document in exhibit...s. handschin j. rumble j. tran t. ware (u 338-e) 2015 general rate case...

Application No.: A.13-11-003 Exhibit No.: SCE-18 Witnesses: T. Champ

T. Condit T. Edeson R. Fisher S. Handschin J. Rumble J. Tran T. Ware

(U 338-E)

2015 General Rate Case

Rebuttal Testimony

PUBLIC

Generation

Before the

Public Utilities Commission of the State of California

Rosemead, CaliforniaSeptember 2014

SCE-18: Generation

Table Of Contents Section Page Witness

-i-

I.� PALO VERDE NUCLEAR GENERATING STATION ..................................1 T. Champ�

A.� SCE’s Position .......................................................................................1�

B.� ORA’s Position ......................................................................................1�

C.� SCE’s Rebuttal to ORA’s Position ........................................................1�

1.� SCE Met The Burden of Proof And Should Not Be Required To Summarize Billing Information Provided To ORA As Part Of ORA’s Independent Review .......................................................................................2�

2.� ORA’s Review Of The 2012 Annual Audit Report Should Be Limited To This GRC ..............................................2�

3.� ORA’s Review Of The Nuclear Administrative And Technical Manual (NATM) Project Should Be Limited To This GRC ................................................................3�

4.� As Participant Owner Of PVNGS, SCE Is Not In A Position To “Ensure” That Commission-Authorized Palo Verde Forecasts Are Spent On The Same Projects .......................................................................................3�

II.� POWER PROCUREMENT ...............................................................................5 J. Tran�

A.� Introduction ............................................................................................5�

B.� Power Procurement Business Unit Capital Expenditures ......................5�

1.� Installation And Configuration Of Communication Equipment Is Essential To SCE’s Operations Of The Grid .....................................................................................5�

2.� ORA’s Position ..........................................................................6�

3.� SCE’s Rebuttal To ORA Position ..............................................6�

C.� SBUA’s Discussion On SONGS-Related Concerns And Small Renewable Program Funding Is Not Within The Scope Of This Proceeding .....................................................................7�

III.� POWER PRODUCTION GENERATION POLICY.........................................8 T. Ware�

SCE-18: Generation

Table Of Contents (Continued) Section Page Witness

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A.� SCE Application And The Positions Of The Parties .............................8�

B.� SCE Rebuttal Summary .........................................................................9�

1.� TURN Errs In Attempting To Perform An Accelerated Analysis Using Unadjusted 2013 Recorded O&M Expense Data .................................................10�

2.� ORA Draws Incorrect Conclusions From PPD Staffing Level Changes ............................................................12�

3.� The ORA Request For Department Spending To O&M And Capital Accounts Would Not Result In Meaningful Information ...........................................................12�

4.� The ORA Recorded “Rate Base” O&M Spending Trend Graph Is Misleading ......................................................14�

5.� ORA Presents An Incomplete Assessment Of Recorded O&M Expense As Compared To Previous GRC Authorized Funding Levels ............................................15�

6.� The Hydro, Mountainview & Peakers Test Year 2015 Forecasts Are Less Than 2009 GRC And 2012 GRC Authorized And Is Fully Consistent With Recorded Expense ....................................................................19�

IV.� MOHAVE GENERATING STATION O&M.................................................20�

A.� SCE's Application ................................................................................20�

B.� Summary Of Parties’ Positions By FERC Account .............................20�

C.� ORA's Position .....................................................................................21�

D.� SCE’s Rebuttal .....................................................................................22�

1.� ORA Incorrectly Characterizes The Scope And Purpose Of SCE's Forecast For Managing The Decommissioned Power Plant .................................................22�

2.� ORA Erroneously Assumes That SCE Can Quickly Divest Its Ownership Share Of The Decommissioned Power Plant Site ..........................................22�

SCE-18: Generation


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V.� HYDRO O&M AND CAPITAL .....................................................................24 T. Condit�

A.� Hydro O&M .........................................................................................24�

1.� SCE’s Application ...................................................................24�

2.� ORA’s Position ........................................................................24�

3.� TURN’s Position ......................................................................25�

4.� Position Summary ....................................................................25�

5.� SCE’s Rebuttal To ORA ..........................................................27�

a)� ORA’s Use Of Last Recorded Year Is Inconsistent With Commission Forecast Guidance And Ignores Year-Over-Year Fluctuations That Substantiate The Use Of An Average ..................................................................28�

b)� ORA’s Review Of The PA Consulting Benchmarking Study Is Incomplete .............................32�

6.� SCE’s Rebuttal To TURN .......................................................34�

a)� SCE Accepts TURN’s $0.083 Million Reduction To The FERC Account 536 Hydro Fees Forecast ....................................................34�

b)� TURN’s Forecasting Methodology Using of 2013 Recorded-Unadjusted Expenses Is Flawed and Contains Numerous Errors .......................35�

c)� TURN’s Assessment That SCE Recorded The Same $0.121 Million In Hydro And Claims FERC Accounts Is Incorrect ............................36�

d)� TURN Errs In Its Assumption That San Gorgonio Expenses Are No Longer Recoverable by Ratepayers ..........................................36�

B.� Hydro Capital .......................................................................................37�


2.� ORA’s Position ........................................................................37�

SCE-18: Generation


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4.� SCE Will Adopt 2013 Recorded Expenditures ........................38�

5.� SCE’s Rebuttal To ORA ..........................................................38�

a)� SCE Accepts ORA’s Recommended Adjustments Due To The Cancellation Of The Mammoth Pool Fishwater Generator Replacement Project ....................................................38�

b)� ORA’s Adjustment For 2014 Completed Projects Is Premature And Fails To Capture All Project Costs ..........................................................39�

c)� Considering The Current Expenditure Level Of A Project Alone Cannot Provide An Accurate Correlation As to Whether A Project Is Either “On” Or “Off” Schedule ...................40�

d)� Contingencies For Hydro Projects Are Consistent With Association For The Advancement Of Cost Engineering (AACE) Guidelines ....................................................................41�

e)� San Gorgonio Decommissioning Is Necessary To Maintain Compliance With FERC Requirements ....................................................43�

VI.� MOUNTAINVIEW O&M AND CAPITAL ...................................................44 T. Ware�

A.� Mountainview O&M ............................................................................44�

1.� SCE Application ......................................................................44�

2.� ORA Position ...........................................................................46�

3.� TURN’s Position ......................................................................47�

4.� Parties’ Positions By FERC Account ......................................48�

5.� Parties’ Positions By Forecast Cost Component .....................49�

6.� SCE Rebuttal To ORA and TURN’s Adjustments To The Base O&M Forecast Component ................................51�

SCE-18: Generation


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a)� SCE Accepts TURN’s Proposal To Move Added Facilities Costs From Non-Labor To Other ............................................................................51�

b)� TURN’s Forecast for FERC Account 549 Contains Significant Errors Because Of Limitations Inherent In Using 2013 Recorded-Unadjusted Expense Data ............................51�

c)� ORA’s Base Forecast For FERC Account 554 Non-Labor Expense Is Not Sufficient to Fund Annually Recurring Maintenance Expenses ......................................................................53�

7.� SCE’s Rebuttal To ORA And TURN’s Adjustments To The CSA Annual Fees And CSA Major Outage Fees ..........................................................................................54�

a)� SCE Agrees With Using 2013 Recorded And The TURN 2014-2017 Forecast For The CSA Escalation Factors ........................................55�

b)� SCE Accepts The TURN Forecast For All CSA Fees .....................................................................55�

c)� SCE’s Revised Forecast For The CSA Major Outage Fees Is Now Less Than ORA’s Proposed Forecast ........................................................55�

d)� ORA Erroneously Throws Out 2008 and 2012 Data To Forecast The CSA Variable Fee Portion Of The Annual Fee Based On Incorrect Assumptions .................................................56�

8.� SCE Accepts The TURN Forecast For The Non-CSA Overhaul Cost Component ..............................................58�

B.� MOUNTAINVIEW CAPITAL ...........................................................59�


2.� ORA’s Position ........................................................................59�


SCE-18: Generation


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VII.� PEAKERS O&M AND CAPITAL ..................................................................60 T. Condit �

A.� PEAKERS O&M .................................................................................60�


2.� ORA’s Position ........................................................................60�

3.� TURN’s Position ......................................................................60�


5.� SCE’s Rebuttal to ORA ...........................................................63�

a)� SCE Combined FERC Accounts To Streamline Its Showing ................................................63�

b)� ORA’s Use Of LRY For Forecasting Labor Expenses in Maintenance Account 554 Fails To Capture O&M Expenses That Will Be Incurred During The Test Year ....................................64�

c)� ORA Underestimates The Increased O&M Expenses Related To The McGrath Peaker In The Test Year ..........................................................64�

(1)� SCE’s Forecasting Method For The McGrath Peaker Is Reasonable Given That McGrath Operated For Only A Portion Of The Year ............................64�

(2)� ORA’s Forecasting Method For McGrath Is Flawed ..........................................65�

6.� SCE’s Rebuttal To TURN .......................................................67�

a)� TURN Errs In Attempting To Perform An Accelerated Analysis Using 2013 Recorded-Unadjusted Expense Data ............................................67�

b)� SCE Agrees With TURN’s Added Facility Charges Adjustment .....................................................67�

B.� PEAKERS CAPITAL ..........................................................................67�


SCE-18: Generation


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2.� ORA’s Position ........................................................................68�

3.� SBUA’s Position ......................................................................68�



6.� SCE’s Rebuttal To SBUA ........................................................69�

VIII.� SOLAR PHOTOVOLTAIC PROGRAM ........................................................72 S. Handschin�

A.� SCE’s Application ...............................................................................72�

B.� SPVP Program O&M Expenses...........................................................72�

1.� ORA’s Position ........................................................................72�

2.� TURN’s Position ......................................................................72�


4.� SCE’s Rebuttal .........................................................................73�

a)� SCE’s Forecast Is Based On SCE’s Operational Experience With The SPVP Program And Recorded Costs ......................................74�

b)� ORA’s Reliance On The US Most Contract To Develop A Forecast Is Misplaced...........................75�

c)� SCE Accepts TURN’s Recommendation For Moving The Added Facility Costs To “Other” .........................................................................77�

d)� TURN’s Forecast Does Not Include All SPVP Facilities ............................................................77�

C.� SPVP Capital Expenditures .................................................................79�

1.� ORA’s Position ........................................................................79�

2.� SCE Rebuttal ............................................................................79�

D.� SPVP Reasonableness Review ............................................................79�

SCE-18: Generation


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1.� ORA’s Position ........................................................................79�

2.� SCE Rebuttal ............................................................................79�

a)� SCE’s Decision to Terminate the SunPower Contract Was Prudent ..................................................79�

IX.� FUEL CELL PROGRAM ................................................................................85 J. Rumble�

A.� SCE’s Application ...............................................................................85�

B.� ORA’s And TURN’s Positions ............................................................85�

C.� SCE’s Rebuttal .....................................................................................86�

1.� CSUSB Fuel Cell LTSA O&M Expense .................................86�

2.� Fuel Cell Program Labor Expense ...........................................87�

X.� CATALINA .....................................................................................................89 T. Edeson�

A.� SCE’S Application ...............................................................................89�

B.� ORA And TURN’s Recommendations On O&M Expense .................89�

C.� SCE’s Rebuttal On ORA’s Proposed Reductions To O&M Expense ................................................................................................90�

D.� ORA And TURN’s Recommendations On Capital Expenditures ........................................................................................91�

E.� SCE’s Rebuttal To TURN ...................................................................91�

1.� SCE Provided Valid Explanations For Project Delays ......................................................................................91�

2.� SCE Followed Correct Accounting For AFUDC And Property Tax .....................................................................92 R. Fisher�

3.� SCE’s Accounting For AFUDC Is Compliant And Appropriate ..............................................................................92�

4.� Recovery Of Property Tax Is Appropriate ...............................94�

Appendix A Power Procurement .....................................................................................�

SCE-18: Generation


-ix-

Appendix B Power Production Generation Policy ..........................................................�

Appendix C Mohave ........................................................................................................�

Appendix D Hydro ...........................................................................................................�

Appendix E Mountainview ..............................................................................................�

Appendix F Peakers .........................................................................................................�

Appendix G Solar Photovoltaic Program (SPVP) ...........................................................�

Appendix H Fuel Cell Program .......................................................................................�

Appendix I Catalina .........................................................................................................

SCE-18: Generation

List Of Figures Figure Page

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Figure III-1 Mountainview 2006–2012 Recorded O&M Expense ($000) ($2012) ...................................17�

Figure III-2 Hydro 2006–2012 Recorded O&M Expense ($000) ($2012) ................................................19�

Figure V-3 SCE Hydro Recorded/Adjusted O&M Non-Labor Expenses by FERC

Account ($000) ($2012) ......................................................................................................................30�

Figure V-4 2011 PA Consulting Hydro Benchmarking Report: FERC Form 1 2011 O&M

Expense ($/MWh) ................................................................................................................................34�

Figure V-5 Construction Project Spending Pattern ...................................................................................41�

Figure VI-6 Mountainview Annual FFH ...................................................................................................58�

Figure VIII-7 SPV Panel Pricing Trends (Provided by ORA) .................................................................82

SCE-18: Generation

List Of Tables Table Page

-xi-

Table III-1 Power Production Department Test Year 2015 O&M Expense Forecast

($Million) ($2012) .................................................................................................................................8�

Table III-2 Power Production Department 2013-2015 Capital Expenditure Forecast

($Million) ($Nominal) ...........................................................................................................................9�

Table III-3 2008-2012 GRC Authorized vs. Recorded O&M Expense .....................................................16�

Table IV-4 TY 2015 O&M Position Comparison by FERC Account (SCE Share) ($000)

($2012) .................................................................................................................................................21�

Table V-5 TY 2015 O&M Position Comparison ($000) ($2012) .............................................................26�

Table V-6 TY 2015 O&M Position Comparison by FERC Account ($000) ($2012) .............................27�

Table V-7 SCE Hydro O&M Recorded/Adjusted Non-Labor Expenses by FERC Account

($000) ($2012) .....................................................................................................................................29�

Table V-8 Hydro TY 2015 O&M Non-Labor Forecast Method Comparison ($000)

($Nominal) ...........................................................................................................................................31�

Table V-9 2013-2015 Capital Forecast Comparison ($000) ($Nominal) .................................................38�

Table VI-10 TY 2015 O&M Position Comparison by FERC Account ($000) ($2012) ..........................49�

Table VI-11 TY 2015 O&M Position Comparison by Forecast Component ($000)

($2012) .................................................................................................................................................50�

Table VI-12 FERC Account 554 Non-Labor Expenses During Non-Overhaul Years

($000) ($2012) .....................................................................................................................................53�

Table VI-13 Total CSA Fees Forecast ($000) ($2012) ............................................................................54�

Table VI-14 CSA Variable Fee Forecast Comparison ($000) ($2012) ....................................................57�

Table VII-15 TY 2015 O&M Position Comparison ($000) ($2012) ........................................................62�

Table VII-16 TY 2015 O&M Position Comparison by FERC Account ($000) ($2012) .........................63�

Table VII-17 2013-2015 Capital Position Comparison ($000) ($Nominal) .............................................69�

Table VIII-18 TY 2015 O&M Position Comparison by FERC Account ($000) ($2012) .........................73�

Table VIII-19 SCE Forecast O&M Expenses Not Covered in a Third Party O&M

Contract (All Costs Shown in $2012) ..................................................................................................76�

Table VIII-20 Intra-Company Transfers From the Solar Photovoltaic Program (SPVP) for

Ongoing Maintenance Expenses (Based on 2012 Rate of 0.38%) ......................................................78�

SCE-18: Generation

List Of Tables (Continued) Table Page

xii

Table VIII-21 Contract Termination Savings Based on 2011 Program Size of 250 MW .........................83�

Table VIII-22 Realized Savings Based on Final Program Size of 91.4 MW ............................................84�

Table IX-23 TY 2015 O&M Position Comparison ($000) ($2012) ..........................................................86�

Table X-24 TY 2015 O&M Position Comparison ($000) ($2012) ...........................................................90

1

I. 1

PALO VERDE NUCLEAR GENERATING STATION 2

A. SCE’s Position 3

SCE forecasts $73.8 million for Palo Verde Nuclear Generating Station (PVNGS) O&M 4

expenses for Test Year 2015 and $94.8 million for capital expenditures from 2013 through 2015. 5

B. ORA’s Position 6

ORA did not dispute SCE’s Test Year 2015 O&M forecast. ORA stated, “Based on review of 7

SCE’s testimony, workpapers, and the data request responses discussed above, ORA accepts SCE’s 8

PVNGS O&M forecast for TY2015.”1 ORA also did not dispute SCE’s forecast of capital expenditures 9

from 2013 through 2015. ORA discussed two of Palo Verde’s capital projects and determined that 10

SCE’s forecast for both projects “appears reasonable.”2 11

However, ORA makes four recommendations unrelated to SCE’s 2015 Test Year request: (1) 12

“SCE revisit the issue of the invoice and billing process, and the level of detail that should be made 13

available by SCE (through APS),”3 (2) “ORA reserves the right to address these unresolved audit issues 14

when the information is available, whether in this GRC or the next,”4 (3) “SCE provide a detailed report 15

on the completed NATM project and final spending in the next GRC;”5 and (4) “SCE report in the next 16

GRC how SCE ensures that authorized PVNGS capital budgets are spent on the projects authorized by 17

this Commission.”6 18

C. SCE’s Rebuttal to ORA’s Position 19

ORA did not dispute SCE’s forecast of Palo Verde O&M or capital. SCE’s forecast should be 20

adopted. 21

ORA’s four other recommendations regarding Palo Verde should not be adopted for the reasons 22

discussed below. 23

1 ORA-05, p. 5, lines 11-13. 2 ORA-05, p. 6, lines 3-4. 3 ORA-05, p. 6, lines 20-22. 4 ORA-05, p. 7, lines 14-16. 5 ORA-05, p. 8, lines 7-8. 6 ORA-05, p. 8, lines 8-10.

2

1. SCE Met The Burden of Proof And Should Not Be Required To Summarize Billing 1

Information Provided To ORA As Part Of ORA’s Independent Review 2

In December 2013, ORA submitted a data request to SCE that stated, “Referring to p. 2, 3

Figure 1-1, provide SCE’s annual payments for O&M to APS for 2008-2012...”7 SCE timely provided 4

the requested information. As part of that data request response, SCE explained, “SCE does not make 5

annual payments to APS, rather SCE receives weekly invoices (accruals) and a monthly true up to 6

record the actual costs that were incurred during the month.”8 These weekly invoices were provided to 7

ORA in December 2013 and January 2014. ORA now argues, “The data received from SCE is rather 8

voluminous and raw.”9 SCE simply provided the information that was requested. Until SCE received 9

ORA’s testimony, SCE was unaware that ORA was not satisfied with the data provided. ORA did not 10

submit a follow up data request or discuss the issue with SCE. If ORA had raised the issue with SCE, 11

SCE would have provided the data (if available) in a manner satisfactory to ORA. Further, SCE 12

provided workpapers10 with the details of the costs reflected in the chart referenced in ORA’s data 13

request. In light of these facts, ORA’s recommendation to “revisit the issue of the invoice and billing 14

process” should be rejected. 15

2. ORA’s Review Of The 2012 Annual Audit Report Should Be Limited To This GRC 16

In a data request, ORA asked SCE to provide the annual audit reports for years 2008-17

2012. As of November 2013, SCE had provided the audit reports for years 2008-2011.11 SCE replied to 18

ORA’s data request and stated that the audit report for 2012 would not be issued until approximately 19

July 2014, and offered that it could be requested at that time.12 ORA did not subsequently request the 20

information. As such, SCE was unaware that ORA still had interest in the audit report. ORA now 21

requests the right to address any unresolved audit issues either at the time the 2012 audit is provided by 22

SCE or in the next GRC. 23

7 DRA-038-SJL, Q. 4. 8 Response to data request DRA-038-SJL, Q. 4. 9 ORA-05, p. 6, lines 16-17. 10 SCE-02, Vol. 3, pp. 8-107. 11 Response to data request DRA-038-SJL, Q. 6. 12 Response to data request DRA-290-SJL, Q. 1.

