21

treated as OOR for ratemaking purposes. TURN asserts, “First, Edison is doing nothing. The sale is 22

82 Exhibit TURN-09 Generation Marcus, p. 9, lines 1-2, 5.

83 $71.590 million = 2018 recorded of $77,470 million - $5.880 million.


85 Id., pp.4-9.

86 Id., p. 9, lines 12-17.

87 Id., p. 11.

44

made by APS as the owner of Palo Verde. Edison just passively collects its 15.8%. There is no reason to 1

give incentives for Edison when Edison has made absolutely no effort related to this transaction.”88 2

Second, “It is not reasonable to give Edison shareholders money from another utility’s affiliate 3

transaction where Edison is a passive participant.”89 Third, “Essentially, Edison appears to be putting the 4

revenue into NTPS but not subtracting incremental costs necessary to make the sale, contrary to the 5

NTPS regulations as they exist now.”90 6

3. Rebuttal To TURN’s Positions 7

a) SCE’s Corrected Palo Verde O&M Non-Labor Forecast In 2018 Constant 8

Dollars Was Developed Based On The Best Information Available At The 9

Time It Was Developed, Whereas TURN’s Recommended Reduction Is 10

Based On Previously Unavailable Information 11

As discussed above, SCE served an erratum to correct the Test Year 2021 Palo 12

Verde O&M non-labor forecast from nominal dollars into 2018 constant dollars. TURN’s non-labor 13

O&M forecast of $71.590 million is $1.516 million less than SCE’s corrected O&M non-labor forecast 14

of $73.105 million ($73.105 million - $71.590 million). 15

SCE used the $631.6 million (2021$, 100% share) forecast for 2021 in APS’s 16

2019 Palo Verde Budget Book issued in July 2018, which was APS’s latest approved forecast available 17

to SCE at the time it developed the 2021 Palo Verde O&M non-labor forecast. After deducting 18

forecasted payroll taxes, insurance, and overheads, SCE’s share of the remaining cost was $78.699 19

million (2021$) or $73.105 million (2018$). 20

The remaining difference of $1.516 million between SCE’s corrected forecast and 21

TURN’s is a result of TURN’s use of the updated APS 2020 budget issued in July 2019. In contrast, 22

TURN used the $625.6 million (2020$, 100% share) forecast for 2020 in APS’s 2020 Palo Verde 23

Budget Book as a proxy for Palo Verde’s 2021 forecast. Thus, TURN cherry-picked a lower forecast 24

that was not available to SCE at the time it developed its 2021 Palo Verde O&M non-labor forecast. The 25

forecasting methodologies utilized in GRCs should be principled and any associated forecasting 26

88 Id., p. 12.

89 Id., p.12.

90 Id., p.13.

45

adjustments made during the course of rate case proceedings should be based upon symmetrical 1

principles equally applicable to both utilities and intervenors. To that end, just as it would be unfair for 2

SCE to use a previously unavailable budget increase by APS as the basis for requesting an increase to 3

the Palo Verde forecast mid-stream during this GRC proceeding, it is equally unfair for TURN to use a 4

previously unavailable budget decrease by APS to recommend a reduction to the Palo Verde forecast 5

mid-stream during this GRC proceeding. 6

SCE developed the Test Year 2021 Palo Verde O&M non-labor forecast based on 7

a principled approach using the best information available from APS at the time SCE developed the 8

forecast. SCE’s 2021 forecast is $8.895 million91 lower than both the five-year average cost, and $4.513 9

million92 lower than the 2018 recorded cost, making it a reasonable forecast. The Commission strives for 10

fairness and a balance of risks in rate case proceedings. As a general rule, the Commission should reject 11

TURN’s attempt to selectively use post-GRC-submission data available from APS to justify a lower 12

forecast, when there may be other areas in which post-GRC-submission data available from APS 13

justifying a higher forecast. As such, the Commission should reject TURN’s recommendation to reduce 14

SCE’s forecast based on updated APS forecast information that was not available to SCE until one 15

month before SCE was required to file its GRC application. Instead, the Commission should adopt 16