3

Upon reviewing ORA’s testimony, SCE learned that ORA did want the audit report and 1

as such, SCE sent ORA the 2012 audit in DRA-301-SJL Revised Question Supplemental. 2

In light of these facts, ORA’s request to address any unresolved audit issues in the next 3

GRC should be rejected. 4

3. ORA’s Review Of The Nuclear Administrative And Technical Manual (NATM) 5

Project Should Be Limited To This GRC 6

ORA requests that SCE provide in the next GRC cycle a detailed report containing 7

project details and final costs of the NATM project. ORA stated that the Commission authorized the 8

capital spending of $3.8 million in the 2012 GRC but had required SCE to ensure the authorized 9

spending was used for this project. ORA misconstrues the Commission’s finding. 10

In Decision 12-11-015, the Commission directed SCE to “ensure that the NATM 11

replacement project is completed in a timely manner and that the authorized funds are not diverted to 12

some other project at Palo Verde.” In SCE’s direct testimony,13 it is clear that the authorized amount of 13

$3.8 million has been spent on the NATM project. It is also clear that trailing costs to finalize this 14

project will occur through 2015 at which time, the project will be concluded. As such, SCE is seeking 15

approval of the project costs in this GRC cycle and will not include this project in the next GRC. 16

SCE has fulfilled the Commission’s request to ensure the project is completed in a timely 17

manner and that the authorized funds were not diverted to another project. ORA does not recommend a 18

disallowance for this project or claim that SCE was negligent in overseeing the project. Rather, ORA 19

requests that SCE provide information in the next GRC cycle that is outside of the next GRC scope. The 20

Commission should reject this request. 21

4. As Participant Owner Of PVNGS, SCE Is Not In A Position To “Ensure” That 22

Commission-Authorized Palo Verde Forecasts Are Spent On The Same Projects 23

Finally, ORA recommends the Commission require SCE to report in the next GRC how 24

SCE ensures that authorized PVNGS capital budgets are spent on the projects that are authorized by the 25

Commission. SCE is a participant owner, not the owner operator of Palo Verde. As stated in SCE’s 26

direct testimony, “APS identifies and implements capital projects as necessary to support safe operation 27

of the plant to meet regulatory requirements, optimize overall cost-effective plant operation, or to 28

continue to increase reliable plant operation. APS has developed and utilized a budgeting and cost-29

13 SCE-02, Vol. 3, p. 19, Table IX-2.

4

control program to implement an optimum level of capital expenditures.”14 Therefore, SCE is not in a 1

position to “ensure” that Commission-authorized Palo Verde forecasts are spent on the same projects. 2

Further, as discussed by Mr. Litzinger in SCE-01, utility management needs the flexibility to spend the 3

overall authorized revenue requirement based on emerging priorities. Therefore, the Commission should 4

reject this request. 5

14 SCE-02, Vol. 3, p. 10, lines 5-8.

5

II. 1

POWER PROCUREMENT 2

A. Introduction 3

This volume presents SCE’s rebuttal to the recommendations raised by the Office of Ratepayer 4

Advocates (ORA) and Small Business Utility Advocates (SBUA) related to SCE’s 2015 General Rate 5

Case (GRC) forecast for Power Procurement. All recommendations related to SCE’s Operational 6

Excellence savings have been consolidated and are addressed in SCE-28 and are therefore excluded 7

from this exhibit. This chapter is composed of the following sections: 8

� Section B - Power Procurement Business Unit Capital Expenditures 9

� Section C - Other Issues 10

B. Power Procurement Business Unit Capital Expenditures 11

1. Installation And Configuration Of Communication Equipment Is Essential To 12

SCE’s Operations Of The Grid 13

As stated in SCE-02, Vol. 4, SCE requires the installation of specialized communication 14

equipment on every utility-owned and contracted generation resource in its portfolio. The typical 15

communication equipment includes T1 data lines, a router, a firewall, a protocol translator, and control 16

system modules.15 This communication equipment connects to SCE’s Generation Management System 17

(GMS), which is the interface that allows SCE to have two-way communication and to remotely monitor 18

and manage the generation resources in its portfolio. 19

Communication equipment is essential to allow SCE to receive telemetry data from 20

weather stations and utility-owned and contracted generation resources as well as to install and utilize 21

emergency satellite phone systems at all SCE-owned and contracted generation stations. This 22

communication equipment allows SCE to operate its portfolio of generation resources effectively both 23

within and outside the California Independent System Operator Corporation (CAISO) control area. 24

Specifically, it enables SCE to more effectively adjust energy schedules, settle energy transactions, and 25

respond to dispatch protocols, where applicable. All of this communication equipment requires 26

specialized installation, configuration, and testing. 27

15 See SCE-02, Vol. 4., p. 42.

6

SCE Power Procurement has filed in SCE-02, Vol. 4, a request of $3.45 million in 2013, 1

$1.78 million in 2014, $1.85 million in 2015, $1.55 million in 2016 and $1.55 million in 2017, for the 2

installation and configuration of the communication equipment.16 3

2. ORA’s Position 4

ORA is recommending that the Commission utilize SCE’s 2013 recorded actual amount 5

of $0.986 million for its 2013 capital expenditures for communication equipment. ORA believes that 6

SCE’s 2013 recorded capital expenditures are the most current, thus the most accurate. Additionally, 7

ORA is recommending that the Commission adopt ORA’s proposed capital expenditures for 8

communication equipment of $1.030 million for 2014 and $1.098 million for 2015.17 To derive these 9

numbers, ORA utilized SCE’s actual recorded 2013 amount and applied a basic escalation factor to 10

account for inflation.18 11

3. SCE’s Rebuttal To ORA Position 12

SCE disagrees with ORA’s simplistic approach of escalating actual 2013 expenditures to 13

calculate expenditures for years 2014 and 2015. ORA’s method is inappropriate because it does not take 14

into consideration the underlying factors driving the estimation of these capital expenditures, namely the 15

number of contracts that come online in a given year and the ability to aggregate communication 16

equipment. 17

SCE’s forecast is based on not only the number of contracts or generating resources in its 18

portfolio with online dates in 2014 and 2015, but SCE also considers the potential for efficiencies 19

through communication equipment aggregation among multiple projects.19 Not all aggregation of 20

equipment is necessarily homogenous; however, the level of aggregation that may be available for one 21

group of contracts, may not be appropriate for others. Moreover, SCE’s forecast must reflect CAISO 22

rules and interconnection guidelines related to aggregation. 23

SCE anticipates that some of the contracts that SCE expected to come online in 2013 but 24

were delayed, will come online in 2014 and 2015. SCE also anticipates that there may be less ability to 25

16 See Standard Capital Testimony, SCE-02, Vol. 4, p. 43, Standard Capital Workpapers, SCE-02, Vol. 4, pp. 27

and 35, and SCE Data Request Response to DRA-004-GSD Q. 3 (Appendix A). 17 See ORA-06, p. 2. 18 See ORA-04, ORA Escalation, pp. 1-6. 19 See SCE’s Data Request Response to DRA-004-GSD Q. 1 (Appendix A).

7

aggregate the contracts that it anticipates coming online in 2014 and 2015, due to geographical 1

constraints. 2

For the reasons detailed above, SCE recommends that the Commission not adopt ORA’s 3

recommendations concerning Power Procurement’s Capital Expenditures for the years 2014 and 2015. 4

SCE recommends that the Commission adopt SCE’s proposed Power Procurement’s Capital 5

Expenditures as requested in its opening GRC 2015 Testimony for the years 2014 and 2015. 6

C. SBUA’s Discussion On SONGS-Related Concerns And Small Renewable Program Funding 7

Is Not Within The Scope Of This Proceeding 8

SBUA’s opening testimony to SCE’s 2015 GRC application inappropriately discusses the likely 9

replacement of the SONGS generation capacity and recommendations on how SCE should replace the 10

expected loss of capacity. SBUA’s discussion on all SONGS-related issues are beyond the scope of this 11

proceeding. Discussion on replacement capacity for SONGS-out should be addressed in more 12

appropriate proceedings such as the Long Term Procurement (LTPP) proceeding or the Resource 13

Adequacy (RA) proceeding. 14

In addition, SBUA’s opening testimony discusses briefly and provides recommendations 15

concerning the continuous funding of CPUC small renewables programs. This funding discussion is 16

clearly beyond the scope of SCE’s 2015 GRC proceeding. The Commission already considers these 17

issues in various renewable proceedings, such as the Renewable Auction Mechanism (RAM) proceeding 18

R.08-08-009 and the Solar Photovoltaic Program (SPVP) proceeding A.08-07-017. 19

8

III. 1

POWER PRODUCTION GENERATION POLICY 2

A. SCE Application And The Positions Of The Parties 3

SCE-02 Volume 5 direct testimony provides a general overview of the Power Production 4

Department (PPD) submittals contained within SCE-02 Vol. 6–10.20 Table III-1 below summarizes the 5

SCE Power Production TY 2015 O&M expense forecast by asset (i.e., Hydro, Mountainview, Peakers, 6

Mohave, Solar PV and Fuel Cells).21 Also included is a summary of the adjusted forecasts proposed by 7

ORA and TURN, along with the SCE rebuttal position, which incorporates those adjustments that SCE 8

accepts.22 9

Table III-1 Power Production Department Test Year 2015 O&M Expense Forecast

($Million) ($2012)

SCE ORA TURNSCE

Rebuttal Position

Hydro 53.2 48.9 52.0 53.1Mountainview 50.3 47.3 48.4 48.7Peaker 10.5 9.7 9.8 10.5Mohave 0.3 0.0 0.3 0.3Solar 4.3 3.4 4.3 4.3Fuel Cell 0.7 0.5 0.6 0.7TOTAL 119.3 109.8 115.4 117.6

Table III-2 below summarizes the SCE Power Production 2013-2015 capital expenditure 10

forecast, along with a summary of the adjusted forecasts proposed by ORA, TURN and SBUA. Also 11

20 ORA, TURN and others frequently group SCE PPD operations along with SCE Catalina power generating

operations, and refer to that grouping as "NonNuclear Generation." However, as Catalina is not managed by SCE PPD, this Chapter of the SCE Rebuttal Testimony does not discuss Catalina.

21 Costs presented in this Chapter include figures that are rounded to the nearest $100,000. See SCE Chapters IV - IX for the more exact figures (i.e., to the nearest $1,000) of the various forecasts and adjustments of the parties. Mohave costs are SCE's share of total costs for the jointly-owned decommissioned site.

22 The ORA forecast for Mountainview includes ORA revisions as provided in Appendix E, ORA Response to SCE-DRA-065-PM1 Q. 1.

9

included is a summary of the SCE rebuttal position, which incorporates those adjustments that SCE 1

accepts, including revising the capital expenditure forecast to reflect 2013 recorded expenditures. 2

Table III-2 Power Production Department 2013-2015 Capital Expenditure Forecast

($Million) ($Nominal)

Year SCE ORA TURN SBUASCE

Rebuttal Position

Hydro 2013 82.1 60.2 82.1 82.1 60.22014 72.6 69.4 72.6 72.6 71.12015 99.2 67.0 99.2 99.2 90.2

Mountainview 2013 9.6 9.3 9.6 9.6 9.32014 1.3 1.3 1.3 1.3 1.32015 1.1 1.1 1.1 1.1 1.1

Peaker 2013 1.1 1.2 1.1 1.1 1.22014 3.0 3.0 3.0 3.0 3.02015 3.0 3.0 3.0 2.0 3.0

Solar 2013 31.5 26.6 31.5 31.5 25.42014 0.4 0.4 0.4 0.4 0.42015 1.0 1.0 1.0 1.0 1.0

Fuel Cell 2013 0.7 0.7 0.7 0.7 0.72014 0.0 0.0 0.0 0.0 0.02015 0.0 0.0 0.0 0.0 0.0

TOTAL 2013 125.0 98.0 125.0 125.0 96.82014 77.3 74.1 77.3 77.3 75.82015 104.3 72.1 104.3 103.3 95.3

In this chapter, SCE responds to some of the general observations from ORA regarding PPD's 3

overall staffing level and spending trends, and explains its objections to TURN’s analysis and use of 4

2013 recorded-unadjusted O&M expense data. A more detailed response to each of the itemized 5

adjustments proposed by ORA, TURN and SBUA is provided in Chapters IV – IX. 6

B. SCE Rebuttal Summary 7

SCE carefully analyzed and considered the adjustments proposed by the parties. SCE accepts 8

several of the TY 2015 O&M expense forecast itemized reductions proposed by TURN, resulting in an 9

SCE rebuttal position forecast that is $1.7 million lower than presented in the GRC Application. SCE 10

concludes that the remaining TURN adjustments, and those of ORA and SBUA, are inappropriate. 11

Among the many reasons that SCE objects to these proposed adjustments is that SCE found significant 12

10

computational errors (i.e., spreadsheet errors) made by ORA in their analysis and forecasts.23 SCE’s 1

findings and objections to ORA’s, TURN’s and SBUA’s proposed itemized reductions are discussed in 2

more detail in Chapters IV - IX. 3

ORA prefaces its proposed reductions to PPD O&M expense and capital expenditure forecasts 4

by noting that SCE "Non-Nuclear" Generation O&M expense trended downward during 2009-2012. In 5

section III.B.4, SCE provides a more complete picture of PPD spending trends. 6

ORA then discusses that SCE PPD has "under-spent" compared to past Commission authorized 7

GRC amounts. ORA asserts that staffing reductions from 2012 to 2013 suggest that actual PPD 2015 8

TY costs will be lower than SCE forecast. SCE addresses these assertions in III.B.2. 9

TURN prefaces its proposed reductions to PPD O&M expense by asserting that 2013 unadjusted 10

spend data should be included in the analysis. However, full year adjusted 2013 data was not available 11

when SCE submitted its Application in November 2013, and it takes significant time and effort for SCE 12

to adjust the 2013 data, before it is fully comparable to the 2008-2012 recorded O&M expense data 13

provided in the SCE Application. That 2013 data adjustment work has not yet begun. In accordance 14

with the Commission's Rate Case Plan (D.07-07-004, D.93-07-030 and D.89-01-040), this work would 15

not normally be required until SCE begins preparation of its 2018 GRC filing. In attempting to use the 16

unadjusted 2013 data, TURN makes significant errors. SCE discusses these errors in more detail below. 17

1. TURN Errs In Attempting To Perform An Accelerated Analysis Using Unadjusted 18

2013 Recorded O&M Expense Data 19

Based (in part) on analysis of unadjusted 2013 recorded O&M expense, TURN recommended 20

reductions to the following PPD TY 2015 O&M expense forecast components: 21

� A $0.233 million reduction to Mountainview labor and non-labor base forecast for 22

Maintenance (FERC Account 549) 23

� A $1.239 million reduction to Hydro non-labor base forecast for Fee’s (FERC Account 24

536), Operations (FERC Account 539) and Maintenance (FERC Account 545) 25

� A $0.772 million reduction to Peakers labor and non-labor base forecast for Operations 26

(FERC Account 549) and Maintenance (FERC Account 554) 27

SCE does not agree with these proposed reductions for several reasons. First, the use of 28

unadjusted 2013 recorded expense data is contrary to the Commission's Rate Case Plan (D.07-07-004, 29

23 See Appendix E, ORA response to SCE-DRA-065-PM1 Q. 1.a-f.

11

D.93-07-030 and D.89-01-040). Second, TURN selectively uses unadjusted expenses in certain FERC 1

Accounts only when it reduces the TY forecast. Third, accelerated attempts to use unadjusted data for 2

forecasting purposes leads to significant errors. 3

To prepare adjusted 2008-2012 recorded data, SCE completed a comprehensive and analytical 4

process. There are approximately 10,000 Final Cost Centers (FCCs) where expenses are recorded, 5

which are then summarized in a file with recorded data that has nearly one million lines of data. Each 6

department analyzes and adjusts their expenses to: (1) remove one-time expenses or adjust to reflect 7

other ratemaking mechanisms, (2) transfer FCCs between departments, and (3) organize the FCCs for 8

the most effective and representative TY forecast. The unadjusted 2013 expense data TURN relies on 9

has not been analyzed in this way and, therefore, is not comparable to adjusted data or complete. The 10

adjustment process is a monumental task, requiring every department in SCE to participate. This 11

process is described in SCE-10, Vol. 1, Chapter IX.A-IX.E and is further explained in SCE-17.24 12

Chapter V provides information regarding several errors SCE found in TURN’s analysis of the 13

2013 recorded-unadjusted expense for Hydro. SCE also found that TURN miscalculated the total 2013 14

recorded-unadjusted O&M expense for Mountainview Operations (FERC Account 549). As discussed 15

in more detail in Chapter VI, TURN computed this total at $7.706 million, when the actual total is closer 16

to $8.738 million. Using the erroneous total, TURN then used a five-year average of 2009-2013 to 17

forecast the 2015 TY expense for this account. TURN’s erroneous forecast was $0.233 less than SCE’s 18

forecast. However, using the correct unadjusted 2013 recorded expense produces a forecast that is 19

approximately $0.020 million higher than SCE’s forecast.25 20

SCE certainly does not propose to increase the forecast for this account using unadjusted 2013 21

recorded expense data. However, this example illustrates the reasonableness of the Commission's rate 22

case plan, which requires that the most recent five full years of recorded-adjusted O&M expense data be 23

provided with the GRC Application. The plan then allows for sufficient time for parties to analyze the 24

data and to conduct discovery. Attempting to adjust and then incorporate a sixth year of O&M expense 25

data while the rate case is already well underway would almost certainly prolong the GRC process. If a 26

sixth year of data were to be included, additional time will be required to properly analyze and conduct 27

discovery on the data. ORA also agrees with SCE that 2013 O&M expense data “would merely be 28

24 See SCE-17, p. 26. 25 See Appendix E, Mountainview 549 Operations Forecasts.

12

supplementary.”26 For these reasons, the TURN proposed TY 2015 O&M reductions that are based on 1

unadjusted 2013 recorded expense data should be rejected. 2

2. ORA Draws Incorrect Conclusions From PPD Staffing Level Changes 3

ORA’s testimony contains a graph showing 2008-2013 staffing levels in the SCE Power 4

Production Department (PPD).27 ORA speculates that if SCE significantly reduced overall ongoing 5

O&M based on the staffing reductions between 2012 and 2013, then the SCE 2015 TY O&M expense 6

forecast could be over-stated. In response to data request DRA-054-PM1 Q4 Revised, SCE explained to 7

ORA that PPD staffing level changes do not automatically result in PPD O&M expense reductions, as 8

follows. 9

Certain functions that were performed by PPD Staff during 2008 through 2012 were 10 transferred to other SCE departments in late-2012. These other departments continue 11 to provide support services to the PPD plants, and as such, the costs associated with 12 these services continued to record to Hydro, Mountainview, Peakers and SPV, and 13 Mohave and Four Corners oversight through 2013. This transfer of work and 14 personnel to other departments accounts for a large portion of the PPD staffing 15 level reduction, 112 to 74, experienced between 2012 and 2013.28 16

While this response is quoted in the ORA report, ORA ignores it and speculates about the 17

correlation between PPD staffing and future O&M expense. SCE explained that the staffing reduction 18

was largely the result of a re-organization in 2013 that also involved other departments. PPD personnel 19

who have been transferred to other departments still continue to provide support to PPD, and thus their 20

expenses still record to PPD FERC accounts. Therefore, a comparison of the 2012 and 2013 PPD-only 21

staffing levels cannot be utilized to directly forecast future PPD expenses. An attempt to do so, based on 22

this data in isolation, would produce inaccurate results. 23

3. The ORA Request For Department Spending To O&M And Capital Accounts 24

Would Not Result In Meaningful Information 25

In attempting to evaluate the PPD staffing level data discussed above, ORA requested (in 26

data request DRA-106-PM1 Q5) 2010 to 2013 work hour data charged to PPD O&M expense accounts 27

by supplemental employees, contractors and SCE employees.29 In response, SCE explained that such 28

26 Prehearing Conference February 11, 2014, Statement by Mr. Gruen of ORA, p. 49. 27 ORA-07, p. 2. 28 See Appendix B, SCE response to DRA-054-PM1, Q. 4 Revised. Emphasis added. 29 ORA-07, p. 4, lines 11-14.

13

man-hour data (i.e., by FERC account) cannot be readily extracted from SCE’s accounting system, and 1

would require a study to compute. SCE also noted that many contractors are paid by the job, and not by 2

man-hours. Most importantly, SCE noted that such a man-hour computation is not necessary because 3

the dollar cost associated with those man-hours is already captured in the appropriate FERC account: 4

[E]mployee “work hours” were not directly utilized in the development of SCE’s… 5 capital expenditure or O&M expense forecasts. The methods utilized to forecast 6 future Labor and NonLabor costs… would take into account all expenses incurred by 7 Supplemental Employees, Contract Workers, and SCE employees performing work 8 within a specific generation area.30 9

SCE departments work together as a team to perform O&M and capital project work 10

tasks in an organizationally efficient manner. Relative to PPD, certain employees work fulltime on PPD 11

work. Other employees work on both PPD work and on other SCE activities that are not related to the 12

PPD assets. In still other cases, employees perform work that is common across all of PPD, and 13

therefore, the labor costs for these employees is then allocated to each area of PPD (i.e., Hydro, 14

Mountainview, Peakers and Solar). Finally, in all cases, all labor costs are already appropriately 15

accounted for in the proper FERC O&M expense accounts and in the proper capital project work order 16

accounts. These include the labor cost of man-hours expended by non-PPD employees performing 17

power plant O&M and capital project activities, and vice versa, the costs for PPD-employees performing 18

work for other areas of SCE. 19

Seeking a direct cost correlation for a given change in department level staffing, ORA 20

proposes that the Commission require SCE to provide (in the next GRC) the following additional data as 21

part of the five years of recorded data (in nominal and base year dollars): 22

1. Yearly charges by departments that charge to multiple expense and Capital Sub-23

FERC Accounts within lines of business. 24

2. An explanation and showing of changes to the allocation of expenses and Capital 25

to Sub-FERC Accounts. 26

ORA ignores that significant effort will be required to produce this data, which cannot be 27

readily extracted from SCE’s current accounting system. ORA provides no explanation of the value of 28

such additional data in analyzing past O&M and capital recorded costs, as a means of forecasting future 29

30 See Appendix B, SCE response to DRA-106-PM1, Q. 05.a-c.

14

costs. SCE already provides labor dollars for all of SCE by FERC account, as well as staffing level data. 1

SCE already provides, to the extent reasonably possible, additional staffing level and labor cost data to 2

interveners during the discovery process. PPD follows SCE company-wide accounting practices and 3

charges expenses directly to FERC accounts and capital work orders based on the work performed (i.e. 4

activity based accounting). 5

ORA does not understand the complexities of utility activity-based accounting and the 6

SCE GRC showing when it says: 7

Due to the way SCE charges time between lines of business (i.e. Hydro, 8 Mountainview, Peakers, Four Corners, Solar, Fuel Cell Generation assets and the 9 PPD) and allocates recorded expenses within the same FERC Accounts to those lines 10 of business, recorded expenses are not normalized to take into account those 11 charge ins and outs.31 12

It does not make sense to “normalize” recorded expenses that accurately reflect costs 13

associated with a particular activity. In fact, it is efficient for SCE to direct staff to work on related 14

activities across generation lines and other areas like T&D, and, as noted by ORA, “[t]his data is 15

reflected in recorded data. . . .”32 The 2008-2012 recorded expense data is already an accurate reflection 16

of the work performed during those years and SCE recommends that the Commission reject ORA’s 17

recommendation to normalize data. 18

4. The ORA Recorded “Rate Base” O&M Spending Trend Graph Is Misleading 19

ORA includes a table and graph of total SCE recorded “rate rase” O&M Expenses for 20

non-nuclear generation during 2009 through 2012.33 This graph shows a steadily decreasing “rate base” 21

recorded O&M expense over these four years (i.e., a spend of approximately $160 million in 2008 22

trending steadily down to approximately $135 million in 2012). Correspondingly, ORA then asserts 23

"[t]he Non-Nuclear Generation historical reductions in some areas do reduce SCE's TY 2015 forecasts 24

creating some offsetting savings for ratepayers, yet in ORA's evaluation, SCE continues to over forecast 25

31 ORA-07, p. 4, lines 3-7. Emphasis added. 32 ORA-07, p. 4, line 8. 33 ORA-07, p. 9, Table 7-5 and p. 10, Graph 7-2. The ORA graph does not include SPVP or Fuel Cell recorded

expense, because the costs for these assets were not recovered in SCE Base Rates during 2009 through 2012. SCE does not disagree with excluding from the ORA graph the SPVP and Fuel Cell recorded expenses. SPVP and Fuel Cells are relatively new assets and trend graphs of their past recorded O&M expense is of very limited value in forecasting future expenses for a variety of reasons (e.g., construction of the current fleet of SCE SPVP plants was not completed until well into 2013).