SCE’s $73,105 million (corrected in 2018 dollars) O&M non-labor forecast. 17

(1) TURN’s Recommended Reduction Of $139,000 For Palo Verde NEI 18

Membership Dues Is Excessive And Unjustified 19

Palo Verde is a member of the Nuclear Energy Institute (NEI), which is 20

the policy organization of the nuclear technologies industry. NEI’s members include domestic and 21

foreign companies that own or operate commercial nuclear power plants, reactor designers and advanced 22

technology companies, architect and engineering firms, nuclear fuel suppliers and service companies, 23

consulting services, manufacturing companies, companies involved in nuclear medicine and nuclear 24

industrial applications, radionuclide pharmaceutical companies, universities, research laboratories, law 25

firms, and labor unions.93 26

91 $8.895M = $81.999M - $73.106M.

92 $4.513M = $77.619M - $73.106M.

93 See nei.org/about-nei, accessed on May 19, 2020.

46

Participation in NEI programs, committees, conferences, and activities 1

helps nuclear utilities to address and resolve issues important to the nuclear industry. These issues 2

include, but are not limited to, regulatory reforms, provision of a stable nuclear fuel supply, management 3

of spent nuclear fuel, and NRC license renewal. In addition, just as NEI took an active role in the 4

Nuclear Regulatory Commission’s determination of the additional security measures that would be 5

required to protect nuclear power plants following the September 11, 2001 terrorist attack, NEI is 6

currently leading an effort to identify and implement health and safety measures to ensure the continued 7

safe generation of nuclear energy in response to the ongoing COVID-19 pandemic. Palo Verde has 8

actively participated in, and directly benefitted from, these types of efforts. Palo Verde would likely 9

have incurred much higher costs than its NEI dues to achieve the same benefits but for its participation 10

in NEI. 11

Whereas in past rate cases, the Commission has ordered that shareholders 12

bear 50% of the cost for NEI membership dues, more recently, NEI has commenced specifying the 13

percentage of its membership dues that are attributable to lobbying expenses. For example, Palo Verde’s 14

invoice for 2018 Annual NEI Membership dues states, “Pursuant to section 6033(e) of the Internal 15

Revenue Code of 1986, NEI has estimated that 2.5% of NEI’s 2020 dues are attributable to lobbying 16

expenses and, therefore, are not deductible as ordinary and necessary business expenses.” In addition, 17

the NEI invoiced amounts include a $10,000 (100% share) voluntary contribution to the Foundation for 18

Nuclear Studies (FNS).94 SCE’s combined share of the 2.5% dues attributed to NEI lobbying expenses 19

plus the FNS contribution is $8,526 (2018$, SCE share). This is the appropriate and reasonable amount 20

that the Commission could remove from SCE’s corrected 2021 Palo Verde O&M non-labor forecast. 21

The Commission should not apply an arbitrary 50/50 rule not tied to NEI’s reporting of what their 22

lobbying costs actually are under the Internal Revenue Code. 23

94 The Foundation for Nuclear Studies, a 501(c)(3) nonprofit, provides information and educational

opportunities for policymakers and the general public about nuclear science and technology, with the objective of promoting sound national policy. In pursuit of its mission, the Foundation sponsors a highly regarded Congressional Briefing Series with forums on a broad spectrum of issues related to nuclear technology, ranging from medical isotopes to the transportation of nuclear materials. The events attract high-quality speakers and seek to provide a balanced presentation of differing perspectives.

47

(2) Palo Verde Water Sales Revenues Are Correctly Classified As Non-1

Tariffed Products And Services (NTP&S) And Should Not Be 2

Included As OOR For Ratemaking As TURN Recommends 3

SCE correctly classified Palo Verde water sales as NTP&S according to 4

D.99-09-070 provides two categories of NTP&S, Passive and Active. NTP&S water sales are 5

appropriately classified as Passive. This means that customers are entitled to 30 percent of Gross 6

Incremental Revenues pursuant to the Gross Revenue Sharing Mechanism (GRSM). 7

As noted, Palo Verde water sales revenues are appropriately accounted for 8

as NTP&S revenue. However, after SCE responded to TURN-SCE-062-Question 28, SCE became 9

aware that the established accounting was incorrectly netting the Palo Verde water sale revenues against 10

O&M expenses, resulting in Gross Incremental Revenues not being shared with customers. SCE will 11

include the non-reported water sales in the 2019 NTP&S report to be filed with the CPUC by June 30, 12

2020. Additionally, SCE will provide customers with their accumulated 30% allocation of the Palo 13

Verde water sales Gross Incremental Revenues in the next Electric Deferred Refund Account (EDRA) 14

submission in January 2021. SCE issued a revised response to TURN-SCE-062, Question 2895 on June 15

2, 2020 to correct the information provided in error. 16

TURN is incorrect in its assumption that the incremental costs of Palo 17

Verde water sales have been inappropriately included in O&M costs borne by customers as opposed to 18

being paid for by shareholders. For the Palo Verde water sales, all incremental costs are paid for by the 19

purchaser (Redhawk Industries). On a monthly basis, APS invoices Redhawk for water transportation 20

and treatment expenses.96 Therefore, there are no incremental costs for SCE to account for and 21

separately charge to shareholders. 22

In sum, SCE complies with D.99-09-070 in classifying Palo Verde water 23

sales as Passive NTP&S and, therefore, TURN’s recommendation to reclassify these revenues as OOR 24

subject to GRC ratemaking should be denied. TURN’s concern that associated incremental costs are 25

being charged to customers is without support. Additionally, SCE will reflect the corrected Palo Verde 26

95 Appendix A - Data Requests, TURN-SCE-062, Question 28 Revised.

96 Appendix B - Workpapers, Sample APS’ April 2020 Invoice (dated May 1, 2020) to Redhawk for Water transportation and treatment.

48

water sales in the 2019 NTP&S report as well as provide customers the accumulated 30 percent of Gross 1

Incremental Revenues in the next EDRA filing. 2

4. Conclusion 3

SCE’s Test Year O&M non-labor rebuttal forecast should be adopted. TURN’s 4

recommendation for a lower amount is based on updated APS budget not available for SCE to use in 5

preparing the O&M non-labor forecast for the application. It would be unfair for the Commission to 6

allow TURN to argue for a lower forecast based upon information from APS that was unavailable when 7

SCE prepared its original forecast, just as the reverse would be unfair. In addition, the correct NEI 8

reduction for NEI lobbying costs that should not be paid for by customers is only $9,000, not $139,000 9

as TURN asserts and has been included in SCE’s rebuttal forecast. Lastly, Palo Verde’s water sale 10

revenue is correctly treated as NTP&S in compliance with D.99-09-070, incremental water sales 11

expenses for transportation and treatment are entirely paid for by the purchaser, and SCE will be 12

crediting customers / ratepayers their Gross Revenue Sharing Mechanism allocation of revenues in the 13

next EDRA proceeding. 14

B. Capital Expenditures 15


As the operating agent for Palo Verde, APS identifies and implements capital projects to 17

support safe operation of the plant to meet regulatory requirements, optimize overall cost-effective plant 18

operation, and provide reliable plant operation. APS has developed and utilized a budgeting and cost-19

control program to implement an optimum level of capital expenditures.97 Table V-19 below provide a 20

summary of the Palo Verde capital expenditures forecast for 2019-2021 with SCE application forecasts, 21

Cal Advocates and TURN’s forecast, and SCE’s rebuttal forecast position. 22


49

Table V-19 Palo Verde Capital Expenditures


(Nominal $000)


Both Cal Advocates and TURN recommend no adjustments to Palo Verde’s capital 2

expenditure forecast.98, 99 3

3. SCE’s Rebuttal To Cal Advocates And TURN’s Positions 4

As provided above in Table V-19, SCE’s rebuttal 2019-2021 capital expenditures 5

forecast has been updated for Palo Verde’s 2019 recorded capital expenditures that were $367,000 less 6

than forecast. For additional information on SCE’s company-wide 2019 capital forecast update, please 7

see SCE-12, Vol. 1. 8

4. Conclusion 9

The 2019-2021 Palo Verde capital expenditures forecast should be approved as Cal 10

Advocates and TURN made no recommendations to modify the forecast. 11

98 Exhibit PAO-09, p. 3.


SCECal

Advocates TURNCal

Advocates TURN1 Palo Verde 111,074 111,074 111,074 - - 110,707

Line No.