15

in its GRC request. . . ."34 This assertion sums up ORA’s observations regarding PPD 2008-2013 1

staffing, the overall strong downward trend of PPD 2009-2012 recorded O&M expense (i.e., when 2

including Four Corners), and the comparison of this recorded spend to past GRC authorized expenses. 3

ORA grossly over-simplifies SCE’s detailed analysis completed to forecast PPD TY 4

2015 O&M expense. For example, ORA’s graph includes the full annual cost of Four Corners in 2009 5

through 2011, and only nine months of Four Corners costs in 2012.35 While it is true Four Corners GRC 6

base rate cost recovery ended in September 2012, a spending trend graph that uses partial-year and full-7

year cost data is of very limited value to assess future PPD expenses (which are for whole years of 2015 8

through 2017). Also, as the sale of the SCE share of Four Corners was completed in December 2013, 9

the ORA 2009-2012 total PPD “rate base” O&M spend graph (which includes Four Corners), is of little 10

value in forecasting future PPD expenses. 11

As further explained below, and in the subsequent chapters of this volume, SCE TY 2015 12

forecasts (including as revised in the SCE rebuttal position forecasts) for Hydro, Mountainview, 13

Peakers, SPVP and Fuel Cells are based on detailed analysis of each of the cost components that 14

comprise these forecasts. ORA’s analysis of many of these individual cost components is 15

disproportionately influenced by the 2009-2012 “rate base” spending trend, including the relatively low 16

recorded expense of 2012. The low spend recorded in 2012 is due to several factors, including 17

Mountainview’s incurring lower than typical maintenance costs in anticipation of the 2013 major 18

overhauls, and the ongoing drought that impacted Hydro 2011 and 2012 spending. SCE analyzed all 19

five years of recorded expense to arrive at a reasonable TY 2015 forecast needed to assure the ongoing 20

reliable operation of these important generating assets. 21

5. ORA Presents An Incomplete Assessment Of Recorded O&M Expense As 22

Compared To Previous GRC Authorized Funding Levels 23

ORA Table 7-5 compares non-nuclear generation recorded O&M expenses with those 24

authorized by the Commission in previous SCE GRCs.36 The ORA table is reproduced here Table III-3, 25

34 ORA-07, p. 4, lines 26-27, and p. 5, lines 1-2. 35 As SCE informed all parties several months ago, SCE has already removed all Four Corners costs from its

2015 GRC forecast because SCE completed the sale of its share of the plant in December 2013. 36 ORA-07, p. 9.

16

for reference. 37 Note that this table only addresses GRC Base Rate O&M expense funding, and 1

commensurate costs, and not funding and costs handled through other mechanisms such as balancing 2

accounts. 3

Table III-3 2008-2012 GRC Authorized vs. Recorded O&M Expense

($000) ($2012) 2008 2009 2010 2011 2012 Total

Hydro Recorded 44,816 51,398 53,775 60,118 49,204 259,311Authorized 42,385 57,853 57,853 57,853 61,433 277,377Total 2,431 (6,455) (4,078) 2,265 (12,229) (18,066)

Mountainview Recorded 0 51,286 31,844 28,817 31,060 143,007Authorized 0 47,161 47,161 47,161 45,346 186,829Total 0 4,125 (15,317) (18,344) (14,286) (43,822)

Peakers Recorded 0 9,646 8,918 9,112 9,074 36,750Authorized 0 10,359 10,359 10,359 12,254 43,331Total 0 (713) (1,441) (1,247) (3,180) (6,581)

Total Recorded 44,816 112,330 94,537 98,047 89,338 439,068Authorized 42,385 115,373 115,373 115,373 119,033 507,537Total 2,431 (3,043) (20,836) (17,326) (29,695) (68,469)

Four Corners Recorded 50,106 43,654 51,745 45,997 28,427 219,929Authorized 40,253 46,521 46,521 46,521 32,892 212,708Total 9,853 (2,867) 5,224 (524) (4,465) 7,221

The Four Corners data from the ORA table is repeated here only to show that year-by-4

year variances of past recorded O&M expense, as compared to GRC authorized funding for older power 5

plants (i.e., Hydro and Four Corners), were mixed during 2008 through 2012 (i.e., in some years spend 6

was higher, and other years lower, than GRC authorized). Much of the “underspend” noted by ORA 7

was experienced at Mountainview and Peakers. Mountainview was a brand new plant and the Peakers 8

were still under construction when SCE submitted the 2009 GRC Application in 2007. There was no 9

recorded O&M spend data available for Peakers, and only very limited recorded spend data available for 10

Mountainview, upon which to base future cost forecasts. 11

During this same timeframe, Hydro was facing increasing compliance costs associated 12

with newly issued and pending FERC licenses. Among other issues, Hydro was also in the process of 13

37 Catalina data is omitted as it is beyond the scope of this chapter.

17

hiring additional apprentices to prepare for the anticipated “baby-boomer” generation retirement bubble. 1

Mountainview was planning for the first round of plant overhauls, and the forecast needed to account for 2

those overhaul costs. Mountainview, Peakers and Hydro were all experiencing increasing compliance 3

costs for physical and cyber security, and grid reliability associated with NERC Reliability Standards. 4

As forecast in the 2009 GRC, Mountainview costs did, in fact, trend significantly upward 5

from their 2006 and 2007 spending levels. As had been expected, this increase was dominated by the 6

costs of the plant's first round of overhauls. Specifically, costs for 2008 and 2009 are much higher than 7

other years because of the 2009 overhauls on each unit, as summarized above and detailed in SCE-02 8

Vol. 9 p. 16. This can be seen in Figure III-1 below. 9

Figure III-1 Mountainview 2006–2012 Recorded O&M Expense

($000) ($2012)

0

10,000

20,000

30,000

40,000

50,000

60,000

2006 2007 2008 2009 2010 2011 2012

Mountainview

While the Mountainview overhauls had been expected, they had to be performed earlier 10

than planned, which impacted the accuracy of the GRC forecast. The SCE 2009 GRC forecast, and the 11

subsequent funding amount adopted in the 2009 GRC Decision (D.09-03-025), had assumed that all of 12

the Mountainview 2009 overhaul costs would record in 2009 and 2010, rather than in 2008 and 2009. 13

Specifically, SCE had planned that the two overhauls (i.e., one on each unit) would be conducted in the 14

fall of 2009 and in the spring of 2010, respectively. However, because of plant conditions, SCE had to 15

accelerate these overhauls by approximately six months. The Unit 4 overhaul was conducted in the 16

spring of 2009 and Unit 3 overhaul was conducted in the fall of 2009. Because of the need to accelerate 17

the overhauls, SCE incurred expenses of approximately $16 million ($2012) in 2008, for the Unit 4 18

18

HGPI overhaul pre-payment and related overhaul expenses, that originally had been forecast to occur in 1

2009.38 This accounts for a large portion of the Mountainview “underspend” from 2009-2011 noted by 2

ORA. 3

Likewise, the 2012 Mountainview “underspend” noted by the ORA is largely due to the 4

cyclical nature of Mountainview overhaul costs. Consistent with the 2009 GRC decision (D.09-03-025), 5

the Commission decision in the SCE 2012 GRC (D.12-11-051) included the 2012-2014 average annual 6

forecast costs for the now-completed 2013 major overhauls. Because 2013 recorded-adjusted O&M 7

expense data is not yet available, SCE cannot compute the exact amount that Mountainview 2013 8

recorded O&M expense exceeds 2012 recorded expense. However, SCE believes that the increase in 9

Mountainview expense in 2013 (as compared to 2012) was very substantial. Once adjusted and 10

computed, the incremental costs of the 2013 overhauls will almost certainly be well in excess of the 11

2012 “underspend” noted by ORA. For example, in this 2015 GRC, SCE forecast Mountainview 2013 12

total O&M expense at $53.4 million, or $22.3 million more than the $31.1 million recorded in 2012. 13

The Commission decisions in the SCE 2009 and 2012 GRCs included O&M funding for 14

McGrath Peaker operations. In each case, the authorized amounts assumed that the McGrath Peaker 15

would become operational at some point during the respective three-year GRC funding periods. These 16

forecasts and authorized amounts were based on the most current information available at those times. 17

However, subsequently, the McGrath Peaker did not enter commercial service until November 2013. 18

The McGrath Peaker construction delays account for an additional portion of the 2009-2012 19

“underspend” noted by ORA. 20

During 2009 through 2011 Hydro costs steadily and significantly trended upward from 21

2006-2008 recorded cost levels. This can be seen in Figure III-2 below. SCE agrees that this trend was 22

not as steep as the authorized Hydro O&M expense funding in the SCE 2009 GRC for the 2009-2011 23

three-year GRC funding cycle. As Figure III-2 below shows, it was not until 2011 that Hydro recorded 24

expense of $60.1 million exceeded the $57.9 million authorized annual amount from the 2009 GRC. 25

38 This can be seen in Figure III-1, where 2008 recorded expense of approximately $46.5 million, was

approximately $16 million higher than 2010-2012 annual average recorded expense of approximately $30.6 million.

19

Figure III-2 Hydro 2006–2012 Recorded O&M Expense

($000) ($2012)

�

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

2006 2007 2008 2009 2010 2011 2012

Hydro

SCE has worked hard to manage Hydro expenses, and the SCE Hydro 2015 TY rebuttal 1

position O&M expense forecast (at approximately $53.1 million) is significantly less than both the 2009 2

GRC authorized amount (at approximately $57.9 million) and the 2012 GRC authorized amount (at 3

approximately $61.4 million).39 4

6. The Hydro, Mountainview & Peakers Test Year 2015 Forecasts Are Less Than 2009 5

GRC And 2012 GRC Authorized And Is Fully Consistent With Recorded Expense 6

SCE’s forecast in this 2015 GRC is based on actual recorded expense from 2008 through 7

2012, and incorporates lessons learned from plant operations since the prior 2009 and 2012 GRCs. 8

SCE’s rebuttal position forecast of approximately $112.2 million is $6.8 million less than 2012 GRC 9

authorized funding of $119.0 million (i.e., for Hydro, Mountainview and Peakers in aggregate, in 10

$2012). It is also $3.1 million less than the 2009 GRC authorized amount of $115.4 million ($2012). 11

The combined SCE rebuttal position forecast for Hydro, Mountainview and Peakers is 12

$112.2 million, and is essentially identical to 2009 recorded O&M expense of $112.3 million ($2012), 13

the last year (up until 2013) that Mountainvew incurred overhaul expenses. The TY 2015 forecast 14

accounts for increased Mountainview CSA fees and the addition of McGrath to the Peaker fleet. The 15

SCE forecast is reasonable. 16

39 Figures are in $2012.

20

IV. 1

MOHAVE GENERATING STATION O&M 2

A. SCE's Application 3

SCE forecasts TY 2015 O&M expenses for Mohave Generating Station (Mohave) of $0.308 4

million (SCE share) utilizing an itemized forecast. As a consequence of Mohave’s past operations as a 5

power generation facility, from which SCE customers benefitted for decades, SCE will continue to incur 6

O&M expenses for continued management of the decommissioned power plant site. These expenses 7

include ongoing site security, minor maintenance activities, and regulatory compliance activities mostly 8

associated with the ash canyon landfill (such as monitoring well testing and reporting; landfill cover 9

maintenance and inspections). The expenses also include permit obligations related to the Construction 10

Stormwater permit and the Ash Canyon Dam permit. The expenses will continue into the foreseeable 11

future until final site closure and/or sale can be achieved. 12

SCE forecasted capital expenditures of $0.600 million in 2013 to complete decommissioning.1 13

SCE also proposes to close the Mohave Balancing Account (MBA) in 2015 as decommissioning 14

activities are now concluding. 15

B. Summary Of Parties’ Positions By FERC Account 16

Table IV-4 below summarizes SCE's O&M expense forecast for Mohave site maintenance, and 17

ORA's proposed adjustments, by FERC account and divided into the labor and non-labor categories.40 18

40 Table IV-4 reflects: (a) SCE’s application forecast in SCE-02, Vol. 6, Pt. 1 as well as SCE-02, Vol. 6, Pt. 1,

Revision 1; (b) ORA’s proposed adjustments in ORA-07; and (c) SCE’s rebuttal position as presented in this exhibit.

21

Table IV-4 TY 2015 O&M Position Comparison by FERC Account

(SCE Share) ($000) ($2012)

SCE Application

ORA Adjustments

SCE Rebuttal Position

FERC 506.013 Labor $ 112 $ (112) $ 112 Non Labor $ 68 $ (68) $ 68 Other $ - $ - $ - Total $ 180 $ (180) $ 180 FERC 514.013 Labor $ - $ - $ - Non Labor $ 128 $ (128) $ 128 Other $ - $ - $ - Total $ 128 $ (128) $ 128 TOTAL $ 308 $ (308) $ 308

C. ORA's Position 1

ORA proposes a TY 2015 O&M forecast of zero for Mohave O&M activities, observing that 2

[o]n December, 20, 2013, SCE filed a letter with the Energy Division of the CPUC stating 3 the company's intentions to sell its ownership interest in the Mohave site, not including the 4 Mohave Switchyard and the Mohave-to-Eldorado and Mohave-to-Lugo 500kV transmission 5 lines.41 6

ORA reasons that given SCE’s intentions and because the Mohave Switchyard and transmission 7

lines are not generation assets, the MBA should be closed and SCE should collect zero O&M expenses 8

in generation FERC accounts in TY 2015.42 SCE responds to ORA’s testimony in detail below. 9

ORA agrees with SCE’s proposal to close the MBA effective January 1, 2015, but recommends a 10

a reduction in the capital-related revenue requirement. SCE responds to ORA's capital-related 11

recommendation in SCE Exhibit SCE-26, Volume 1C. 12

41 Actual 2013 recorded capital expenditures to complete the Mohave Decommissioning were a credit of

0.3 million (SCE Share). As discussed in DRA-041-PM1 Q. 10.b. these credits were primarily related to equipment salvage proceeds (Appendix C).

42 ORA-07, p. 12, lines 1-7.

22

D. SCE’s Rebuttal 1

1. ORA Incorrectly Characterizes The Scope And Purpose Of SCE's Forecast For 2

Managing The Decommissioned Power Plant 3

ORA misunderstands the scope and purpose of SCE’s forecast. Mohave has ongoing 4

O&M expenses associated with the generation portion of the site.43 As noted above, these activities 5

include security and maintenance activities, and regulatory obligations in connection with the Ash 6

Canyon landfill, and are directly attributable to activities that occurred while Mohave was a generating 7

facility. 44 In particular, the regulatory requirements pertain to the closed Ash Canyon landfill; Nevada 8

Division of Environmental Protection (NDEP) dam permit associated with the Ash Canyon Dam; 9

ongoing inspection and potential maintenance associated with the closed evaporation ponds; and a 10

construction storm water permit that will remain in place until an approximate 70% natural vegetation 11

cover is re-established. The forecasted expenses are therefore generation facility related. Accordingly, 12

the TY 2015 forecast for Mohave is appropriately included within the Power Production Expense FERC 13

Accounts for Steam Power Generation operations (FERC Account 506.013) and maintenance (FERC 14

Account 514.013). 15

2. ORA Erroneously Assumes That SCE Can Quickly Divest Its Ownership Share Of 16

The Decommissioned Power Plant Site 17

ORA implies that Mohave O&M costs should not be included in the 2015 GRC base 18

rates due to SCE’s stated intention to sell the facility. Although SCE intends to sell its portion of the 19

site, SCE is responsible as the operator and co-owner of the Mohave plant for maintaining the site and 20

meeting regulatory obligations. Therefore, SCE will continue to incur costs relating to these obligations 21

until the sale is complete. 22

While it is true that SCE has announced its intent to sell the Mohave site, the sale process 23

is in its earliest stages, and it unlikely to be completed in the near future. A successful sale, of course, 24

requires a willing buyer and coordination with the plant’s other three co-owners. Ultimately, a sale 25

agreement may also need approval by the Commission. It is likely that this process will take many 26

43 O&M expenses related to the operation of the switchyard and transmission lines are included in SCE-03,

Transmission & Distribution. 44 For example, the ash generated by the coal burning operations of the power plant produced all of the ash

waste material that was disposed of into the ash canyon landfill in compliance with ash disposal regulatory requirements.

23

months and perhaps years to complete. Furthermore, since there is not yet a sale, there are no sale 1

contract details available for review. It is speculative to assume that SCE would not incur expenses 2

related site maintenance and closure costs, for at least some period of time, following the date at which a 3

potential sale is completed. 4

It is reasonable to forecast that SCE will continue to incur Mohave power plant site 5

maintenance cost obligations for the 2015 GRC three-year ratemaking cycle. SCE should be allowed to 6

recover such modest, forecast O&M expenses associated with the Mohave site, via Base Rates, until 7

these cost obligations cease, consistent with cost-of-service ratemaking principles. The Commission 8

should approve SCE’s TY 2015 O&M forecast of $0.308 million for Mohave. 9

24

V. 1

HYDRO O&M AND CAPITAL 2

A. Hydro O&M 3

1. SCE’s Application 4

SCE’s TY 2015 Hydro O&M expense forecast contains two parts for each of the 5

consolidated FERC Accounts for Operations (539), Maintenance (545), and Fees (536): (1) a “base 6

forecast” that is derived from analysis of historical 2008 to 2012 recorded-adjusted O&M expenses 7

totaling $53.450 million, and (2) a decrease to the base forecast in FERC Account 539 of $0.225 million 8

based on forecasted savings from Operational Excellence. The sum of these two parts results in a 2015 9

TY Hydro O&M forecast of $53.244 million. 10

SCE’s base forecast uses Last Recorded Year (LYR) for labor expenses in FERC 11

Accounts 539 and 545, as these expenses have been relatively stable over the last three years.45 The 12

base forecast for non-labor uses a five-year average in FERC Accounts 539, 545 and 536, as these 13

expenses have fluctuated year-by-year as a result of weather and other factors. 14


ORA recommends a $4.353 million (8%) reduction to SCE’s TY 2015 Hydro O&M 16

forecast to arrive at its proposed forecast of $48.871 million. Whereas SCE used a five-year average to 17

forecast non-labor expenses for all Hydro accounts (i.e., 539, 545 and 536), ORA uses LRY; i.e., 2012 18

recorded. This accounts for $3.531 million46 of ORA’s proposed reduction to SCE’s 2015 TY O&M 19

forecast.47 In support of the proposed reduction, ORA asserts that SCE’s forecasted expenses are high 20

when compared to other hydro systems, and notes that SCE’s 2012 O&M expenses were 25% less than 21

authorized in D.12-11.051 (SCE’s 2012 GRC). ORA further contends that SCE did not sufficiently 22

justify the use of a five-year average for non-labor. SCE addresses these assertions below. 23

ORA also recommends an additional reduction of $0.107 million in FERC Account 539 24

for Operational Excellence, which ORA discusses in Exhibit ORA-19.48 SCE’s rebuttal to ORA’s 25

additional Operational Excellence adjustments are included in Exhibit SCE-28. 26

45 FERC 536 does not normally incur Labor expense. 46 (X) Indicates an adjustment relative to SCE’s application forecast. 47 See ORA-07, p. 17, lines 1-3. 48 See Table 19-11 at ORA-19, p. 24.

25

3. TURN’s Position 1

TURN recommends a $1.236 million (2.3%) reduction to SCE’s TY 2015 Hydro O&M 2

forecast to arrive at its proposed forecast of $51.987 million. TURN uses 2013 recorded, unadjusted 3

expenses for its proposed forecasts; recommends removal of the O&M expenses incurred at the San 4

Gorgonio hydro plant; and adjusts for the Kaweah 3 Special Use Permit (SUP) and a 2009 expense that 5

was added to Account 925 (Claims). 6

TURN asserts that 2013 recorded expenses should be included in the analysis used to 7

forecast the labor and non-labor expenses for FERC Accounts 539 and 545. Specifically, TURN 8

recommends a two-year average for FERC Accounts 539 and 545, claiming that labor costs were 9

reduced in 2013. TURN also asserts that for purposes of forecasting future Hydro expense, San 10

Gorgonio costs should be excluded in the past recorded expense data. In TURN’s view, SCE customers 11

should not fund San Gorgonio’s ongoing O&M because SCE’s San Gorgonio hydro facilities no longer 12

generate electricity. 13

TURN reviewed the fee invoices that recorded to Account 536 during 2008-2012, and 14

noted that the Kaweah 3 Special Use Permit (SUP) fees include payments for pre-2008 operations. 15

TURN proposes removing fees for pre-2008 operations. Further, TURN recommends using a six-year 16

average (2008 through 2013) for the non-labor expenses in order to “[t]ake 2013 data into account.”49 17

This 6-year average is the basis for its forecast. 18

Lastly, TURN claims that SCE had accounted for a certain $0.121 million 2010 expense 19

in both FERC Account 925 (Claims) and Hydro Account 539.50 TURN therefore proposes removing 20

this expense from the FERC Account 539 recorded expense data, which would reduce the TY 2015 21

forecast by $0.024 million as that expense is no longer part of the multi-year average used. 22

SCE responds to TURN’s testimony below. 23

4. Position Summary 24

Table V-5 below summarizes the forecasting methods used in SCE’s Application, and 25

those proposed by ORA and TURN, summarized by FERC Account, divided into the labor, non-labor 26

and other categories. 27

49 TURN-05, Marcus, p. 11. 50 TURN-05, Marcus, p. 12, footnote 22, points to workpapers for FERC Account 925 at SCE-08, Vol. 2, p.

122. This workpaper shows $0.121 million recorded in 2010 in F200989, and not in 2009 as stated by TURN.

26

Table V-5 TY 2015 O&M Position Comparison

($000) ($2012)

Acnt Labor �Non�Labor Other Total Labor Non�Labor Other

SCEFee's 536 0 5,971 0 5,971 - 5-Yr Avg. -

Sub�Total 0 5,971 0 5,97119,195 12,218 0 31,413 LRY 5-Yr Avg. -

(87) (139) (226) OpEx Adj. OpEx Adj. -Sub�Total 19,108 12,079 0 31,187

Maintenance 545 9,436 6,629 0 16,065 LRY 5-Yr Avg. -Sub�Total 9,436 6,629 0 16,065

28,544 24,679 0 53,224

ORA Lower�than�SCE: 4,353Fee's 536 0 6,020 0 6,020 - LRY -

Sub�Total 0 6,020 0 6,020539 19,195 11,504 0 30,699 LRY LRY -

(185) (148) 0 (333) OpEx Adj. OpEx Adj. -Sub�Total 19,010 11,356 0 30,366

Maintenance 545 9,436 3,049 0 12,485 LRY LRY -Sub�Total 9,436 3,049 0 12,485

28,446 20,425 0 48,871

TURN Lower�than�SCE: 1,2360 5,699 0 5,699 - 6-Yr Avg. -0 (83) 0 (83) - Kaweah SUP Adj. -0 (11) 0 (11) - San Gorgonio Adj. -0 (18) 0 (18) - Dam Inspection Adj. -

Sub�Total 0 5,587 0 5,587

18,459 12,079 0 30,5382-year Avg. + Severance Adj. 2-year Avg. -

0 (24) 0 (24) - Claims Adj. -(53) (4) 0 (57) San Gorgonio Adj. San Gorgonio Adj. -

Sub�Total 18,406 12,051 0 30,457

9,343 6,630 0 15,9732-year Avg. + Severance Adj. 2-year Avg. -

(24) (5) 0 (29) San Gorgonio Adj. San Gorgonio Adj. -Sub�Total 9,319 6,625 0 15,944

27,725 24,263 0 51,988

2015�TY�Forecast�($000)�($2012) Forecast�Method

Operations 539

��TOTAL�SCE�FORECAST

��TOTAL�TURN�FORECAST

��TOTAL�ORA�FORECAST

Fee's 536

Operations 539

Maintenance 545

Operations

27

Table V-6 below summarizes the forecast reductions proposed by ORA and TURN, 1

summarized by FERC Account, divided into the labor, non-labor and other categories.51 2

Table V-6 TY 2015 O&M Position Comparison by FERC Account

($000) ($2012) SCE

ApplicationORA

AdjustmentsORA OpX

AdjustmentsTURN

AdjustmentsSCE Rebuttal

PositionFERC 536 Labor -$ -$ -$ -$ -$ Hydro Fee's Non Labor 5,971$ 49$ -$ (384)$ 5,888$

Other -$ -$ -$ -$ Total 5,971$ 49$ -$ (384)$ 5,888$

FERC 539 Labor 19,108$ 87$ (98)$ (702)$ 19,108$ Hydro Non Labor 12,079$ (575)$ (9)$ (28)$ 12,079$ Operations Other -$ -$ -$ -$ -$

Total 31,187$ (488)$ (107)$ (730)$ 31,187$ FERC 545 Labor 9,436$ -$ -$ (117)$ 9,436$ Hydro Non Labor 6,629$ (3,580)$ -$ (4)$ 6,629$ Maintenance Other -$ -$ -$ -$ -$

Total 16,065$ (3,580)$ -$ (121)$ 16,065$ 53,224$ (4,020)$ (107)$ (1,236)$ 53,140$ GRAND TOTAL

5. SCE’s Rebuttal To ORA 3

ORA proposes a $4.254 million reduction to the SCE Hydro non-labor forecast for 4

Accounts 536, 539 and 545 combined. ORA uses Last Recorded Year (LRY) as the forecast basis, 5

whereas SCE uses a five-year average. ORA use of LRY to forecast Hydro non-labor expense is 6

inconsistent with Commission guidance on GRC TY expense forecasting. The ORA forecast assumes a 7

continuing downward spending trend, which is unproven, and ignores the effects of precipitation levels 8

on expense. While 2012 recorded non-labor expense is lower than that recorded in years 2008 through 9

2011, there is not a clear upward or downward trend over these five year. Therefore, a five-year average 10

(2008-2012) is a reasonable and appropriate basis to forecast TY expense. 11

ORA asserts that SCE took steps in 2012 to reduce future costs and therefore, the use of 12

LRY produces an appropriate forecast. ORA references a single study that compares SCE’s hydro costs 13

51 Table V-6 reflects: (a) SCE's application forecast in SCE-02, Vol. 7, Part 1 as well as Errata-SCE-02, Vol. 7,

Part 1; (b) ORA's proposed adjustments in ORA-7; (c) ORA’s proposed OpX adjustment in ORA-19 (d) TURN's proposed adjustments in TURN-5; and (e) SCE’s rebuttal position as presented in this exhibit.

28

to other hydro operators. Below SCE provides further information regarding this study, and the inherent 1

limitations encountered in conducting such studies. ORA also ignores the effects of precipitation levels 2

on the recorded 2008-2012 five-year spending pattern. A five-year average remains the most 3

appropriate basis for forecasting TY 2015 O&M non-labor expense. 4

As mentioned previously, SCE’s rebuttal to ORA’s additional Operational Excellence 5

adjustments are included in Exhibit SCE-28. 6

a) ORA’s Use Of Last Recorded Year Is Inconsistent With Commission 7

Forecast Guidance And Ignores Year-Over-Year Fluctuations That 8

Substantiate The Use Of An Average 9

SCE disagrees with ORA’s LRY forecasting method for non-labor expenses in 10

FERC Accounts 536, 539 and 545 for several reasons. In testimony SCE explained that: 11

The recorded costs shown reflect inherent variations from year to year due to 12 the uncertainty of the FERC fees, which are directly affected by the 13 precipitation at the Hydro Facilities and represent the majority of costs 14 recorded in FERC 536.52 15

Work accelerated in 2011 due to very low rainfall, resulting in lower expenses 16 in 2012. The last recorded year is therefore not a sufficient forecast to support 17 maintenance activities during the Test Year. A five-year average best reflects 18 historical and future expenses. . . .53 19

In 2012, precipitation levels were again very low. However, as much of the 20 maintenance back-log had been addressed in 2011, overall Hydro spending in 21 2012 was much lower than 2011, including non-labor. . . .54 22

Furthermore, in Workpapers SCE further elaborated that: 23

While 2008-2010 non-labor expenses remained relatively stable, expenses in 24 2011 and 2012 varied due to weather conditions. Work was accelerated in 25 2011 due to very low rainfall, resulting in lower expenses in 2012. The 2012 26 base year is therefore not an appropriate forecast to support operations 27 activities during test year 2015. A five-year average best reflects historical 28 and forecast expenses for non-labor.55 29

52 SCE-02, Vol. 7, Part 1, p. 13. 53 SCE-02, Vol. 7, Part 1, p. 25. 54 SCE-02, Vol. 7, Part 1, p. 20. 55 See Appendix D, Workpapers, SCE-02, Vol. 7, Part 1, pp. 22 and 48.

29

As summarized above, in direct testimony SCE explained how precipitation levels 1

(i.e., the ongoing drought) resulted in higher-than-typical maintenance non-labor expense in 2011, 2

followed by lower-than-typical levels in 2012 (Account 545). Hydro operations costs (Account 539) 3

were also impacted by these maintenance activities, as operations provide significant support for 4

maintenance work. SCE also explained how the 2008-2012 annual precipitation levels impacted the 5

year-by-year fees paid to regulatory agencies (Account 536). The 2008-2012 recorded non-labor 6

expense for these three accounts is provided in Table V-7 below. As shown, the recorded non-labor 7

expenses in SCE’s Hydro O&M accounts (536, 539 and 545) fluctuated between 2008 and 2012, with 8

the most substantial fluctuation occurring in between 2011 and 2012 for the reasons noted above. 9

Table V-7 SCE Hydro O&M Recorded/Adjusted Non-Labor Expenses by FERC Account

($000) ($2012) FERC

Account 2008 2009 2010 2011 20125-YR Avg.

536 4,805 6,986 5,006 7,037 6,020 5,971539 10,422 11,784 12,410 14,971 11,504 12,218545 7,224 7,364 7,273 8,238 3,049 6,630Total 22,451 26,135 24,689 30,245 20,573 24,819

By comparison, the SCE’s TY 2015 O&M non-labor forecast is $24.679 million, 10

which lies just below 2010 recorded. Figure V-3 below provides a graphical display of the 2008-2012 11

non-labor recorded expense data by FERC Account. 12

30

Figure V-3 SCE Hydro Recorded/Adjusted O&M Non-Labor Expenses by FERC Account

($000) ($2012)

0

5,000

10,000

15,000

2008 2009 2010 2011 2012

Non

-Lab

or O

&M

Exp

ense

s

Year

FERC 536 Fees FERC 539 Operations FERC 545 Maintenance

Figure V-3 above shows that there is not a strong trend, either upward or 1

downward, over the 2008-2012 time periods for non-labor costs for any of the three FERC accounts at 2

issue. Rather, the costs fluctuate over the years. Therefore, an averaging method is the most appropriate 3

method for forecasting non-labor expenses and is consistent with Commission guidance discussed in 4

further detail below. Table V-8 below summarizes the various standard averaging methods commonly 5

used in GRC TY expense forecasting. As shown, the five-year average, which SCE selected, produces 6

the lowest cost forecast of the most common averaging methods used for forecasting. 7

31

Table V-8 Hydro TY 2015 O&M Non-Labor Forecast Method Comparison

($000) ($Nominal)

FERC Account

2-YR Avg.

3-YR Avg.

4-YR Avg.

5-YR Avg.

ORA Forecast

536 6,529 6,021 6,262 5,971 6,020539 13,238 12,962 12,667 12,218 11,356545 5,644 6,187 6,481 6,630 3,059

Total 25,410 25,169 25,411 24,819 20,435

There are many approaches to forecasting Test Year expenses and many different 1

methods have been used in prior GRCs. In the Commission’s decision on Pacific Gas and Electric 2

Company’s (PG&E) 1990 GRC, the Commission provided the following guidance for selecting an 3

appropriate forecasting methodology: 4

The Commission has recognized that there are different valid and acceptable 5 methods for account-by-account forecasting test year costs in a GRC, 6 including using a single recorded year’s expenses ... and using multi-year 7 average recorded costs .... The question at hand is which of these two methods 8 yields the most accurate and reliable forecast of test year expenses. 9

If recorded expenses in an account have been relatively stable for three or 10 more years, the 1987 recorded expense is an appropriate base estimate for 11 1990. 12

If recorded expenses in an account have shown a trend in a certain direction 13 over three or more years, the 1987 level is the most recent point in the trend 14 and is an appropriate base estimate for 1990. 15

For those accounts which have significant fluctuations in recorded expenses 16 from year to year, or which are influenced by weather or other external forces 17 beyond the control of the utility, an average of recorded expenses over a 18 period of time (typical four years) is a reasonable base expense for the 1990 19 Test Year. (D.89-12-057, 34 CPUC 2d 199, 231.)56 20

The Commission first articulated these forecasting principles 25 years ago 21

in the 1989 PG&E GRC decision, and repeated them in its decision for SCE’s 2003 GRC. In sum, the 22

Commission determined that if an account had been either relatively stable or trending in a certain 23

direction, then the last recorded year is an appropriate base estimate. The Commissioned also 24

32

determined that, on the other hand, if recorded costs fluctuated significantly from year to year, or are 1

influenced by external forces beyond the utility’s control (e.g. weather) then an average is an appropriate 2

base estimate. SCE followed these principles in developing its 2015 TY O&M forecast, and ORA did 3

not. 4

b) ORA’s Review Of The PA Consulting Benchmarking Study Is Incomplete 5

During 2012, SCE contracted with Personnel Administration (PA) Consulting to 6

explore potential initiatives to improve the operational performance of the SCE Hydro fleet, including 7

cost performance. This work was summarized in a final report as identified in the response to the 8

Master Data Request, and subsequently provided in SCE response to DRA-054-PM1 Q1(Appendix D). 9

The final report benchmarked SCE Hydro Fleet cost performance (i.e., largely based on recorded costs 10

during years 2009 through 2011) in two primary ways: (1) a comparison of SCE costs to that of other 11

international Hydro fleet operators on a “Cost per Weighted Maintenance Object (WMO)” basis, and (2) 12

a comparison of SCE costs to those of other US Hydro fleet operators on a $/MW and a $/kWh basis 13

using FERC Form 1 data. 14

The WMO is a proprietary measure used by PA Consulting that is intended to 15

account for the large variability in the physical and geographic configuration of Hydro fleets world-16

wide. The WMO computation is based on many factors, such as the amount of equipment present in 17

each fleet, the accessibility of that equipment based on roads and terrain, and similar issues. SCE was 18

the first North American Hydro operator to participate in the PA Consulting Hydro Fleet WMO bench-19

marking process. The PA Consulting “Cost per WMO” data base includes fleets in Europe, Africa, 20

South America and Asia. 21

ORA claims that the PA Consulting benchmarking study demonstrates that SCE’s 22

Hydro costs are unreasonable. The O&M expense forecast reductions proposed by ORA assumes that, 23

based on the PA Consulting study, SCE Hydro costs can be quickly, readily and significantly reduced. 24

Such reductions would then need to be sustained over the 2015-2017 GRC cycle without adversely 25

impacting SCE Hydro reliability and regulatory compliance. However, ORA bases this assertion solely 26

on the WMO portion of the study, and ignores the $/MW and $/kWh results in the study. 27

Continued from the previous page 56 D.04-07-022, pp. 15-16.

33

ORA over reliance on the study’s cost per WMO results, with no mention of the 1

$/MW and $/MWh results, is misplaced. ORA does not acknowledge that SCE was the only (as of the 2

final report date of July 2012) North American company to participate in PA Consulting’s 3

benchmarking report for Hydro Generating facilities. Comparing SCE’s Hydro to “other utility Hydro 4

Systems”, which are not located in the United States, is not reasonable. 5

Further, PA Consulting did not provide its proprietary calculations for WMO that 6

PA Consulting used to normalize costs across the hydro plants who participated in the study. Without 7

this information, it is impossible to ascertain the reasons that SCE Hydro has a high cost on a per WMO 8

basis compared to the international operators in the data base. It could be the result of differences in 9

wages, environmental and other regulatory compliance costs, and many other similar factors. It is 10

reasonable to assume that SCE may incur higher costs in these and other areas compared to the other 11

operators in the PA Consulting data base. 12

In contrast to the $/WMO results, the PA Consulting study also showed that 2011 13

SCE Hydro cost performance was average when compared to other US Hydro fleet operators on a 14

$/MWH basis.57 These study results are reproduced below Figure V-4.58 ORA completely ignores this 15

finding. 16

57 PA Consulting, at the recommendation of SCE, prepared a supplemental analysis that provided a direct

comparison of SCE to 13 other US hydro utility companies, utilizing Capacity Factor vs. 2011 O&M spend per MWh.

58 PA Consulting identifies SCE Hydro expenses as EIX, however only SCE Hydro expenses were captured for this table.

34

Figure V-4 2011 PA Consulting Hydro Benchmarking Report:

FERC Form 1 2011 O&M Expense ($/MWh)

It is important to note that the above $/MWH benchmarking results are solely 1

based on SCE’s recorded 2011 Hydro expenses and MWH production levels. As explained above, 2011 2

expenses were higher than typical due to SCE undertaking additional maintenance. This was further 3

compounded by SCE Hydro 2011 MWH production levels being lower than typical due to the ongoing 4

drought. The SCE rebuttal position Hydro O&M expense forecast is $6.978 million (12%) lower than 5

2011 recorded expense. 6

ORA assumes that Hydro expense can be readily and significantly reduced below 7

2008-2012 average spending levels. The SCE forecast provides a more reasonable approach to assure 8

sufficient funds are available to sustain the reliable operation of the SCE Hydro fleet, to assure that the 9

economical power provided by the SCE Hydro fleet continues to be fully available for SCE customers. 10

6. SCE’s Rebuttal To TURN 11

a) SCE Accepts TURN’s $0.083 Million Reduction To The FERC Account 536 12

Hydro Fees Forecast 13

SCE accepts TURN’s proposed $0.083 million ($2012) downward adjustment to 14

SCE’s TY 2015 forecast for FERC Account 536 relative to removing Kaweah SUP payments for pre-15

35

2008 operations from the 2008-2012 five-year average. However, SCE also notes that TURN’s 1

testimony on this issue is not fully accurate. TURN asserts that “…ratepayers will pay Edison more 2

money in the coming rate case cycle because Edison argued with the Federal government for five years 3

than if Edison had paid on time.”59 TURN’s assertion concerns SCE’s dispute with the US Park Service 4

regarding its proposed increase to the Kaweah 3 SUP fee. This dispute took several years to resolve. 5

The parties subsequently agreed to a much lower fee increase; i.e., an annual fee of approximately 6

$325,000 rather than approximately $1.4 million. SCE’s negotiation of the lower fee benefitted 7

ratepayers. 8

b) TURN’s Forecasting Methodology Using of 2013 Recorded-Unadjusted 9

Expenses Is Flawed and Contains Numerous Errors 10

TURN uses 2013 recorded-unadjusted expenses to propose certain adjustments to 11

SCE’s TY 2015 Hydro O&M forecast. Specifically, TURN proposes using: (1) a six-year average 12

(2008-2013) for FERC Account 536, (2) a three-year average (2010-2013) for Dam Safety Inspection 13

non-labor expenses for FERC Account 536, and (3) a two-year average (2012-2013) for labor expenses 14

in FERC Accounts 539 and 545. In aggregate, these proposed adjustments reduce SCE’s TY 2015 15

forecast by $1.032 million. 16

Using 2013 recorded-unadjusted expenses is invalid, and can result in significant 17

forecast errors. SCE explained its reasoning to TURN in SCE response to TURN-70 Q1.a (Appendix 18

D): “SCE utilizes an accrual-based accounting system. Therefore adjustments are necessary to correct 19

accruals… so that the final recorded/adjusted numbers will reflect the actual bills received.” It is not 20

possible to predict the number of adjustments that will be needed nor magnitude or direction (i.e., 21

increase or decrease) of these adjustments for any given FERC account. It takes SCE’s GRC team 22

several months to adjust recorded data before using the data in forecasts. Some examples of those 23

adjustments are removing non-recurring costs and reclassifying expenses from one account to another. 24

These adjustments require the professional judgment of SCE’s GRC team, and it is not possible to make 25

those adjustments at this time in the procedural schedule. 26

In addition, SCE discovered a number of errors in TURN workpapers concerning 27

FERC 536 Account. These errors include missing Final Cost Centers (FCC’s) and the inclusion of 28

certain labor expenses. These are errors that SCE, during the process of forecasting its TY O&M 29

59 TURN Testimony, p. 11.

36

expenses, would correct. As shown in Appendix D, SCE estimates, from its review of TURN’s analysis 1

for FERC Account 536, the magnitude of TURN’s errors are at least $0.281 million.60 Furthermore, use 2

of 2013 recorded expense data is not consistent with the Commission’s Rate Case Plan.61 Additional 3

objections to TURN’s use of unadjusted 2013 recorded data to forecast TY 2015 expenses are discussed 4

in Chapters III and VI . 5

c) TURN’s Assessment That SCE Recorded The Same $0.121 Million In Hydro 6

And Claims FERC Accounts Is Incorrect 7

TURN claims that SCE recorded $121,000 (constant 2012$) in 2010 [sic 2009] in 8

both FERC Accounts 539 and 925 based on the fact that Final Cost Center (FCC) 200989 appears in 9

both workpapers62 and TURN did not observe an adjustment between these two FERC Accounts. 10

TURN proposes to remove $24,000 from the FERC Account 539 non-labor five-year average. 11

TURN wrongly assumes that the referenced $121,000 (2012$) recorded to FERC 12

Account 539 in 2010. The referenced $121,000 (constant 2012$) was directly charged to FERC 13

Account 925 and not to FERC Account 539.63 This amount is not included in the 2008-2012 recorded 14

expenses or the TY 2015 forecast for FERC Account 539, as assumed by TURN. 15

The Commission should reject TURN’s recommendation to reduce the TY 2015 16

non-labor forecast by $24,000 in FERC Account 539. See SCE-26 for SCE’s rebuttal to this 17

recommended adjustment. 18

d) TURN Errs In Its Assumption That San Gorgonio Expenses Are No Longer 19

Recoverable by Ratepayers 20

TURN seeks to remove ongoing expenses incurred for the San Gorgonio 21

powerhouse, thereby reducing the SCE O&M expense forecast by $0.086 million. These expenses are 22

for the ongoing operation of the San Gorgonio water diversions and flowlines, which provide water to 23

downstream users in accordance with long-standing agreements between SCE and those parties. These 24

agreements were necessary so that SCE customers were able to benefit from the many decades of San 25

60 Appendix D, “TURN Original “Hydro 536 539 and 545 Workpapers – hydro 2013 data.” 61 D.07-07-004, D.93-07-030 and D.89-01-040. 62 The 2010 nominal dollars were $115,000. 63 The Claims Reserve costs are recorded to FERC Account 925 in 2010 as shown in SCE-08, Vol. 2,

Workpapers p. 108, line FERC Form 1 Recorded (Nominal$).