2019 - 2021 Forecast Variance from SCE SCE Rebuttal Position

Appendix A

Generation Data Request Responses

A1

DATA REQUEST PAGE(S)

TURN-SCE-072, Question 07. A2 to A8

TURN-SCE-073, Question 21 A9 to A10

TURN-73, Question 06 A11 to A12

PubAdv-SCE-088-SLJ, Q2 A13 to A14

TURN 62, Question 17 A15 to A16

TURN-SCE-062, Question 28 Revised A17 to A18

TURN-SCE-072 Q.07.a

A2

Southern California Edison A.19-08-013 – SCE 2021 General Rate Case

DATA REQUEST SET T U R N - S C E - 0 7 2

To: TURN Prepared by: Lisa DeLorme Job Title: Senior Attorney Received Date: 4/17/2020

Response Date: 5/1/2020

Question 07.a-l: Regarding the Borel project, on SCE-05, Vol. 1, page 53, Note f) states “U.S. Army Corps has initiated condemnation of a portion of the water conveyance canal, which has made the project inoperable.”

a. What is the reason for the condemnation? Please explain in detail.b. Please provide documentation of the condemnation in summary form.c. Has the U.S. Army Corps of Engineers agreed to pay SCE any compensation for the condemnation? If

so, how much compensation does SCE expect to receive for the condemnation, and over what term? Please provide relevant documentation.

d. Are there any negotiations, litigation, or agreements ongoing regarding compensation to SCE for thecondemnation?

i. If negotiations or litigation, please describe the status of the negotiations or litigation in generalterms and estimate relevant timelines for resolution.

ii. If an agreement has been reached, please identify the amount paid over what term and providerelevant documentation.

e. If the Army Corps of Engineers has paid or will pay compensation, how would SCE account for suchcompensation amounts for ratemaking purposes?

f. When did the plant cease operation because of the action of the Corps?g. Please provide an annual estimate of the value of lost generation from the date when the plant ceased

operation until the license renewal in 2046. h. Please identify headwater benefit fees and FERC fees associated with this project in real and nominal

dollars for each year from 2014-2019, inclusive. i. What is the gross plant and accumulated depreciation for the Borel project?j. Please provide annual operation and maintenance expenses for the Borel project for 2014-2019 in real

2018 dollars and nominal dollars, divided into labor and non-labor costs. k. What is the rationale for SCE to assume for purposes of estimating decommissioning expense in this

case that the Army Corps of Engineering will pay nothing toward the decommissioning of Borel (SCE-5, p. 118)

l. At page 114 of the workpapers in WPSCE05, Vol. 1, Book A, there is reference to estimates prepared byCardno for SCE in 2015. Please provide those estimates and the supporting material.

Responses to Question 07.a-l:

A. Regarding the Borel Project, on SCE-05, Vol. 1, page 53, Note f) states “U.S. Army Corps hasinitiated condemnation of a portion of the water conveyance canal, which has made the projectinoperable.” What is the reason for the condemnation? Please explain in detail.

A3

TURN-SCE-072: 07.a-l Page 2 of 6

The Borel Project is a 12 MW hydroelectric project which was originally constructed in the early 1900s and which employs a complex diversion and water-conveyance system from the Kern River to the Borel Powerhouse. A 12-mile diversion canal brings water down-gradient to the power plant.

In the 1950s, the U.S. Army Corps of Engineers constructed a flood control dam located between the original Borel Project canal intake works and the power plant. The dam consists of a main dam and an auxiliary dam, which together created Lake Isabella. Accordingly, much of the canal works now sit on federal land.

When the dam was constructed, SCE and the Army Corps entered into an agreement providing that the Army Corps would permit SCE’s water-conduit piping to run through (i.e. be buried within) the auxiliary earthen dam pursuant to an easement granted to SCE, and would guarantee water delivery to the Borel Project. However, beginning in 2012 the plant has not been able to take in water through the canal intake works and the Borel plant has not generated power since that time.

The Army Corps has determined that the dam is seismically unsafe and presents a danger to the citizens of Bakersfield in the event of a seismic event. Accordingly, they have undertaken a seismic upgrade project to improve the dam. In the fall of 2018, the Army Corps began construction activities and condemned the SCE easement for the canal, rendering SCE’s Borel Project inoperable. SCE and the Army Corps determined that it was not technologically/economically feasible to relocate the water-conduit piping. Elimination of the water-conduit piping eliminated the water supply to the power plant, rendering future generation impossible.

In pursuit of its seismic improvement plan, the Army Corps directed the United States Department of Justice to initiate an action in eminent domain to condemn the SCE easement through/under the dam and remove the water-conduit piping through the dam, and to determine the just compensation that was due to SCE as a result. The eminent domain action is titled United States of America v. 10.7 Acres of Land, More or Less, Situate in Kern County , State of California, and Southern California Edison Company, et al., Case No. 1:18-cv-01295-NONE-JTL, which is currently pending in the United States District Court for the Eastern District of California (the “Eminent Domain Action”).

Concurrently, SCE filed a breach of contract action in the United States Court of Claims, seeking damages due to the generation which has been lost by failure to deliver water to the Borel Project since 2012. That action is titled Southern California Edison Company v. United States, Case No. 1:18-cv-01564-EJD (the “Contract Action”)

B. Please provide documentation of the condemnation in summary form.

On September 21, 2018, the United States government filed its compliant in the Eminent Domain Action, titled United States of America v. 10.7 Acres of Land, More or Less, Situate in Kern County , State of California, and Southern California Edison Company, et al., Case No. 1:18-cv-01295-NONE-JTL, which is currently pending in the United States District Court for the Eastern District of California. The United States filed a Declaration of Taking in the Eminent Domain Action

A4


on September 21, 2018, and deposited $18,000,000 with the Court Registry as estimated just compensation on September 25, 2018.

C. Has the U.S. Army Corps of Engineers agreed to pay SCE any compensation for the condemnation?If so, how much compensation does SCE expect to receive for the condemnation and over whatterm? Please provide relevant documentation.

After having engaged in settlement discussions during the course of the Eminent Domain Action and the Contract Action, the parties have agreed that the just compensation payable by the United States for all claims, including the taking of the property, together with any appurtenant improvements, and for lost past and future generation, shall be $31,000,000, inclusive of interest, attorneys’ fees, and costs. The parties are in the process of executing a stipulated judgment to submit to the court in the Eastern District of California, requesting that the court enter judgment in that amount.

D. Are there any negotiations, litigation or agreements ongoing regarding compensation to SCE for thecondemnation?

(i) If negotiations or litigation, please describe the status of the negotiations orlitigation in general terms and estimate relevant timelines for dissolution.

(ii) If an agreement has been reached, please identify the amount paid over what termand provide relevant documentation.

After having engaged in settlement discussions during the course of the Eminent Domain Action and the Contract Action, the parties have agreed that the just compensation payable by the United States for all claims, including the taking of the property, together with any appurtenant improvements, and for lost past and future generation, shall be $31,000,000, inclusive of interest, attorneys’ fees, and costs. The parties are in the process of executing a stipulated judgment to submit to the court in the Eastern District of California, requesting that the court enter judgment in that amount and order immediate disbursement of the entire amount to SCE.

E. If the Army Corps of Engineers has paid or will pay compensation, how would SCE account for suchcompensation amounts for ratepaying purposes?

To the extent funds received from the Army Corps of Engineers compensate SCE for capital costs (net book value or future decommissioning), SCE will credit the accumulated depreciation reserve thereby reducing amounts to be collected from customers in future rate cases.