37

Gorgonio power generating operations. SCE continues to negotiate with the parties to arrive at an 1

agreement whereby SCE can complete the transfer or decommissioning of the San Gorgonio facilities, 2

and thereby end the need for SCE to continue to operate and maintain the remaining facilities. 3

The Commission should reject TURN’s recommendation to reduce SCE’s TY 4

2015 O&M expenses related to the San Gorgonio hydro project. In its justification, TURN only states 5

that this facility is “no longer used and useful in providing utility service.” Although the San Gorgonio 6

hydro project is no longer producing electricity, SCE is required contractually to maintain the facilities 7

and thus continues to incur yearly O&M expenses, which are recoverable by ratepayers. This contract 8

will continue until either ownership has passed to new owners or decommissioning of the facilities has 9

been completed. The major O&M expenses include the performance of flow-line maintenance, staff to 10

facilitate decommissioning of the facilities, and site security. Based on SCE’s contract for maintaining 11

the facilities and TURN’s error in assuming that these expenses are no longer recoverable, the 12

Commission should reject TURN’s proposal. 13

For a status update for the San Gorgonio Decommissioning Project please refer to 14

SCE’s rebuttal to ORA’s proposed capital reduction for the San Gorgonio project in Section V.B.5(e) of 15

this testimony. 16

B. Hydro Capital 17


SCE Hydro capital investments are required for infrastructure (e.g. flowlines and 19

powerhouse roofs) and equipment replacement and our ongoing efforts to renew the Federal Energy 20

Regulatory Commission (FERC) licenses for many of our hydro facilities. The total Hydro capital 21

expenditure forecast is $438.293 million for 2013-2017 in nominal dollars, and for 2013, 2014 and 2015 22

are $82.1 million, $72.5 million and $99.2 million, respectively. 23


ORA recommends authorizing total capital expenditures for 2013, 2014 and 2015 of 25

$60.2 million, $69.4 million, and $67.0 million respectively. 26

ORA proposes adjusting SCE’s 2013 forecasted expenditures by $21.597 million to 27

reflect the recorded amount of $60.177 million. ORA also proposes adjusting SCE’s 2014 and 2015 28

forecast for: (1) 27 projects that were identified as being completed in 2014; (2) one project (Mammoth 29

Pool Fishwater Generator) that is no longer being perused; (3) twelve projects that were identified by 30

ORA as being off-schedule; and (4) six projects ORA believes contain excessive contingency. ORA 31

38

also proposes a reduction of $1.500 million in 2015 to the San Gorgonio Decommissioning project.64 1

No other intervener provided any testimony regarding SCE’s 2013-2015 Hydro capital forecast. SCE’s 2

responds to ORA’s recommendations below. 3


Table V-9 below summarizes the forecast reductions proposed by ORA. 5

Table V-9 2013-2015 Capital Forecast Comparison

($000) ($Nominal)

2013 2014 2015 Total

SCE 82,134 72,649 99,231 254,014

ORA�Proposed�Reductions 57,5002013 Recorded (21,957) 0 0 (21,957)Completed Projects 0 (2,700) (4,000) (6,700)Mammoth Pool FWG 0 (1,500) (9,000) (10,500)Projects off schedule 0 3,900 (12,800) (8,900)Contingency Adjustment 0 (2,928) (5,015) (7,943)San Gorgonio 0 0 (1,500) (1,500)

��TOTAL�ORA�REDUCTION (21,957) (3,228) (32,315) (57,500)

Lower�than�SCE:

4. SCE Will Adopt 2013 Recorded Expenditures 6

Consistent with ORA’s recommendation, SCE will adopt 2013 recorded expenditures of 7

$60.177 million. 8

5. SCE’s Rebuttal To ORA 9

a) SCE Accepts ORA’s Recommended Adjustments Due To The Cancellation 10

Of The Mammoth Pool Fishwater Generator Replacement Project 11

SCE accepts ORA’s recommended downward adjustments of $1.500 million and 12

$9.000 million for 2014 and 2015 respectively for SCE’s Hydro capital forecast, reflecting the removal 13

of the Mammoth Pool Fishwater Generator Replacement Project from the SCE forecast.65 14

64 ORA identifies an additional reduction in the amount of $0.176 million for 2013. This reduction was already

accounted for in the $21.957 million reduction requested to match 2013 recorded expenditures. 65 See DRA-115-PM1 Q. 7.

39

b) ORA’s Adjustment For 2014 Completed Projects Is Premature And Fails To 1

Capture All Project Costs 2

SCE provided, at ORA’s request, a listing of those projects being requested in the 3

2015 Hydro GRC submittal that as of April 3, 2014, had been completed.66 Based on this information, 4

ORA has recommended: “[a]djusting SCE’s forecast to reflect the completed projects [i]n 2014 and 5

2015 respectively.”67 This is not appropriate. Although a project may be identified as either in-service68 6

or completed, this does not mean that all project expenditures have been captured. For example, trailing 7

costs,69 retainage,70 and final accounting review of all recorded expenditures must be completed prior to 8

considering all project expenditures as being captured and the project completed and total expenditures 9

finalized. 10

To demonstrate this, SCE provides in Appendix D, SCE Response to DRA-271-11

PM1 Question 5, a comparison of those projects for which ORA is requesting a downward adjustment. 12

This comparison between the recorded unadjusted values provided on April 3, 2014, and August 28, 13

2014, shows that an additional $0.318 million in expenditures for these projects have been identified 14

since April 3, 2014, and SCE expects that additional costs will be attributed to these projects at the end 15

of the year when SCE’s 2014 books are closed. ORA’s adjustment request utilizing recorded to date, 16

but not yet finalized expenditures, is premature and would fail to capture all project costs. Using 2013 17

recorded capital costs is appropriate for capturing 2013 expenditures, because the 2013 books are closed, 18

as noted above. But this is not the case for 2014 capital costs, including how those costs relate to capital 19

costs forecast for 2015. Therefore, SCE recommends that the Commission reject ORA’s proposal to 20

adjust SCE’s 2014 and 2015 capital forecast. 21

66 See Appendix D, SCE response to DRA-271-PM1 Q. 5. 67 ORA-07, p. 19. 68 Available for use. 69 A project can be placed in-service prior to all work being completed, such as final painting, paving, etc. Also,

cost invoices can continue to be processed for several months after placing a project in-service. 70 A portion of the agreed upon contract price deliberately withheld until the work is substantially complete in

order to assure that contractor or subcontractor will satisfy its obligations and complete a construction project.

40

c) Considering The Current Expenditure Level Of A Project Alone Cannot 1

Provide An Accurate Correlation As to Whether A Project Is Either “On” 2

Or “Off” Schedule 3

ORA recommends shifting the forecasted expenditures by one year (i.e., shift 4

2013 forecast expenditures into 2014 and 2014 into 2015) for fifteen projects it considers to be “off-5

schedule.”71 ORA bases their recommendation on the fact that the total costs to date are lower than 6

forecasted spending levels for these projects.72 ORA reasons that when the current expenditure level is a 7

low percentage of the total project budget that the project is then off-schedule. ORA’s reasoning is 8

flawed, and does not appropriately consider the nature of project timelines, corrective actions that may 9

be taken to accelerate remaining work on certain projects, and project activity sequencing and durations. 10

SCE informed ORA that all fifteen projects were on-schedule, 73 when 11

considering the overall project timeline, which contain slack time or float.74 Certain activities may take 12

longer than expected, but the project may still be on schedule due to contingency built into the project 13

timeline. This contingency allows overall project completion targets to still be met even when certain 14

activities take longer than expected. 15

In addition, projects can also be accelerated in order to meet the project’s final 16

deadlines.75 SCE often utilizes its available resources to accelerate the remaining projects activities 17

when needed to restore the project to an on-schedule status. 18

Finally, ORA does not understand that considering the current expenditure level 19

of a project in isolation cannot, and does not, provide an accurate correlation as to whether a project is 20

71 In testimony ORA identified this number as 12, but ORA’s WP’s show this number to be 15. SCE believes

that ORA’s WP’s are correct. 72 See ORA-07, p. 22, and Appendix D, ORA response to SCE-DRA-046-PM1 Q1. 73 See Appendix D, SCE response to DRA-220-PM1 Q. 3.a-z , and SCE response to DRA-271-PM1 Q1. 74 The schedules for many projects do not assume that the project is to be completed in the least time possible.

As such, these schedules can allow for certain pre-construction activities to start later than previously planned while still completing the project on or near its overall planned completion date. For example: A project with a forecasted completion date at the end of summer or beginning of fall (this is often the case for Hydro projects due to harsh winter weather conditions) can have engineering scheduled during the preceding year. Depending on the level of complexity, this work can oftentimes be performed at the beginning of the year (i.e. the year scheduled for construction) and would not delay to project completion timeline.

75 Acceleration can include situations where activities normally performed in sequence are instead performed in parallel.

41

either “on” or “off” schedule. Figure V-5 below shows a typical spending pattern for a generic 1

construction project: 2

Figure V-5 Construction Project Spending Pattern

Conceptual Transfer

Final Engineering and Construction Trailing Costs & Retention Release

Project In-Service

Cos

t

Time

ExecutionPlanning

Conceptual Design

Pre-Engineering

As shown in Figure V-5, the costs incurred during the early stage of a projects 3

life-span (Conceptual Design and Pre Engineering) are minimal, while the majority of a project costs are 4

incurred towards the end. Each project time-line is unique; as projects may take weeks, months, or even 5

many years to complete. Concluding that a project will not complete “on” schedule simply because a 6

certain level of spending has not occurred is faulty reasoning. One must also know the anticipated 7

project timeline (i.e. how long does the project of this type typically take to perform: weeks, months or 8

years), the amount of slack time and/or if the project can be fast tracked. Only with this information, 9

none of which ORA possesses, can a determination then be made as to whether a project is either “on” 10

or “off” schedule. The Commission should thus reject ORA’s proposal. 11

d) Contingencies For Hydro Projects Are Consistent With Association For The 12

Advancement Of Cost Engineering (AACE) Guidelines 13

ORA also asserts that SCE’s Hydro capital forecast contains excessive 14

contingency. ORA is wrong. First, the summed total average contingency included by SCE reasonably 15

42

lies between 10% and 15%.76 Second, none of the six individual projects77 ORA identifies in testimony 1

have excessive contingency. The weighted average contingency for these six projects, which are 2

designated as Class 4 Level, is 25% and each project contains no more than 30% contingency.78 These 3

contingencies are consistent with the Association for the Advancement of Cost Engineering (AACE) 4

guidelines for the expected accuracy range (+30/-15% and +120/-60) for a project designated with a 5

Class 4 Level project. Furthermore, ORA acknowledges that in prior GRC decisions, the Commission 6

has indicated that contingencies based on AACE guidelines are reasonable.79 In Appendix D of this 7

testimony, SCE has provided excerpts from the “AACE International – Skills & Knowledge of Cost 8

Engineering” book that further supports these contingency amounts. 9

ORA’s approach of applying a “one-size-fits-all” approach of applying 10% 10

contingency to projects of varying types (AACE class level) and stages of completion is not prudent and 11

would not provide an accurate amount of funding that will be required to complete these six projects. 12

As mentioned above, SCE’s Hydro capital forecast averages between 10% and 15% contingency. 13

Project-by-project contingency levels depend on the type and phase of the project and the confidence 14

level of the estimate. SCE’s Hydro capital request, which contains approximately 10% to 15% 15

contingency on average, and more specifically, 25% to 30% for the six projects (of which one now has 16

an 8% contingency) questioned by ORA, is consistent with the Commission’s previous GRC decisions 17

and AACE guidelines. 18

It would be short-sighted for SCE to use project cost estimates that are falsely too 19

low for any given project, due to not including an appropriate level of contingency relative to the 20

amount of project engineering work that has been completed to date. This could lead to over-estimates 21

of the net economic value of the project for SCE customers. The Commission should reject ORA’s 22

proposed reduction to SCE’s 2014 and 2015 forecast. 23

76 See Appendix D, SCE response to DRA-106-PM1 Q22a-c. 77 Lee Vining Substation, Gem Lake Dam-Resurface Down Stream Side, Waugh Dam-Seismic

Upgrade/Pressure Grout, Rush Creek-Rebuild Tram Track and Replace Tram Car, Kern River 3-Rebuid Tunnel, and Agnew Dam-Resurface Dam/Seismic Upgrade.

78 See Appendix D, SCE response to DRA-220-PM1 Q3.a-z. 79 D.12-11-051, pp. 36-37.

43

e) San Gorgonio Decommissioning Is Necessary To Maintain Compliance With 1

FERC Requirements 2

The Commission should reject ORA’s recommendation to reduce SCE’s funding 3

for the San Gorgonio Decommissioning project. ORA asserts that SCE did not provide justification 4

necessary to support the forecast expenditures because SCE’s direct testimony for this GRC was the 5

“…same exact language [SCE] used in its 2012 GRC application.”80 ORA essentially suggests that SCE 6

was required to update testimony from the 2012 GRC submittal to provide proper justification for SCE’s 7

2015 GRC submittal, even though the scope of work for the San Gorgonio Decommissioning project has 8

not changed. ORA also claims that SCE failed to provide an update to an ORA data request that sought 9

the following: “Provide bases for each forecast included in Table VIII-32 (page 77 hydro capital), 10

including justification for process(es) used in forecasting and all methods, and assumptions.”81 SCE 11

provided ORA exactly what was asked: “[A] detailed cost estimate and explanation for how that 12

estimate was developed.” ORA did not ask SCE to provide an update on the status of the San Gorgonio 13

project. In any event, the most recent update is that SCE has continued to meet with the stakeholders, 14

including water rights holders, the USFS and FERC. These negotiations have been contentious, and 15

have lasted longer than originally forecast. This resulted in the San Gorgonio Decommissioning Project 16

delays experienced between the SCE 2012 and 2015 GRCs. SCE believes that the negotiations will be 17

resolved in the foreseeable future. SCE believes the San Gorgonio Decommissioning cost forecast in 18

this GRC continues to provide a reasonable estimate of the costs (and the timing of the costs) that SCE 19

will incur to end SCE's ongoing obligation to operate and maintain the San Gorgonio water diversions 20

and flowlines. The estimate is reasonable and should be adopted.21

80 ORA-07, pp. 26-27. 81 DRA-010-PM1, Q. 5.

44

VI. 1

MOUNTAINVIEW O&M AND CAPITAL 2

A. Mountainview O&M 3

1. SCE Application 4

The TY 2015 O&M expense forecast for Mountainview is $50.263 million. This forecast 5

includes the levelized cost (i.e., the average annual cost of 2015 through 2017) to perform Hot Gas Path 6

Inspection (HGPI) overhauls on both units in 2016.82 These overhaul costs include the six-month-ahead 7

pre-payments payable to General Electric (GE) in 2015 for the Unit 3 Hot Gas Path overhaul forecast for 8

early 2016. 9

Overhauls are conducted on each of Mountainview’s two generating units approximately 10

every three years, with the most recent overhauls completed in 2013.83 While overhauls on a given 11

generating unit are not needed every year, overhauls are a significant expense when they occur. The 12

SCE Mountainview O&M expense forecast is significantly higher in 2015 and 2016 than in 2017 13

because we plan to conduct overhauls in 2016 (and will incur an overhaul pre-payment in 2015), and no 14

overhauls in 2017. In determining our TY 2015 O&M forecast, SCE averaged the cost of these 15

overhauls over the three-year rate case cycle of 2015 through 2017, in a manner consistent with how the 16

similar Mountainview overhaul costs were averaged in SCE Test Year 2009 GRC decision.84 17

A significant portion of Mountainview total annual O&M expense consists of various 18

payments for the plant’s Contract Services Agreement (CSA) with GE, who manufactured the turbine 19

generators and other significant portions of the plant. Pursuant to the CSA, GE provides various 20

services (including certain overhaul maintenance work). These CSA costs include overhaul pre-21

payments (i.e., the “Hot Gas Path Adder Fee”) as noted above, and five other recurring fees.85 The GE 22

82 Mountainview Generating Station consists of two essentially identical units; Unit 3 and Unit 4. The plant was

constructed at the same site as the former San Bernardino Generating Station, which consisted of Units 1&2 and was subsequently decommissioned.

83 The overhauls on each of Mountainview's two units are typically not performed at the same time. For example, in 2013, Unit 4 was overhauled in the spring and Unit 3 was overhauled in the fall.

84 D.09-03-025, pp. 31-33. Likewise, the forecast overhaul costs for other SCE-owned fossil-fueled power plants were averaged over the three-year GRC rate cycle in the Commission's Decisions in SCE 2003, 2006 and 2009 GRC proceedings.

85 The Fixed Fee and Variable Fee are invoiced quarterly, the Performance Fee is invoiced yearly; collectively, SCE refers to these three fees as Annual Fees. The Hot Gas Path Adder Fee, the Use Tax Reimbursement and the Cash Adjustment Fee are each invoiced commensurate with each overhaul (with prescribed invoice timing

(Continued)

45

CSA payments account for over half of the SCE TY forecast. All of the Mountainview CSA costs are 1

accounted for in the O&M “Other” cost category.86 2

The TY 2015 forecast includes FERC Account 549 (Mountainview Operations) and 3

FERC Account 554 (Mountainview Maintenance).87 The forecast for Mountainview consists of four 4

components: 5

1. The Base forecast, which captures the plant’s annual labor and non-labor O&M costs. 6

The SCE Base forecast is $20.350 million, and includes all of Mountainview FERC 7

Account 549 (Operations), and a portion of FERC Account 554 (Maintenance). SCE 8

used Last Recorded Year (LRY) to forecast labor and non-labor in FERC Account 9

549 and labor in FERC Account 554 as the LRY as these expenses have remained 10

relatively stable over the last three years. For non-labor in FERC Account 554, SCE 11

used a 2008-2012 five-year average after removing the overhaul costs that were 12

incurred in 2009. 13

2. CSA Annual Fees (i.e., the Fixed Fee, Variable Fee and Performance Fee), which 14

capture annually recurring fees for the GE CSA. The SCE forecast for CSA Annual 15

Fees is $ million, based on a five-year average of 2008-2012 and adjusted for 16

CSA contract inflation. The Variable Fee also includes an increase from GE Tier 1 to 17

Tier 2 pricing in 2014. The CSA Annual Fees are forecast in FERC Account 554 in 18

other expenses. 19

3. CSA Major Outage Fees (i.e., the Hot Gas Path Adder Fee, the Use Tax 20

Reimbursement and the Cash Adjustment Fee), which capture CSA fees triggered by 21

major maintenance work (i.e., the planned 2016 HGPI overhauls) and are also 22

adjusted for CSA contract inflation. The SCE forecast for CSA Major Outage Fees is 23

Continued from the previous page

pursuant to the CSA); collectively, SCE refers to these three fees as Major Outage Fees. See SCE-02 Vol. 8 p. 29 for further details.

86 The Mountainview O&M expense consists of Labor, Non-Labor and "Other" cost categories. There are no other costs in the Mountainview "Other" cost category besides the GE CSA costs.

87 As requested by the ORA, and explained in more detail in SCE-02, Vol. 8, in this GRC consolidated all of the Mountainview operations accounts into FERC 549 and all Mountainview maintenance accounts into FERC 554.

46

$ million (i.e., the forecast 2015-2017 annual average cost). The CSA Major 1

Outage Fees are forecast in FERC Account 554 in other expenses. 2

4. The Non-CSA 2016 Overhaul Cost Adjustment, which captures forecast costs for the 3

planned 2016 HGPI overhauls not covered by the GE CSA. The SCE forecast for the 4

Non-CSA 2016 Overhaul Cost Adjustment is $1.728 million by adding the difference 5

of the 2009 non-labor from the non-labor average of the years 2008, 2009, 2010, 6

2011 and 2012 and normalizing this amount over the 2015-2017 general rate case 7

cycle. The Non-CSA 2016 Overhaul Cost Adjustment is forecast in FERC Account 8

554 in as labor and non-labor expenses. 9

2. ORA Position 10

ORA recommends several reductions to the SCE TY forecast, totaling $2.974 million, 11

which is 6% of the SCE forecast. 12

ORA proposes reducing the Base forecast component by $1.699 million by using 2012 13

LRY to forecast the FERC Account 554 (maintenance) non-labor portion of the Base forecast. For the 14

FERC Account 554 non-labor portion, SCE used a 2008-2012 five-year average after removing the 15

overhaul costs that were incurred in 2009. ORA asserts that LRY should be used because FERC 16

Account 554 non-labor costs trended downward during 2010 through 2012. 17

ORA proposes reducing the FERC Account 554 other expense forecast by $0.334 million 18

for the CSA Major Outage Fees.88 ORA computes this adjustment by reducing the forecast annual 19

escalation factor for CSA fees.89 To forecast the CSA fee annual escalation factor, SCE used the 2008-20

2012 five-year average of past recorded escalation. ORA instead uses a 2009-2013 five-year average, 21

thereby incorporating the recorded 2013 CSA inflation factor, which is now known. 22

In addition, ORA proposes reducing the CSA Annual Fees by $0.941 million.90 ORA 23

computes this adjustment by: (1) using the same ORA revision to the CSA fee annual escalation factor 24

88 ORA-07, p. 29, Table 7-11. 89 The CSA contains a Total Escalation Factor (TEF) to account for annual inflation. The TEF is applied to all

six of the CSA fees. The CSA has a specific formula for computing TEF. Therefore, the CSA TEF is forecast separately (i.e., for years 2013 and beyond) from the various forecast annual escalation rates discussed in SCE-10, Vol. 1 Revised.