F. When did the plant cease operation because of the action of the Corps?

The Borel Project ceased operation in 2012 when the Corps did not supply water under drought conditions. After a period of non-generation, repairs to the facility would have been necessary to re-start its generators if the Corps was ready to supply water. However, by that time SCE had learned that the Corps was going to go forward with the seismic upgrade project and would be acquiring SCE’s easement rights in the canal, ending its ability to be supplied with water. Accordingly, it did not make sense to go forward with those repairs and the plant remained shuttered until the United States filed the condemnation action in 2018.

A5


G. Please provide an annual estimate of the value of lost generation from the date when the plant ceased operation until the license renewal in 2046.

SCE valued past lost generation as follows:

SCE valued future lost generation between 2018 and 2033, when the BLM easement grant was due to expire. SCE’s projections of the present? value of future lost generation over that period, using income, cost and market approaches, ranged from $10.1 to $21 million.

H. Please identify headwater benefit fees and FERC fees associated with this project in real and nominal dollars for each year from 2014-2019, inclusive.

Federal Lands Charges Paid to FERC For 2014: 6,872.82 For 2015: 6,644.48 For 2016: 6,784.12 For 2017: 6,927.54 For 2018: 7,072.85 For 2019: 7,220.04 (SCE has petitioned FERC for a refund of the 2019 fees due to the condemnation action.) Headwaters Benefits Paid (Including FERC Fee) For 2014: 16,264 For 2015: 18,312 For 2016: 16,583 For 2017: 19,199 For 2018: 14,710 For 2019: Invoice has not been received. To calculate these amounts in real dollars we would need to use an inflation factor and a reference year that were not specified in the question.

I. What is the gross plant and accumulated depreciation for the Borel Project?

At the time of retirement in September 2017 the balances were the following:

Gross Plant: $27,368,484

Accumulated Depreciation: $8,700,969

J. Please provide annual operation and maintenance expenses for the Borel Project for 2014-2019 in real 2018 dollars and nominal dollars, divided into labor and non-labor costs.

Lost revenues ($M) 2012 2013 2014 2015 2016 2017 TotalRenewable energy value $0.7 $1.0 $2.6 $1.5 $2.6 $3.0 $11.4Capacity value $0.2 $0.3 $0.3 $0.2 $0.2 $0.2 $1.3Total $0.9 $1.3 $2.9 $1.7 $2.8 $3.2 $12.8

A6


2017 costs were higher than previous years because the Borel - Rebuild Canals and Tunnels Capital project was cancelled in 2017 and all incurred costs ($1,041,125.63) were transferred to O&M.

To calculate these amounts in real dollars we would need to use an inflation factor and a reference year that were not specified in the question.

K. What is the rationale for SCE to assume for purposes of estimating decommissioning

expense in this case that the Army Corps of Engineering will pay nothing toward the decommissioning of Borel? (SCE-5, p. 118).

Federal eminent domain law provides only for recovery of the value of the property taken and not for the recovery of consequential damages or losses. See e.g. United States v. Westinghouse Elec. & Mfg. Co., 339 U.S. 261, 264, 70 S. Ct. 644, 646, 94 L. Ed. 816 (1950); Intertype Corp. v. Clark-Cong. Corp., 240 F.2d 375, 377 (7th Cir. 1957).

L. At page 114 of the workpapers in WPSCE05, Volume 1, Book A, there is reference to estimates prepared by Cardno for SCE in 2015. Please provide those estimates and the supporting material.

The 2015 estimate provided by Cardno was a Class 4 evaluation. Cardno was later asked to revisit their previous evaluation and upgrade it to a more detailed Class 3 analysis so that it would provide a more accurate cost estimate.

In 2017, Cardo estimated the cost of decommissioning at $110.4M (with a range of $99.4M to $132.5M).

Attached are three documents. 1) Borel Hydroelectric Project Decommissioning Conceptual Level Economic Analysis (Final) (04-07-2015); 2) Borel Decommissioning Class 3 Estimate (06-09-2017); and 3) Borel Hydroelectric Project Decommissioning (06-09-2017).

The third document listed above explains in the first paragraph why the estimated decommissioning costs increased from the previous estimate.