90 ORA originally forecast this reduction to be $3.141 million (e.g., ORA -7, p. 29, Table 7-11), but SCE identified several formula errors in ORA’s forecast (i.e., in ORA workpaper WP7-8C). In response ORA revised its CSA Variable Fee Forecast in SCE-DRA-065-PM1, thereby producing a revised Annual Fee

(Continued)

47

that is discussed above, and (2) using a three-year average of recorded 2009-2011 FFH data to forecast 1

the Variable Fee portion of the Annual Fees. The SCE forecast uses the 2008-2012 five-year average of 2

the actual recorded payments made to GE for this fee.91 An average of 26,914 FFH per Year were 3

recorded during 2009-2011, whereas an average of 28,291 FFH per Year were recorded during 2008-4

2012.92 5

ORA indicates that it did not use recorded 2012 FFH data because annual FFH trended 6

downward from 2008 to 2013. But this reasoning is not accurate based on formula errors in ORA’s 7

model.93 This is discussed in more detail later in this volume. ORA also states that 2008 FFH data 8

should not be used because it is higher than the annual FFH that are likely to be incurred in the future. 9

ORA asserts that the relatively high FFH recorded in 2008 (i.e., compared to subsequent years) is 10

because the plant operated under a Power Purchase Agreement (PPA) from 2006 through 2008, and then 11

transitioned to GRC Base Rate recovery starting in 2009. 12

ORA does not propose any adjustments to the SCE forecast for Non-CSA Overhaul Costs 13

for the planned 2016 HGPI overhauls. 14


TURN proposes several reductions to SCE TY forecast, totaling $1.822 million (4%). 16

TURN proposes reducing the Base forecast component of FERC Account 549 17

(operations) by $0.233 million; consisting of a $0.112 million reduction to labor and a $0.121 reduction 18

to non-labor. TURN proposes using a 2010-2013 four-year average to forecast Operations labor and 19

non-labor, whereas SCE used LRY. TURN believes Operations costs have been fluctuating over the last 20

four years (i.e., 2010-2013) and 2013 is the lowest of these four years. 21

Continued from the previous page

forecast of $ million, or $0.940 million less than SCE. See Appendix E for a copy of SCE-DRA-065-PM1 Q. 1.a-f.

91 The Annual Variable Fee is the largest of the six CSA fees (accounting for almost half of the SCE forecast of total CSA fees) and is computed by multiplying the FFH fee rate by the amount of FFH for each of the plant's four combustion turbines. Hence, as FFH increases, the FFH Variable Fee increases.

92 Because of timing issues related to how the fee is computed for CSA quarterly billing purposes, the ORA use of FFH data to calculate the fee introduces additional slight differences compared to the SCE forecast, which is based on actual 2008-2012 CSA recorded quarterly payment data. The method used by ORA to compute quarterly FFH also accounts for some of this difference.

93 These errors were subsequently corrected by ORA in SCE-DRA-065-PM1 Q. 1.a-f. A copy of SCE-DRA-065-PM1 is provided in Appendix E.

48

TURN also proposes adjusting SCE forecast by transferring $0.070 million from FERC 1

Account 549 non-labor to other expenses. The $0.070 million is the plant’s Added Facilities cost, 2

whereby a portion of SCE Transmission costs are allocated to Mountainview to maintain the plant’s 3

connection to the transmission grid. TURN observes that the SCE forecast of this cost already accounts 4

for escalation from $2012 to $2015, and therefore should be in the other category rather than the non-5

labor category. This transfer also results in a very small (i.e., $0.002 million in non-labor) net reduction 6

to SCE TY forecast, which is part of the $0.233 million adjustment discussed above. 7

In addition, TURN proposes a $1.557 million reduction to other expenses in FERC 8

Account 554 (maintenance), which consists of a $0.942 million reduction to CSA Annual Fees and a 9

$0.615 million reduction to CSA Major Outage Fees. These reductions result from the TURN proposed 10

adjustments to the 2013 to 2017 CSA annual escalation factors. The TURN proposal is based on its 11

analysis of the indices used to compute CSA annual escalation as opposed to SCE’s and ORA’s use of 12

an average of historical CSA annual escalation factors. 13

Lastly, TURN proposes a $0.032 million labor reduction to the Non-CSA Overhaul Cost 14

portion of FERC Account 554. The TURN forecast is based on the difference between plant’s annual 15

Maintenance labor costs recorded costs during 2010 through 2012 (i.e., a three-year average), as 16

compared to those recorded in 2009. SCE had performed the same kind of comparison; however, SCE 17

had also included recorded 2008 costs in the analysis. TURN believes 2008 recorded costs should not 18

be included in the analysis as SCE was still ramping up plant staffing at that time. 19

4. Parties’ Positions By FERC Account 20

Table VI-10 below summarizes the forecast in SCE’s Application, and the forecasts 21

proposed by ORA and TURN, summarized by FERC Account, divided into the labor, non-labor and 22

other categories.94 Also shown is the SCE rebuttal position forecast, which reflects SCE’s acceptance of 23

certain of the forecast reductions proposed by TURN. 24

94 Table VI-10 reflects: (a) SCE's application forecast in SCE-02, Vol. 8, as well as Errata-SCE-02, Vol. 8; (b)

ORA's proposed adjustments in ORA-07 and corrections to ORA's proposed adjustments as provided in SCE-DRA-065-PM1 Q. 1.a-f (Appendix E); (c) TURN's proposed adjustments in TURN-05; and (d) SCE’s rebuttal position as presented in this exhibit.

49

Table VI-10 TY 2015 O&M Position Comparison by FERC Account

($000) ($2012)

SCE Application

ORA Adjustments

TURN Adjustments


FERC 549 Labor 3,790$ -$ (112)$ 3,790$ Operations NonLabor 4,491$ -$ (191)$ 4,419$

Other -$ -$ 70$ 70$ Total 8,281$ -$ (233)$ 8,279$

FERC 554 Labor 3,945$ -$ (32)$ 3,913$ Maintenance NonLabor 9,852$ (1,699)$ -$ 9,852$

Other 28,185$ (1,275)$ (1,557)$ 26,628$ Total 41,982$ (2,974)$ (1,589)$ 40,393$

Mountainview TOTAL 50,263$ (2,974)$ (1,822)$ 48,672$

5. Parties’ Positions By Forecast Cost Component 1

As noted above, the SCE forecast is comprised of four cost components. Table VI-11 2

below summarizes the SCE TY forecast for Mountainview, and the reductions proposed by ORA and 3

TURN, for each of these cost components. Also shown in Table VI-11 is the SCE Rebuttal Position 4

forecast. Note that this table sub-divides the Base O&M Forecast component into its operations and 5

maintenance sub-parts. 6

50

Table VI-11 TY 2015 O&M Position Comparison by Forecast Component

($000) ($2012) Forecast Method

Acnt Labor Non-Labor Other Total Labor Non-Labor OtherSCE APPLICATIONBase Operations 549 3,790 4,491 0 8,281 LRY LRYBase Maintenance 554 3,718 8,351 0 12,069 LRY Itemized Base O&M Sub-Total 7,508 12,842 0 20,350CSA Annual Fees 554 0 0 ItemizedCSA Maj Outage (OH) 554 0 0 ItemizedNonCSA Overhaul 554 227 1,501 0 1,728 Itemized Itemized TOTAL 7,735 14,343 28,185 50,263

ORA Lower than SCE: 2,974Base Operations 549 3,790 4,491 0 8,281 SCE SCEBase Maintenance 554 3,718 (X) 6,652 0 10,370 SCE LRY Base O&M Sub-Total 7,508 11,143 0 18,651CSA Annual Fees 554 0 0 (X) ItemizedCSA Maj Outage (OH) 554 0 0 (X) ItemizedNonCSA Overhaul 554 227 1,501 0 1,728 SCE SCE TOTAL 7,735 12,644 26,910 47,289

TURN Lower than SCE: 1,822Base Operations 549 (X) 3,678 (X) 4,300 (X) 70 8,048 2010-13 Ave 2010-13 Ave AllocateBase Maintenance 554 3,718 8,351 0 12,069 SCE SCE Base O&M Sub-Total 7,396 12,651 70 20,117CSA Annual Fees 554 0 0 (X) ItemizedCSA Maj Outage (OH) 554 0 0 (X) ItemizedNonCSA Overhaul 554 (X) 195 1,501 0 1,696 Itemized SCE TOTAL 7,591 14,152 26,698 48,441

SCE REBUTTAL POSITION Reduced by: 1,591Base Operations 549 3,790 (X) 4,419 (X) 70 8,279 Application LRY TURNBase Maintenance 554 3,718 8,351 0 12,069 Application Application Base O&M Sub-Total 7,508 12,770 70 20,348CSA Annual Fees 554 0 0 (X) TURNCSA Maj Outage (OH) 554 0 0 (X) TURNNonCSA Overhaul 554 (X) 195 1,501 0 1,696 TURN Application TOTAL 7,703 14,271 26,698 48,672

2015 TY Forecast ($1,000 - 2012)

(X) Indicates an adjustment relative to SCE’s application.

The subsequent sections of this chapter summarize the TURN adjustments that SCE 1

incorporated into its rebuttal position forecast, and explain SCE’s objections to ORA proposed 2

reductions and to the remaining adjustments proposed by TURN. 3

51

6. SCE Rebuttal To ORA and TURN’s Adjustments To The Base O&M Forecast 1

Component 2

a) SCE Accepts TURN’s Proposal To Move Added Facilities Costs From Non-3

Labor To Other 4

As noted above, the Base O&M Forecast Component includes all of the costs of 5

FERC Account 549 (operations). SCE accepts TURN’s proposal to move Added Facilities Costs in 6

FERC Account 549, at $0.070 million, from the non-labor to the other expense category, including the 7

$0.002 million reduction to non-labor associated with this transfer. 8

b) TURN’s Forecast for FERC Account 549 Contains Significant Errors 9

Because Of Limitations Inherent In Using 2013 Recorded-Unadjusted 10

Expense Data 11

TURN proposes to reduce the FERC Account 549 forecast by $0.233 million 12

(labor and non-labor).95 Whereas SCE had used LRY, TURN proposes using a 2010-2013 four-year 13

average to forecast Operations labor and non-labor expenses. SCE disagrees with TURN’s use of 2013 14

recorded-unadjusted O&M cost data for forecasting the plant’s TY 2015 TY expense. 15

TURN’s use of 2013 recorded-unadjusted expenses resulted in substantial 16

forecast errors.96 For Mountainview, these errors include the fact that TURN failed to capture all of the 17

Final Cost Centers associated with FERC Account 549 (as aggregated for GRC forecasting) contained in 18

the unadjusted 2013 data. TURN erroneously computed 2013 FERC Account 549 expenses to be 19

$3.865 million for labor and $3.840 million for non-labor ($2013). Using the same 2013 recorded-20

unadjusted expense database used by TURN, SCE computes these totals to actually be $4.592 million 21

for labor and $4.146 million for non-labor, for a total of $8.738 million ($2013).97 This is $1.032 22

95 This includes the $0.002 million net reduction for the TURN "$0.070 million non-labor to other" adjustment

discussed above, which SCE accepts. SCE objects to the remainder (i.e., $0.231 million) of the $0.233 million TURN proposed adjustment to FERC Account 549.

96 In DRA-Verbal-057, SCE provided 2013 recorded-unadjusted expense data by Final Cost Center. Appendix E includes DRA-Verbal-057 and relevant extracts from the large data base provided in DRA-Verbal-057.

97 A review of the unadjusted 2013 database shows that TURN failed to include two cost entries that are part of the aggregated FERC Account 549. These include a labor cost entry of $0.726 million (on line 1388 of the database) and a non-labor cost entry of $0.306 million (on line 1389 of the database). These entries exactly match the difference (in $2013) between TURN totals and SCE totals for FERC Account 549 for labor and non-labor, respectively. These entries can be seen in the in DRA-Verbal-057 data base extract provided in Appendix E.

52

million higher than TURN’s computations.98 Because the actual 2013 totals are significantly higher 1

than those computed by TURN, the TURN forecast (which is partially based on 2013 data) is 2

significantly understated. After correcting these errors, use of the TURN 4-year average of 2010-2013 3

would increase the SCE forecast, and would not reduce it as erroneously asserted by TURN. 4

In this instance, the missing cost entries actually record to FERC Account 550 5

Rents. 99 As requested by ORA and other parties, in this GRC SCE consolidated into FERC Account 6

549 the 2008-2012 expenses that recorded in FERC Accounts 546, 548, 549 and 550. That is, 7

consolidating these FERC Accounts represents one “adjustment” in producing the 2008-2012 recorded-8

adjusted O&M expense data in the general rate case. 9

As TURN discusses, it is very difficult to analyze the 2013 expense database in its 10

present form, given the complexity accounting systems such as the one used at SCE.100 SCE personnel 11

have not yet undertaken the extensive work required to convert the recorded-unadjusted 2013 data into 12

recorded-adjusted format that SCE provided in the general rate case for 2008-2012. TURN’s attempt to 13

incorporate 2013 recorded-unadjusted data into FERC Account level forecasts is unreasonable and 14

dismissive of the rigor involved in preparing recorded-adjusted expenses and further analyzing that data 15

in testimony.101 Indeed, ORA’s agrees with SCE that 2013 O&M expense data “would merely be 16

supplementary.”102 TURN also selectively incorporates SCE’s 2013 expense in certain FERC accounts 17

only when it works to their benefit. The Commission should disregard any recommendations which rely 18

on, in whole or in part, 2013 recorded-unadjusted O&M expenses. 19

98 Using SCE same 2013 inflation factor as was used by TURN, SCE computes these costs at $4.467 million

labor, $4.076 million non-labor, and $8.543 million total, in $2012. TURN had computed the total at $7.536 million in $2012, which is $1.007 million less than the SCE calculation. Adding this amount to the TURN 4-year average increases that average by $0.252 million, which fully negates TURN's $0.233 million proposed downward adjustment. See Appendix E, Mountainview 549 Operations Forecasts.

99 The unadjusted 2013 data base provided to TURN included a short summary description for each FCC (i.e., as a brief “text” box in the data base). These text summaries do not always indicate which power plants are involved, and can potentially be confusing in other ways. Parties attempting to interpret these “text” boxes, without engaging SCE for further explanation, could easily reach erroneous assumptions regarding the full scope of O&M expense that record to a given FCC. TURN indicates they used FCC data to sort the large 2013 unadjusted data base, and it appears that mistaken assumptions regarding FCCs may be the cause of the TURN error.

100 TURN-05, Marcus, pp. 5-8. 101 See SCE-17 regarding TURN-05, Marcus. 102 Prehearing Conference February 11, 2014, Statement by Mr. Gruen of ORA, p. 49.

53

Consistent with the Commission’s guidance in D.89-12-057 and D.-04-07-022, 1

the SCE forecast for FERC Account 549 uses LRY for labor and non-labor because the expenses 2

remained stable between 2010 and 2012. 103 The FERC Account 549 non-labor forecast is appropriately 3

based on a reasoned analysis of the recorded adjusted 2008-2012 expenses and is consistent with 4

Commission forecasting guidance and should be adopted. 5

c) ORA’s Base Forecast For FERC Account 554 Non-Labor Expense Is Not 6

Sufficient to Fund Annually Recurring Maintenance Expenses 7

ORA proposes to reduce the non-labor Base forecast in FERC Account 554 by 8

$1.699 million. The Base forecast includes annually recurring maintenance, and does not include the 9

incremental maintenance costs incurred for overhauls (i.e., such as in 2009). SCE used the average 10

annual expense incurred during the years 2008, 2010, 2011 and 2012, whereas ORA used LRY (2012), 11

as summarized in Table VI-12 below. 12

Table VI-12 FERC Account 554 Non-Labor Expenses During Non-Overhaul Years

($000) ($2012) Year Expense Forecast Method

2008 8,841

2010 9,139

2011 8,772

2012 6,652 ORA – Last Recorded Year

Average 8,351 SCE – Four-Year Average

In testimony, SCE explained that “[i]n 2012 relatively few break down repairs 13

were incurred, and relatively less maintenance was performed as compared to prior years while awaiting 14

the extended outages for the planned 2013 Major Inspection.”104 ORA attempts to buttress its use of 15

LRY (and, by far, the lowest recorded year) for forecasting Base maintenance non-labor expense by 16

stating: “Although the current [downward] trend is likely to continue, utilizing LRY to forecast non-17

103 D.89-12-057, 34 CPUC 2d 199, 231, and D.04-07-022, pp. 15-16. 104 SCE-02, Vol. 8, p. 28.

54

labor provides SCE sufficient ratepayer funding in the event that more breakdowns occur in TY 2015 1

than in the base year 2012.”105 ORA provides no explanation on how maintenance and repair non-labor 2

expenses are expected to trend down as the plant continues to age. ORA fails to explain how its 3

forecast, which matches 2012 recorded expense, provides SCE sufficient funding for a greater level of 4

repairs than those experienced in 2012. ORA simply ignores the reason why 2012 costs were 5

significantly lower than prior years. SCE averaged the low year of 2012 together with the more 6

consistent years of 2008, 2010 and 2011 to produce a logical, reasonable Base forecast for non-labor in 7

FERC Account 554. The SCE forecast should be adopted. 8

7. SCE’s Rebuttal To ORA And TURN’s Adjustments To The CSA Annual Fees And 9

CSA Major Outage Fees 10

Table VI-13 below summarizes the CSA Annual Fees and CSA Major Outage Fees 11

forecasts in SCE’s Application, DRA’s and TURN’s testimony, and SCE’s rebuttal position. 12

Table VI-13 Total CSA Fees Forecast

($000) ($2012)

GE CSA FEES SCE Application

ORA TURNSCE

Rebuttal Position

ANNUAL FEESFixed FeeVariable FeePerformance Fee Sub-TotalMAJOR OUTAGE FEESHot Gas Path Adder (i.e., Overhaul Pre-Payment)Use Tax ReimbursementCash Adjustment Sub-TotalTOTAL 28,185 26,910 26,628 26,628

105 ORA-07, p. 31, lines 1-3.

55

As shown, both ORA and TURN proposed downward adjustments to all six CSA fees. 1

As explained below, SCE accepts TURN’s adjustments to the CSA Annual Fees and CSA Major Outage 2

Fees and rejects all of ORA’s adjustments. 3

a) SCE Agrees With Using 2013 Recorded And The TURN 2014-2017 Forecast 4

For The CSA Escalation Factors 5

As noted earlier, the computation for all six CSA fees includes an inflation factor, 6

referred to as the Total Escalation Factor, or TEF, which increases each year when the annual escalation 7

rate for that year is multiplied into it. SCE agrees with using the 2013 Recorded CSA Annual Escalation 8

Factor of 1.0200 as proposed by both ORA and TURN. In an effort to reduce the issue gap between 9

parties, SCE also accepts the TURN forecast for CSA annual escalation rates for 2014-2017, which is 10

based on its analysis of the indices used to compute these rates. The TURN forecast for CSA escalation 11

rates are less than both the SCE Application forecast, which is based on the 2008-2012 recorded 12

average, and the ORA forecast, which is based on 2009-2013 recorded average. 13

By accepting TURN’s forecast, SCE must correspondingly reject ORA’s forecast, 14

because a single forecast for CSA escalation must be selected before one can compute the CSA dollar 15

cost forecasts for the various CSA fees. 16

b) SCE Accepts The TURN Forecast For All CSA Fees 17

Except for using different CSA escalation factor forecasts, as discussed above, the 18

TURN and SCE Application methods for forecasting CSA Annual Fees and CSA Major Outage Fees are 19

identical. SCE ‘s acceptance of the TURN forecast for CSA escalation factor removes this difference. 20

As noted by TURN, adopting the TURN forecast for CSA escalation reduces the CSA Annual Fee 21

forecast by $0.941 million and reduces the CSA Major Outage Fee forecast by $0.616, for a total 22

reduction of $1.557 million in other expenses in FERC Account 554.106 SCE accepts these reductions. 23

These reductions are summarized in Table VI-13 above. 24

c) SCE’s Revised Forecast For The CSA Major Outage Fees Is Now Less Than 25

ORA’s Proposed Forecast 26

The only difference between the SCE Application forecast for CSA Major Outage 27

Fees and the ORA forecast for these fees is that ORA used a different CSA escalation factor forecast. 28

ORA uses the 2009-2013 recorded average, whereas the SCE Application uses the 2008-2012 recorded 29

106 TURN-05, Marcus, p. 17.

56

average. As explained above, SCE accepts the TURN forecast for the escalation factor, and as a 1

consequence, also accepts the TURN forecast for CSA Major Outage Fees. ORA’s forecast for CSA 2

Major Outage Fees was lower than the SCE Application forecast but higher than the TURN forecast. 3

Therefore, SCE’s revised forecast in this rebuttal testimony for the CSA Major Outage Fees is lower 4

than ORA’s proposed forecast and should be adopted. 5

The CSA Annual Fees cost component forecast is comprised of the CSA Fixed 6

Fee, Performance Fee, and Variable Fee. The only difference between the SCE Application forecast for 7

the Fixed Fee and Performance Fee, and the ORA forecast for these two fees, is that ORA used a 8

different CSA escalation factor forecast. For the reasons already explained above, SCE accepts the 9

TURN CSA escalation factor forecast, and as a consequence, thereby accepts the TURN forecast for the 10

Fixed Fee and Performance Fee. Therefore, SCE’s revised forecast in this rebuttal testimony for the 11

Fixed Fee and Performance Fee component of the CSA Annual Fees is lower than ORA’s proposed 12

forecast and should be adopted. 13

d) ORA Erroneously Throws Out 2008 and 2012 Data To Forecast The CSA 14

Variable Fee Portion Of The Annual Fee Based On Incorrect Assumptions 15

As summarized above in Table VI-13, the SCE rebuttal position forecast for five 16

of the six CSA fees (which matches the TURN forecast for CSA fees) is lower than the ORA forecast; 17

with the exception being the SCE and ORA respective forecasts for CSA Variable Fees. ORA uses a 18

different method than that used by SCE and TURN to forecast the Variable Fees. ORA uses only a 19

three-year average (i.e., 2009-2011) of recorded CSA data whereas SCE and TURN use a five-year 20

average (i.e., 2008-2012) of recorded data. ORA also uses Factored Fired Hours (FFH) recorded data to 21

compute the fee, whereas SCE and TURN use actual recorded cost data from the CSA invoices.107 ORA 22

thereby arrived at a lower forecast for this fee than both TURN and SCE. As shown in Table VI-14 23

below, the ORA forecast for this fee is $0.063 million less than SCE’s rebuttal position forecast as 24

presented in this exhibit.108 While this gap is small, SCE disagrees with ORA use of just 2009-2011 25

data, rather than all five years of data (i.e., 2008-2012) for forecasting future CSA Variable Fees. 26

107 The Annual Variable Fee is computed by multiplying the FFH fee rate by the amount of FFH for each of the

plant's four combustion turbines. Hence, as FFH increases, the FFH Variable Fee increases. 108 These figures incorporate the ORA revisions made in SCE-DRA-065-PM1 Q. 1.a-f (Appendix E).