TOTAL CONSTANT AMOUNT Fiscal_YearGRC_Activity Core_Sub_Activity LABOR_NONLABOR 2014 2015 2016 2017 2018 2019Hydro Maintenance L 174,911 86,337 48,832 267,084 20,866 28,019 Hydro Maintenance NL 64,370 21,951 24,868 904,599 17,322 8,232 Hydro Operations L 88,845 26,139 33,446 16,200 19,023 5,355 Hydro Operations NL 3,778 7,077 17,783 155 1,554 Grand Total 331,904 141,504 124,929 1,188,039 58,764 41,606

TOTAL NOMINAL AMOUNT Fiscal_YearGRC_Activity Core_Sub_Activity LABOR_NONLABOR 2014 2015 2016 2017 2018 2019Hydro Maintenance L 158,687 79,514 46,432 261,136 20,866 28,828 Hydro Maintenance NL 60,924 20,479 23,020 854,667 17,322 8,232 Hydro Operations L 80,604 24,073 31,802 15,839 19,023 5,510 Hydro Operations NL 3,575 6,603 16,461 146 1,554 Grand Total 303,790 130,668 117,716 1,131,789 58,764 42,569

A7


Cardno’s analysis is summarized as follows:

Item No. Description Quantity Unit Cost/Unit Total

1 Planning, Permitting & Monitoring 1 LS $6,075,000 $6,075,000 2 Engineering and Design 1 LS $2,950,000 $2,950,000 3 Construction Management & Inspection 1 LS $4,200,000 $4,200,000 4 Construction General Conditions 1 LS $18,159,000 $18,159,000 5 Decommission, Powerhouse 1 LS $4,065,000 $4,065,000 6 Decommission, Lower Canal 1 LS $28,402,000 $28,402,000 7 Decommission, Upper Canal 1 LS $15,010,000 $15,010,000

Subtotal Direct Construction Costs $78,861,000 Location Factor 2.00% $1,577,000 Remoteness Factor 0.00% $0 State & Local Taxes 4.00% $3,154,000 Total Direct Construction Costs $83,592,000 Historic Preservation Factor 0.00% $0 Subtotal Construction Cost $83,592,000 Contractor Overhead 7.00% $5,520,000 Contractor Profit 7.00% $5,520,000 Estimated Construction Cost $94,632,000 Contingency 20.00% $15,772,000 Total Estimated Cost of

Construction $110,404,000

Proposed Range

Low End: -10% $99,363,600 High End: +20% $132,484,800

A8

TURN-SCE-073 Q.21

A9

Southern California Edison

A.19-08-013 – SCE 2021 General Rate Case

A10

TURN-SCE-073 Q.06a-b

A11



A12

PubAdv-SCE-088-SLJ Q.02

A13



ooo

A14

TURN-SCE-062 Q.17

A15

Southern California Edison A.19-08-013 – SCE 2021 General Rate Case


To: TURN

Prepared by: Juliet Zabasajja Job Title: Sr.Advisor

Received Date: 4/10/2020


Question 17: The chart on WPSCE05V01BkB. Workpaper 230 shows no interconnection facility expenses in each of the years 2014-2017. Were those costs included in non-labor costs? If so, what were they? Response to Question 17: Yes, the interconnection facility expenses recorded in “non-labor” rather than “other” for the years 2014 thru 2017. In 2018, and going forward, the expenses correctly recorded and have been forecasted within the “other” category. The following table provides the interconnection facility expenses for the years 2014 thru 2017.