57

Table VI-14 CSA Variable Fee Forecast Comparison

($000) ($2012)

Comparison of SCE, ORA and TURN Forecasts Forecast

Reduction to SCE

Application Forecast

SCE Application Forecast 0 ORA Forecast After Spreadsheet Error Correction 869 SCE Rebuttal Position Forecast (Matches TURN) 806

The ORA decision to not include 2008 and 2012 data is based on two erroneous 1

assertions: (1) that 2012 data can be rejected because recorded FFH during 2008 through 2013 shows a 2

strong downward trend, and (2) that 2008 data is not representative of future operations, because until 3

2009, plant costs were recovered via a Power Purchase Agreement. 109 ORA’s assertion regarding the 4

purported downward trend during 2008-2012 is incorrect. ORA has since agreed that it made errors and 5

has adjusted its forecast.110 Correction of these errors shows that FFH did not trend steadily downward 6

during 2008-2013, as illustrated in Figure VI-6 below. The overall trend is essentially flat. ORA chose 7

to throw out 2012 data based on a mistaken assumption that there was a clear downward trend in Factor 8

Fired Hours. This is not the case. 9

109 ORA-07, p. 35, Graph 7-6, and related narrative. 110 As documented in SCE-DRA-065-PM1; a copy is provided in Appendix E.

58

Figure VI-6 Mountainview Annual FFH

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

2008 2009 2010 2011 2012 2013

SCE further disagrees with ORA’s claim that the Commission’s cost recovery 1

process for Mountainview, before and after Mountainview was transferred to GRC Base Recovery as 2

part of the Commission’s decision in SCE’s 2009 GRC (D.09-03-025), had any appreciable effect on the 3

operating hours recorded by the plant’s combustion turbines. Turbine operating hours are the main 4

driver of FFH. Mountainview turbine operating hours are influenced by a variety of factors, such as 5

power market conditions and plant outages. ORA fails to explain why recorded FFH in 2012 (under 6

GRC Base Rate Recovery) approaches that recorded in 2008 (under PPA recovery). ORA provides no 7

support for its assertion regarding the purported operational impact of past cost recovery processes. 8

SCE’s and TURN’s forecasts assume that future FFH will be consistent with past 9

2008-2012 recorded FFH. By adopting TURN’s forecast for all six CSA fees, SCE has also 10

substantially narrowed the gap with ORA’s proposed forecast. For the reasons provided above, SCE 11

requests that the Commission adopt SCE’s revised forecast for CSA Annual Fees (including the 12

Variable Fee portion) and CSA Major Outage Fees. 13

8. SCE Accepts The TURN Forecast For The Non-CSA Overhaul Cost Component 14

In an effort to reduce the issue gap between parties, SCE accepts TURN forecast for Non-15

CSA 2012 Overhaul Adjustment, which reduces the labor forecast by $0.032 million in FERC Account 16

554. ORA did not propose any adjustments to this cost component. 17

59

B. MOUNTAINVIEW CAPITAL 1


SCE proposes a Capital expenditure forecast of $13.805 million for 2013-2017. This 3

forecast includes projects to facilitate continued compliance with safety and environmental objectives, 4

and several other projects to sustain station reliability. 5


ORA recommends a $0.369 million reduction to SCE 2013 Capital expenditure forecast 7

amount of $9.633 million.111 ORA seeks to reflect actual 2013 recorded, and makes no adjustments to 8

SCE 2014 and 2015 forecast expenditures of $1.327 million and $1.131 million, respectively. 9



$9.264 million. SCE further agrees with ORA that no adjustments be made to either the 2014 or 2015 12

forecast. 13

111 ORA had rounded the proposed reduction to $0.3 million (ORA-07, p. 35).

60

VII. 1

PEAKERS O&M AND CAPITAL 2

A. PEAKERS O&M 3


SCE forecasts 2015 Test Year O&M expenses of $10.450 million (2012$)112 to operate 5

the five (Barre, Center, Grapeland, Mira Loma and McGrath) Peaker Power Plants (Peakers).113 SCE’s 6

forecast for operations activities (FERC Account 549) used the last recorded year (LRY) forecast 7

method for both labor and non-labor. SCE’s forecast for maintenance activities (FERC Account 554) 8

used a four-year average forecast method for labor and LRY forecast method for non-labor.114 Given 9

that the McGrath Peaker was only in operation for a partial year in 2012, SCE’s 2015 TY forecast 10

included an upward adjustment of $1.206 million in order to annualize a full year of expenses for the 11

McGrath Peaker.115 12


ORA forecasts TY 2015 O&M expenses of $9.711 million ($2012), a proposed $0.739 14

downward adjustment to SCE’s forecasted amount. The ORA forecast is comprised of two parts: (1) 15

using last recorded year (LRY) as a base forecast method for labor and non-labor within Operations 16

Account 549 and Maintenance Account 554, and (2) an upward adjustment in the amount of $0.637 17

million for the addition of the McGrath Peaker, calculated from taking an average of the 2012 direct 18

expenses for the other four Peakers (Barre, Center, Grapeland and Mira Loma). 19


TURN forecasts TY 2015 O&M expenses of $9.786 million ($2012), a proposed $0.664 21

million downward adjustment to SCE’s forecasted amount. TURN’s forecast is comprised of three 22

parts: (1) a two-year average (2012-2013) as a base for both labor and non-labor of the Operations 23

Accounts 549 and Maintenance Account 554, and (2) an upward adjustment of $1.313 million for the 24

112 SCE-02, Vol. 9, p. 1. 113 The McGrath Peaker became operational in November 2012 and the other four Peakers entered service in

August 2007. 114 SCE-02, Vol. 9, p. 15. 115 SCE-02, Vol. 9, p. 10.

61

addition of the McGrath Peaker that utilizes 2013 recorded unadjusted expenses. TURN also moves the 1

$0.429 million116 forecast for added facility charges from non-labor to “Other” in FERC Account 549. 2


Table VII-15 below summarizes the forecasts and forecasting methods used in SCE’s 4

Application, and those proposed by ORA and TURN, summarized by FERC Account, divided into the 5

labor, non-labor and other categories. 6

116 Total sum of Added Fee charges for McGrath ($0.079 million) and other four Peakers ($0.350 million).

62

Table VII-15 TY 2015 O&M Position Comparison

($000) ($2012)

Labor Non�Labor Other Total Labor Non�Labor Other

SCE3,598 2,248 0 5,846 LRY LRY -

91 453 0 544 McGrath Adj. McGrath Adj. -Sub�Total 3,689 2,701 0 6,390

1,437 1,961 0 3,398 4-YR Avg. LRY -207 455 0 662 McGrath Adj. McGrath Adj. -

Sub�Total 1,644 2,416 0 4,060

5,333 5,117 10,450

ORA Lower�than�SCE: 7393,598 2,248 0 5,846 LRY LRY -236 154 0 390 McGrath Adj. McGrath Adj. -

Sub�Total 3,834 2,402 0 6,236

1,267 1,961 0 3,228 LRY LRY -118 129 0 247 McGrath Adj. McGrath Adj. -

Sub�Total 1,385 2,090 0 3,475

5,219 4,492 0 9,711

TURN Lower�than�SCE: 664549 3,417 2,146 0 5,563 2-YR Avg. 2-YR Avg. -

201 398 0 599 McGrath Adj. McGrath Adj. -0 (429) 429 0 Added Facilites Adj. Added Facilites Adj. Adj.

Sub�Total 3,618 2,115 429 6,162

554 1,137 1,772 0 2,909 2-YR Avg. 2-YR Avg. -209 506 0 715 McGrath Adj. McGrath Adj. -

Sub�Total 1,346 2,278 0 3,624 -

4,964 4,393 429 9,786

549

554

��TOTAL�ORA�FORECAST

��TOTAL�TURN�FORECAST

Operations

Maintenance

Operations

Maintenance

554

549

Acnt Forecast�Method

��TOTAL�SCE�FORECAST

2015�TY�Forecast�($000)�($2012)

Operations

Maintenance

63

Table VII-16 below summarizes the forecast reductions proposed by ORA and TURN, 1

summarized by FERC Account, divided into the labor, non-labor and other categories.117 As shown in 2

Table VII-16, SCE’s rebuttal position forecast is unchanged from SCE’s Application. For the reasons 3

explained below, SCE objects to ORA’s and TURN’s proposed reductions to the 2015 TY Peaker O&M 4

forecast. 5

Table VII-16 TY 2015 O&M Position Comparison by FERC Account

($000) ($2012)

5. SCE’s Rebuttal to ORA 6

a) SCE Combined FERC Accounts To Streamline Its Showing 7

ORA suggests that SCE manipulated its forecast when it combined certain FERC 8

accounts.118 This is incorrect. In many areas of the rate case, SCE combined FERC Accounts to address 9

recommendations by Commission staff and interveners in prior GRCs. By combining FERC accounts 10

consistent with those recommendations, SCE attempted to streamline its showing and make it more 11

manageable for the Commission and interveners to review. SCE addressed this in further detail in its 12

Policy Testimony.119 Iit is completely reasonable to consolidate the Peaker Maintenance FERC 13

Accounts (551-554) for forecasting future maintenance expenses given that the expenses included in 14

117 Table VII-16 reflects: (a) SCE's application forecast in SCE-02, Vol. 9 as well as Errata-SCE-02, Vol. 9; (b)

ORA's proposed adjustments in ORA-7; (c) TURN's proposed adjustments in TURN-05; and (d) SCE’s rebuttal position as presented in this exhibit.

118 ORA-07, p. 41. 119 SCE-01, p. 40.

�

SCE Application

ORA Adjustments

TURN Adjustments


FERC 549: Labor $ 3,689 $ 145 $ (71) $ 3,689 Peakers Non Labor $ 2,701 $ (299) $ (586) $ 2,272 Operations Other $ - $ - $ 429 $ 429 Total $ 6,390 $ (154) $ (228) $ 6,390 FERC 554: Labor $ 1,644 $ (259) $ (298) $ 1,644 Peakers Non Labor $ 2,416 $ (326) $ (138) $ 2,416 Operations Other $ - $ - $ - $ - Total $ 4,060 $ (585) $ (436) $ 4,060

GRAND TOTAL $ 10,450 $ (739) $ (664) $ 10,450

64

these FERC Accounts all relate to Peaker maintenance. Further, the detailed expenses for each 1

combined FERC Account were included in SCE’s workpapers, making the consolidation effort 2

transparent. SCE did not combine the FERC Account simply to manipulate a higher forecast. 3

Finally, it should be noted that SCE also combined its Peaker Operations FERC 4

Accounts 546-550, yet ORA took no exception with their consolidation.120 5

b) ORA’s Use Of LRY For Forecasting Labor Expenses in Maintenance 6

Account 554 Fails To Capture O&M Expenses That Will Be Incurred During 7

The Test Year 8

ORA recommends using LRY to forecast the base component labor expenses in 9

FERC Account 554. But, as explained below, this forecasting method would not capture certain costs 10

that appropriately should be included in the forecast. 11

SCE’s opening testimony explained that “[l]abor expenses were lower in 2012 12

due to construction and start-up activities at the McGrath site, which required some labor to record to 13

capital accounts.”121 These costs will instead record to O&M in TY 2015 now that construction of 14

McGrath is complete. Because these labor expenses were recorded to capital projects in 2012, the 2012 15

recorded O&M expenses are not representative of 2015 expenses, and cannot be utilized without 16

adjustment to develop the base component TY 2015 forecast for FERC Account 554. Doing so would 17

fail to capture labor costs that were appropriately recorded to capital in 2012 due to the construction of 18

the McGrath Peaker. ORA’s use of the LYR forecast method does not accurately reflect the expenses 19

for TY 2015 and should be rejected. SCE’s four-year average forecast method is appropriate, best 20

represents the base component expenses SCE expects to incur for the Peaker Plants, and should be 21

adopted. 22

c) ORA Underestimates The Increased O&M Expenses Related To The 23

McGrath Peaker In The Test Year 24

(1) SCE’s Forecasting Method For The McGrath Peaker Is Reasonable 25

Given That McGrath Operated For Only A Portion Of The Year 26

In SCE’s accounting system, each FERC account (e.g., FERC Account 27

549 Peaker Operations) contains several Final Cost Centers (FCCs), which provide additional 28

120 SCE-02, Vol. 9, p. 11, lines 13-14. 121 SCE-02, Vol. 9, p. 16, lines 6-7.

65

granularity regarding the various expenditures that are captured by a given FERC account. For example, 1

each of the five Peakers has a unique FCC for the operations costs incurred for that specific Peaker. 2

Likewise, each of the five Peakers has a unique FCC for the maintenance costs incurred for that specific 3

Peaker. This allows one to compare O&M costs of (for example) the Barre Peaker to those of the Center 4

Peaker. 5

There are also FCCs for costs that are common to all five Peakers (i.e., to 6

capture costs that are not specific to any single Peaker). For example, during most nights, weekends and 7

holidays, only one Peaker employee is on shift. That employee is the on-shift Peaker Control Operator 8

who works at the central Peaker control room that is located at the Peaker headquarters in 9

Westminster.122 For this reason, Control Operator labor costs normally charge to one of the “Peaker – 10

Common” FCCs rather than to one of the “Peaker - Specific” FCCs. These Peaker-Common expenses 11

are significant, accounting for approximately half of total annual Peaker O&M expense. 12

As noted above, the McGrath Peaker came on line in September 2012, and 13

therefore, did not incur a full year of O&M expenses during 2012. To incorporate a full-year of 14

McGrath O&M costs into the SCE 2015 TY forecast, SCE multiplied the 2012 McGrath O&M costs 15

(computed using the individual FCCs for McGrath) by a factor of three, and added that amount to the 16

base forecast. While Peaker-Common costs will also be impacted by the addition of McGrath to the 17

Peaker fleet, SCE’s forecast did not incorporate an additional specific amount for that expected cost 18

impact. Rather, SCE conservatively concluded that the “tripling” of the 2012 McGrath specific FCCs 19

would be sufficient to fund both the full year of O&M for the McGrath-specific FCCs, and the full-year 20

of added cost that McGrath will have on the Peaker-Common FCCs. 21

(2) ORA’s Forecasting Method For McGrath Is Flawed 22

Rather than analyzing 2012 costs that recorded to McGrath-specific FCCs, 23

ORA instead recommends using the average of the direct 2012 O&M expenses for the other four 24

Peakers (i.e., Barre, Center, Grapeland, and Mira Loma) to forecast the TY 2015 McGrath O&M 25

expenses. ORA notes that these four Peakers recorded a 2012 average O&M cost of $1.040 million (i.e., 26

122 While the Peaker primary central control room is currently located at the SCE Westminster facility for a

variety of reasons, none of the five Peakers are located in Westminster. While they can be operated locally, for economy the Peakers are normally remotely started, monitored and shut down from the Westminster control room. Traveling operator mechanics visit each of the five Peakers several times a week to conduct local inspections, etc. Further details are discussed in SCE-02, Vol. 9.

66

not counting O&M costs charged to the Peaker-Common FCCs). ORA’s method is flawed due to the 1

remote location of the McGrath Peaker, which is approximately 50 miles further (one-way) from the 2

Peaker Westminster headquarters than the next furthest Peaker (Mira Loma). Because of its remote 3

location, McGrath Peaker O&M expenses (travel and labor) are very likely to be higher than all other 4

Peakers. SCE’s method of using actual recorded expenses for McGrath accounts for these expected 5

higher expenses whereas ORA’s method does not. 6

Further, the ORA method fails to account for the additional “Peaker - 7

Common expenses that will incrementally increase with the addition of the McGrath Peaker. ORA 8

appears to believe that Peaker-Common costs are not impacted by adding McGrath to the fleet. This is 9

not true. Among many other examples, Peaker-Common costs include planning for repair outages, 10

ordering materials and repair parts, overall management of air permits and other common regulatory 11

compliance work such as compliance with NERC Electric Utility Reliability Standards, conducting site 12

safety inspections, and analyzing and tracking the condition of the Peaker fleet. All of this work 13

increased with the addition of a fifth Peaker (i.e., McGrath) to the fleet. 14

As SCE explained in Appendix F, (SCE response to DRA-067-PM1 15

Question 3), approximately half of Peaker Total Annual O&M expense is common (i.e. shared) for all 16

Peakers and is not allocated out to the individual plants. To accurately forecast Test Year 2015 O&M 17

expenses, the common (i.e. shared) expenses need to be included. Therefore, using the 2012 recorded 18

common expenses ($4.514 million) to produce an average common expense per power plant results in 19

an additional $1.129 million of expense per Peaker.123 This amount, when added to ORA’s calculated 20

direct expense per Peaker Plant ($1.0 million), results in a total forecast (including both direct and 21

common expenses) of $2.129 million, approximately $0.5 million higher than SCE’s Test Year 2015 22

forecast. Using ORA’s recommendation plus appropriately including the common expenses would 23

result in a forecast that exceeds SCE’s request. SCE’s forecast method, utilizing actual 2012 expenses, 24

provides the most accurate estimate of TY 2015 O&M expenses. The Commission should reject ORA’s 25

proposed adjustment, and adopt SCE’s forecast without changes. 26

123 Appendix F, SCE response to DRA-106-PM1 Q. 13 (Peaker 2012 recorded expenses).

67

6. SCE’s Rebuttal To TURN 1

a) TURN Errs In Attempting To Perform An Accelerated Analysis Using 2013 2

Recorded-Unadjusted Expense Data 3

TURN uses 2013 recorded-unadjusted O&M expense data to forecast future 4

Peaker costs. This data was provided to TURN in response to DRA-Verbal-057 Question 1.124 5

Specifically, TURN proposes using a two-year average (2012-2013) for FERC 6

Accounts 549 and 554, and 2013 recorded for the McGrath Adjustment. TURN’s use of unadjusted 7

2013 expenses is invalid, and can result in significant forecast errors. As SCE has previously explained, 8

it is not possible to predict the number of adjustments that will be needed nor is possible to predict the 9

magnitude or direction (i.e., increase or decrease) of these adjustments on any given FERC account.125 10

Moreover, using 2013 recorded-unadjusted expense data is not consistent with the Commission’s Rate 11

Case Plan.126 Therefore, TURN’s use of 2013 unadjusted data to forecast 2015 costs should be rejected. 12

Additional testimony regarding the use of 2013 recorded-unadjusted expense data is included in Chapter 13

III of this exhibit. 14

b) SCE Agrees With TURN’s Added Facility Charges Adjustment 15

SCE agrees with TURN’s recommendation that added facility costs in the amount 16

of $0.429 million be moved from non-labor to other expenses in FERC Account 549. 17

B. PEAKERS CAPITAL 18


SCE forecasts capital expenditures for its Peakers facilities of $1.074 million in 2013, 20

$2.954 million in 2014, and $3.043 million in 2015.127 The first several years of operating experience 21

with the Peakers indicated that further capital improvements would be beneficial for SCE customers. 22

These beneficial projects have largely been completed at the Barre, Center, Grapeland, and Mira Loma 23

sites. The McGrath Peaker site, completed in 2012, has yet to receive these improvement projects, and 24

therefore, the 2013-2017 forecast includes the costs for these improvements. In addition, the forecast 25

124 For example, see Appendix E. 125 SCE's objections to the TURN use of unadjusted 2013 recorded data to forecast 2015 TY expense are further

discussed in Chapters III, V and VI. 126 D.07-07-004, D.93-07-030 and D.89-01-040. 127 SCE-02, Vol. 9, p. 17.