University 2014 2015 2016 2017 Grand TotalCSU San Bernardino $12,823 $12,823 $18,906 $25,318 $69,870USC Santa Barbara $5,771 $3,523 $3,432 $3,432 $16,159Grand Total $18,595 $16,346 $22,338 $28,750 $86,029

A16

TURN-SCE-062 Q.28 Revised

A17

Southern California Edison A.19-08-013 – SCE 2021 GRC


To: TURN

Prepared by: BOB BLEDSOE Job Title: Senior Advisor Received Date: 5/20/2020


Question 28 Revised: Please provide the amount of revenue from water sales from Palo Verde to the Redhawk plant or any other powerplant in each year from 2014 to 2018 and as forecast in 2021 in real and nominal dollars. Explain how the revenue from these sales is accounted for. Response to Question 28 Revised: After submitting the original response to TURN, SCE became aware that the established accounting was incorrectly netting the Palo Verde water sale revenues against O&M expenses (i.e., was reducing O&M expense). SCE will disclose the non-reported Palo Verde water sales in the 2019 Non-Tariff Products & Services (NTP&S) report to be filed with the CPUC around the end of June 2020. Additionally, SCE will provide customers their accumulated 30% revenue allocation of Palo Verde water sales with interest in the next Electric Deferred Refund Account (EDRA) filing in January 2021. SCE’s accounting treatment will be corrected for 2020 sales and will be handled the correct way going forward. The amounts provided below are the total APS water sales revenue and SCE’s share for 2014-2018 in nominal dollars. SCE’s share is 15.8%, annual amounts vary because of invoicing lags, year-end accruals, and accrual reversals.

2014 - $2,503,000 (Total), $395,474 $381,018 (SCE Share) 2015 - $2,527,000 (Total), $399,266 $388,649 (SCE Share) 2016 - $3,056,000 (Total), $482,848 $474,888 (SCE Share) 2017 - $2,789,000 (Total), $440,662 $434,368 (SCE Share) 2018 - $2,787,000 (Total), $440,346 $446,298 (SCE Share) Forecast 2021 – $3,005,000 (Total), $474,790 (SCE Share)

In accordance with GAAP (Generally Accepted Accounting Principles), water sales are recognized on the books as a revenue stream and are not used to offset O&M expenses incurred in the production of water. As discussed above, SCE’s accounting will be corrected for 2020 and forward. All values are in nominal (year of expense) dollars. SCE has not calculated these amounts in real dollars (e.g., constant 2018 dollars).

A18

Appendix B

Workpapers

B1

Workpapers PAGE(S)

Catalina Diesel 2019 Recorded vs. 2019 GRC forecast summary.

B2 to B3

Rule – 1135-1 to 1135-15 B4 to B19

eCFR Table 2d B20 to B21

Sample APS’ April 2020 Invoice (dated May 1, 2020) to Redhawk for Water transportation and treatment.

B22 to B23

Catalina Diesel

2019 Recorded vs. 2019 GRC Forecast

B2

Rule - 1135

B4

eCFR Table 2b

B20

Sample APS’ April 2020 Invoice (dated May 1, 2020) to Redhawk for Water transportation and treatment

B22

Appendix C

Errata

C-1

Errata PAGE(S)

SCE-05, Vol. 1, Generation

Cover page

pp. 3E, 121E, 133E, 134E, 137E, 176E,

179E, 180E, 181E

C2 to C11

GENERATION

C2

ERRATA

E

e.g.

Table I-1 Generation Business Planning Group - Operations and Maintenance Expenses

2014-2018 Recorded and 2019-2021 Forecast (Constant 2018 $000)

C3

156,019 159,111 161,970

77,349 75,241

42,847

$161,970

73,340

E

i.e.,

C4

29,251

29,251

E

Table III-40 CSA Scope Maintenance/Replacements Comparison

C5

29,251

E

Figure III-6 Mountainview - Operations and Maintenance Expenses

2014-2018 Recorded and 2019-2021 Forecast (Constant 2018 $000)

•

•

•

LaborNon-Labor - BaseNon-Labor: Major Insp.Other

C6

3,175

29,251

29,251 43

E

i.e.,

i.e.,

i.e.,

i.e.,

C7

3.175 9.526

9.526

E

i.e.

e.g.

e.g.

C8

$73,340

E

Figure V-15 Palo Verde O&M Expense

2014-2018 Recorded and 2019-2021 Forecast180 (Constant 2018 $000, SCE Share)

LaborNon-Labor

Other

C9

77,349 75,241 73,340

77,114 75,006 73,105

E

C10

73.1054.365

8.894

less

E

C11

E

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