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includes funding for a few additional improvements at all five Peakers, as well as funding for an 1

assumed overhaul of one of the Peaker turbines. 2


ORA proposes using 2013 recorded capital expenditures of $1.191 million (a slight 4

increase to the SCE forecast) and makes no recommendations for reductions to either SCE’s 2014 or 5

2015 capital expenditure forecast of $2.954 million and $3.043 million, respectively. 6

3. SBUA’s Position 7

SBUA recommends that “the Commission should reject SCE’s request to purchase spare 8

transformers unless SCE cannot pool shared transformers with other utilities.”128 SBUA also “disfavors 9

the use of Peakers since they are highly polluting and inefficient,” and believes that the “Peakers should 10

only be used when there is exceptionally high load on the system or other generators are unavailable . . . 11

[and] . . . [s]ince these Peakers should not be used unless there are exceptional circumstances, 12

purchasing backup transformers should not be necessary.”129 13


Table VII-17 below summarizes the forecast reductions proposed by ORA and SBUA as 15

compared to SCE’s Application forecast. TURN did not propose any reductions to SCE’s capital 16

forecast for Peakers. 17

128 SBUA-01, Brown, p. 17. 129 SBUA-01, Brown, p. 17.

69

Table VII-17 2013-2015 Capital Position Comparison

($000) ($Nominal)

2013 2014 2015 Total

SCE 1,074 2,954 3,043 7,071

ORA�Proposed�Reductions 1172013 Recorded 117 0 0 0

��TOTAL�ORA�REDUCTION 117 0 0 117

��TOTAL�ORA�FORECAST 1,191 2,954 3,043 7,188

SBUA�Proposed�Reductions 1,015Spare Transformers 0 0 (1,015) (1,015)

��TOTAL�SBUA�REDUCTION 0 0 (1,015) (1,015)

��TOTAL�SBUA�FORECAST 1,074 2,954 2,028 6,056

Higher�than�SCE:

Lower�than�SCE:



$1.191 million. This amount reflects a $0.117 million increase to SCE’s 2013 Peaker capital forecast. 3

SCE further agrees with ORA that no adjustments be made to either the 2014 or 2015 forecast. 4

6. SCE’s Rebuttal To SBUA 5

Each of the five Peakers has the following principle transformers (in addition to several 6

other, smaller transformers): 66kV/13.8kV Main Generator Step-up Transformer, 13.8kV/3.16kV 7

Auxiliary Transformer, and 13.8kV/480V Auxiliary Transformer (i.e., fifteen transformers total for the 8

five Peakers). The loss of any one of these transformers at a given Peaker site would render that Peaker 9

in operable until a replacement can be ordered, fabricated, delivered and installed. SCE forecast $1.015 10

million for the purchase of three spare transformers to be utilized in the event of a fault/failure of any of 11

these transformers at any one of the five Peaker plants. Given the long lead time (i.e., 6-24 months) to 12

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purchase a transformer, maintaining spare transformers will enhance reliability by drastically reducing 1

outage time should a transformer failure occur.130 2

SBUA fails to recognize that generation step-up transformers are: (1) heavy (most are in 3

excess of one ton) pieces of equipment that require specially designed foundations in order to support 4

their weight; (2) vary in size (i.e., length, width, and height); and (3) vary in capacity, or amount of 5

voltage (MVA). These factors make the type of transformers that can be used interchangeably at 6

multiple plants rare and difficult to find, as the transformers are inherently unique to a specific plant’s 7

design. SCE’s Peaker plants are of identical design, which allows the interchangeable use of the spare 8

transformers for which SCE is requesting recovery. 9

Further, SBUA incorrectly assumes that if SCE could share transformers with other 10

utilities that they would be available for SCE’s use at the precise time of need should a fault/failure 11

occur. SCE does not maintain the condition of “other” plants, and therefore, cannot guarantee that other 12

utilities experience the same fault/failure rate as SCE. A shared spare unit would not be available if it is 13

already in use at another utility, because of an earlier failure at another utility’s plant. The shared 14

approach would not be as effective in supporting SCE system reliability because there is an increased 15

risk of not having a spare transformer available when and if SCE should need it. 16

Finally, SBUA’s recommendation to “pool spare transformers” ignores the details and 17

logistics of such a recommendation such as: (1) which utility would be responsible for warehousing and 18

maintaining the transformers; (2) which utility would have priority in the event of multiple failures 19

within the time frame necessary to procure a new transformer; and (3) how would customers of all 20

utilities share the cost of a pooled asset. 21

SBUA also ignored SCE’s economic analysis, which evaluated the benefits of purchasing 22

spare transformers. The analysis demonstrated an economic benefit of 1.8.131 In addition, SCE’s base 23

case economic analysis actually understates the full economic value of purchasing spare transformers as 24

it does not include the economic value of the other grid support functions (black-start capability and 25

voltage support), that the Peaker Plants provide, which would be lost during a transformer outage 26

without an available spare. 27

130 SCE-02, Vol. 9, pp. 20-21. 131 SCE-02, Vol. 9, pp. 20-21, and Workpapers for Exhibit SCE-02, Vol. 9, pp. 111-112.

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SBUA asserts, “Peakers should only be used when there is exceptionally high load on the 1

system or other generators are unavailable.”132 SCE operates its Peaker fleet when necessary to 2

maintain system reliability. Given their fast-start-capability, the Peakers can fulfill off-line operating 3

reserve requirements. Unlike renewable energy sources such as wind and solar, Peakers are able to meet 4

additional generation needs caused by (1) sudden unanticipated loss of generating capacity elsewhere in 5

the system, (2) unexpected demand, or (3) the power output variability of renewable resources such as 6

wind and solar. SCE prudently operates its Peaker fleet in a manner that is consistent with their 7

intended usage, providing economic benefit and increased service reliability to SCE’s customers. The 8

purchase of spare transformers will enable Peakers to be available when they are needed for system 9

reliability. It would be unacceptable for a black-start Peaker Plant to be out of service for up to 24 10

months simply because SCE did not purchase a spare transformer. 11

SCE cannot and will not risk the reliability of our system. For the reasons explained 12

above, the Commission should reject SBUA’s recommendation13

132 SBUA-01, Brown, p. 17.

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VIII. 1

SOLAR PHOTOVOLTAIC PROGRAM 2

A. SCE’s Application 3

The SCE Solar Photovoltaic Program (SPVP) is a Commission-approved initiative for SCE to 4

install solar photovoltaic panels in its service territory, primarily on commercial rooftop space.133 SCE 5

forecast the Test Year 2015 SPVP operation and maintenance (O&M) expenses at $4.298 million 6

($2012) and 2013-2017 capital expenditures at $38.909 million (nominal dollars). SCE’s $4.298 million 7

O&M forecast consists of $2.214 million for the SPVP labor and non-labor expenses and $2.084 million 8

for SPVP roof top lease expenses. SCE’s forecast for O&M and capital expenditures are necessary to 9

operate and maintain in-service SPVP facilities in a safe and reliable manner while complying with 10

applicable laws and regulations, and to complete SPVP plant construction as authorized by the 11

Commission. 12

SCE also seeks reasonableness review of SPVP recorded O&M expense incurred during years 13

2008 through 2012, totaling $25.960 million (nominal). SCE also demonstrates that recorded capital 14

expenditures for SPVP plant construction are reasonable (i.e., from the inception of the program through 15

2013), as these expenditures do not exceed the $3.85W ($2008) capital expenditure threshold 16

established by the Commission in D.09-06-049, D.12-02-035 and D.13-05-033. 17

B. SPVP Program O&M Expenses 18


ORA recommends reducing the labor and non-labor expenses to $1.277 million for TY 20

2015 SPVP O&M activities and accepts SCE’s forecast for roof top lease expenses of $2.084 million, 21

for a total TY 2015 forecast of $3.361 million. This is a proposed $0.937 million or 22% downward 22

adjustment to the SCE forecast.134 23


TURN accepts SCE forecast for lease costs and proposes a $0.025 million reduction to 25

SCE’s “Added Facility Costs” forecast in Account 549. These costs are for SPVP’s use of the SCE 26

distribution system. TURN’s basis for this recommendation is a table SCE provided in response to a 27

133 D.09-06-049, p. 58, Ordering Paragraph 1. 134 ORA-7C, p. 46, lines 4-7.

73

TURN data request.135 The recommendation results in a new TY 2015 SPVP O&M forecast of $4.273 1

million ($2012). 2

TURN also recommends moving the “Added Facility Costs” from non-labor escalation to 3

“other” non-escalated costs. 4


Table VIII-18 below summarizes SCE, ORA and TURN forecasts, and includes the 6

SCE rebuttal position forecast, which incorporates the partial adjustment accepted by SCE.136 SCE’s 7

objections to the other proposed adjustments are discussed below. 8

Table VIII-18

TY 2015 O&M Position Comparison by FERC Account

($000) ($2012)

FERC 549 Labor $ 555 $ (235) $ - $ 555Misc and Other Non Labor $ 1,659 $ (702) $ (150) $ 1,509Power Generation ExpensesOther $ 0 $ - $ 125 $ 142

Total $ 2,214 $ (937) $ (25) $ 2,206FERC 550 Labor $ 0 $ - $ - $ 0Rents Non Labor $ 2,084 $ - $ - $ 2,084

Other $ 0 $ - $ - $ 0Total $ 2,084 $ - $ - $ 2,084

Grand Total $ 4,298 $ (937) $ (25) $ 4,290

SCE Application

ORA Adjustments

TURN Adjustments


4. SCE’s Rebuttal 9

ORA argues for a $0.937 million reduction (42%) to SCE’s $2.214 million forecast to 10

operate and maintain the facilities. ORA incorrectly characterizes SCE’s TY 2015 forecast as inflated, 11

contending that the SCE forecast contains prior construction costs that should not have been included. 12

ORA based its proposed reduction on its calculated dollar per watt figure derived from SCE’s contract 13

with US Most, who is a contractor SCE utilized to assist with plant O&M while the SPVP plants were 14

135 Appendix G, p. G-1 to G-2, SCE Response to TURN-SCE-077, Q. 01.a. 136 Table VIII-18 reflects: (a) SCE's application forecast in SCE-02, Vol. 10 as well as Errata-SCE-02, Vol. 10;

(b) ORA's proposed adjustments in ORA-07; (c) TURN's proposed adjustments in TURN-05; and (d) SCE’s rebuttal position as presented in this exhibit.

74

being constructed and placed into service. ORA’s recommendation is flawed because it is based solely 1

on the 2013 US Most recorded contract cost, and does not appropriately account for other necessary 2

O&M costs. As discussed in further detail below, SCE’s forecast is based upon SCE’s operational 3

experience with SPVP and analysis of SPVP total recorded costs (and not just with the US Most contract 4

recorded expenses). 5

a) SCE’s Forecast Is Based On SCE’s Operational Experience With The SPVP 6

Program And Recorded Costs 7

In response to DRA-Verbal-013, Question C.01, SCE stated that its “2015 8

forecast is based on 2012 recorded costs in part, but is substantially lower due to completion of the 9

construction phase of the Program in 2013. The forecast for 2015 reflects ongoing O&M for installed 10

equipment…” The response to this data request included an Excel spreadsheet itemizing the forecast.137 11

As shown in Figure III-3 of SCE’s direct testimony138, SCE’s $2.214 million 12

forecast for facility O&M is substantially less than 2012 recorded O&M expenses (i.e., a 54% reduction 13

not including the roof lease expense portion of SPVP 2012 total recorded expense). SCE took a detailed 14

approach to develop the forecast based on its 2008-2012 operational experience and recorded cost at 15

existing SPVP sites, as evidenced by SCE Workpaper 18b (also included as WP 35a),139 and other data 16

request responses.140 SCE appropriately adjusted these costs in its forecast. Recorded 2012 costs were 17

not a substantial basis of the forecast, as erroneously suggested by ORA. Indeed, SCE’s forecast is 18

substantially lower than 2012 recorded costs, now that construction is complete. As noted above, SCE’s 19

O&M forecast is for future anticipated necessary O&M expenses based on operational experience SCE 20

has gained in the SPVP and recorded costs from 2008-2012. This includes gathering significant 21

amounts of SPVP plant O&M data, analyzing and reporting on that data, and sharing lessons learned 22

from SCE SPVP plant operation with the Commission and other stakeholders, as SCE program 23

management personnel did during SPVP plant construction. 24

137 Spreadsheet also provided in response to DRA-Verbal-018, Q. A.01 (Appendix G, p. G-7); and in part to

DRA-Verbal-010, Q. C.01 and DRA-202-PM1, Q. 7 (See Appendix G, p. G-3 and G-23, respectively). 138 SCE-02, Vol. 10, p. 15. 139 Appendix G, pp. G-33 and G-34, Workpapers, SCE-02, Vol. 10, pp. 18b and 35a, respectively. 140 SCE responses to DRA-Verbal-018, Q. A.01 (Appendix G, p. G-7); DRA-Verbal-013, Q. C.01 (Appendix G,

p. G-5); and in part to DRA-Verbal-010, Q. C.01 and DRA-202-PM1, Q. 7 (See Appendix G, p. G-3 and G-23, respectively).

75

b) ORA’s Reliance On The US Most Contract To Develop A Forecast Is 1

Misplaced 2

SCE acknowledges that US Most initially performed a number of the SPVP O&M 3

activities. But in late-2013, these activities transitioned to SCE personnel. ORA uses the US Most 4

contract costs as a proxy to forecast for the costs SCE will incur to perform these same activities. 5

However, US Most did not perform all the necessary SPVP O&M activities discussed in SCE WP 6

18b.141 Therefore, ORA’s approach of using just the US Most contract results in an incomplete forecast. 7

ORA appears to assume that US Most was responsible for all aspects of SPVP O&M and that SCE did 8

nothing except to pay invoices. This assumption is incorrect. 9

While US Most was under contract, SCE personnel oversaw and analyzed

maintenance and operations tasks; provided operations support to coordinate outages with other entities;

cleared equipment for work (i.e., de-energizing equipment so that US Most personnel could safely

perform maintenance tasks) and conducted numerous other O&M activities. During this time, SCE

personnel included at least three FTEs (i.e., fulltime equivalent employees) in the following, or similar,

roles: Project Manager; Supervisor; Operator Mechanic; and Engineering Support. ORA’s flawed

forecasting approach excludes the costs for numerous other activities not included in the scope of the US

Most contract, such as those summarized in below142 143:

141 Workpapers, SCE-02, Vol. 10, p. 18b (See Appendix G, p. G-33). 142 Further detail is provided in Appendix G, p. G-35, ”Table 2 – Solar 2015 GRC O&M Forecast Detail.” 143 Table based on Workpapers, SCE-02, Vol. 10, pp. 18b and 35a (See Appendix G, pp. G-33 and G-34,

respectively).

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Table VIII-19 SCE Forecast O&M Expenses Not Covered in a Third Party O&M Contract

(All Costs Shown in $2012)

Line #

Description 2015 Forecast Expense

Forecast Assumptions Comment

1 Maintenance Labor 342,300 3 Employee FTEExpenses borne by SCE: 1-Project Manager; 1-Supervisor; 0.5-Operator Mechanic; and 0.5-Engineer

2Equipment/Spare Parts/Consumables 0-506,000 Spares, electrical parts, etc.

Estimate based on SCE's involvment with providing equipment, spare parts and consumables

3 Investigations and Repairs

0-164,000 Roof surveys & Inspection, engineering

Estimate based on SCE's involvment during investigations and repairs

4 Testing 0-265,000 Meter recert. Estimate based on SCE's involvment regarding meter testing

5 Monitoring and Reporting

75,000 Verizon telemetry system Expenses borne by SCE, not the contractor

6 Added Facility Costs 150,000 T&D Interconnection Expenses borne by SCE, not the contractor

7 Telecommunications 46,000 Telecom, ISP Expenses borne by SCE, not the contractor

8 Equipment Rentals 25,000 Manlifts, toilets, trailers Expenses borne by SCE, not the contractor

9 Transportation 60,000 SCE trucks, equipment Expenses borne by SCE, not the contractor

10 Training 5,000 Training for maintenance & operation

Expenses borne by SCE, not the contractor

11 Landscaping and Security Management

27,000 Ground systems, fencing Expenses borne by SCE, not the contractor

12 Other costs 150,000 Theft, vandalism, etc. Expenses borne by SCE, not the contractor

13Subtotal

(Rows 2-4, assuming 5% SCE Involvement)

46,750

14 Subtotal (Excluding Rows 2-4)

880,300

15 Total 927,050

As shown in the above table, the estimated expenses of $0.927 million associated 1

with SCE provided activities is essentially the same as the reduction of $0.936 million recommended by 2

ORA. Variables such as manning requirements and maintenance requirements can easily increase the 3

estimated total forecast requested by SCE. As noted above, SCE began performing activities previously 4

77

completed by US Most, as well as continuing to do work that US Most did not do. Accordingly, ORA’s 1

forecast based solely on the US Most contract is inadequate and should be rejected. 2

c) SCE Accepts TURN’s Recommendation For Moving The Added Facility 3

Costs To “Other” 4

SCE accepts TURN’s proposal to move the $0.150 million added facility costs, 5

discussed above, out of FERC Account 549 non-labor. 6

d) TURN’s Forecast Does Not Include All SPVP Facilities 7

TURN’s assertion that the added facility cost should be reduced to “$124,457” 144 8

is incorrect, as not all SPVP facilities were included in their calculation. SCE provided to TURN in a 9

data request response the recorded 2012 “Added Facility Costs” paid to T&D.145 The recorded facilities 10

costs for SPVP027 and SPVP048 were not realized in 2012 and therefore were not included with the 11

data request response. SPVP027 was first synchronized to the grid in late November 2012, and 12

SPVP048 was first synchronized to the grid in August 2013. Table VIII-20146 below summarizes the 13

facility costs for all current UOG SPVP sites (costs for the additional sites were added to the original 14

table provided with the TURN-SCE-077, Q 01.a, response): 15

144 TURN incorrectly included Fuel Cell special facility charges to their total. TURN corrected their value to

$122,547 in their response to SCE data request SCE-TURN-002, Q. 1 (See Appendix G, pp. G-36 to G-38). 145 SCE provided this information in its response to data request TURN-SCE-077, Q. 01.a. (See Appendix G, p.

G-1). 146 Supporting data is provided in Appendix G, pp. G-39 to G-41, ”Intra-company transfers for the Solar

Photovoltaic Program. . . .”

78

Table VIII-20 Intra-Company Transfers From the Solar Photovoltaic Program (SPVP) for Ongoing

Maintenance Expenses (Based on 2012 Rate of 0.38%)

Line # Project Basis RateMonthly Amount

Yearly Assessment

1 SPVP002 - Chino 74,645.49 0.38% 283.65 3,4042 SPVP003 - Rialto 207,591.61 0.38% 788.85 9,4663 SPVP005 - Redlands 37,482.10 0.38% 142.43 1,7094 SPVP006 - Ontario 49,120.04 0.38% 186.66 2,2405 SPVP007 - Redlands 39,823.26 0.38% 151.33 1,8166 SPVP008 - Ontario 18,643.11 0.38% 70.84 8507 SPVP009 - Chino 115,638.61 0.38% 439.43 5,2738 SPVP010 - Fontana 75,000.00 0.38% 285.00 3,4209 SPVP011 - Redlands 121,000.00 0.38% 459.80 5,51810 SPVP012 - Ontario 57,136.15 0.38% 217.12 2,60511 SPVP013 - Redlands 65,000.00 0.38% 247.00 2,96412 SPVP015 - Fontana 138,000.00 0.38% 524.40 6,29313 SPVP016 - Redlands 516,000.00 0.38% 1,960.80 23,53014 SPVP017 - Fontana 119,000.00 0.38% 452.20 5,42615 SPVP018 - Fontana 83,265.57 0.38% 316.41 3,79716 SPVP022 - Redlands 33,866.37 0.38% 128.69 1,54417 SPVP023 - Fontana 126,770.00 0.38% 481.73 5,78118 SPVP026 - Rialto 85,000.00 0.38% 323.00 3,87619 SPVP027 - Rialto 50,370.00 0.38% 191.41 2,29720 SPVP028 - San Bernardino 112,000.00 0.38% 425.60 5,10721 SPVP032 - Ontario 122,000.00 0.38% 463.60 5,56322 SPVP033 - Ontario 147,000.00 0.38% 558.60 6,70323 SPVP042 - Porterville 159,000.00 0.38% 604.20 7,25024 SPVP044 - Perris 184,445.00 0.38% 700.89 8,41125 SPVP048 - Redlands 367,200.00 0.38% 1,395.36 16,74426 Total 141,588

As shown in Table VIII-20 above, the estimated added facility cost for all 1

twenty-five SPVP sites is $0.142 million. Accordingly, SCE partially accepts TURN’s recommended 2

reduction by adjusting SPVP added facility costs from $0.150 million to $0.142 million — resulting in 3

2015 TY forecast reduction of $0.008 million, from $4.298 million to $4.290 million. 4

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C. SPVP Capital Expenditures 1


SCE forecast capital expenditures for 2013, 2014 and 2015 of $31.500 million, $0.425 3

million and $1.035 million, respectively.147 ORA recommends a $4.900 million reduction to the 2013 4

forecast and does not dispute SCE forecast capital expenditures for 2014 and 2015. ORA based its 5

recommendation for 2013 on actual recorded 2013 capital expenditures, observing that: “[c]apital 6

expenditures in 2013 reflect the capital required to complete the construction of the SPVP final solar 7

site, Redlands distribution center (RDC) 10.”148 8

2. SCE Rebuttal 9

SCE partially accepts ORA’s recommendation to reduce forecast 2013 capital 10

expenditures. Specifically, SCE agrees to reduce forecast SPVP 2013 capital expenditures to the final 11

adjusted amount recorded in 2013, which is $25.536 million. This is a $5.964 million reduction to the 12

SCE 2013 forecast. 13

D. SPVP Reasonableness Review 14


SCE requests recovery of all reasonable and prudent capital expenditures and O&M 16

expenses for the construction and maintenance of the SPVP from 2008 through 2014. ORA finds that 17

the 2008-2013 capital expenditures are reasonable and all 2008-2012 O&M expenses are reasonable 18

with the exception of the $10.100 million termination fee SCE paid when it elected to cancel a solar 19

module supply contract with SunPower. 20

2. SCE Rebuttal 21

a) SCE’s Decision to Terminate the SunPower Contract Was Prudent 22

SCE disagrees with ORA’s recommendation to disallow the $10.100 million 23

termination fee SCE paid pursuant to the SunPower contract. This fee recorded to SPVP O&M expense 24

account FERC 549 in conformance with accounting protocols.149 In the first quarter of 2010, SCE 25

entered into two solar panel supply contracts (i.e., Master Supply Agreements or MSA) – one with 26

147 SCE-02, Vol. 10, p. 7, Figure II-1. 148 ORA-7C, p. 48, lines 9-11. Workpapers, SCE-02, Vol. 10, p. 90, “7 (b). Detailed Description.” (See

Appendix G, p. G-42 for a copy of Workpaper, p. 90). 149 SCE discussed the basis for recording the fee to O&M expense in its response to DRA-309-PM1, Q. 01.b

(See Appendix G, p. G-32).

80

SunPower Corporation (SunPower) and the second with Trina Solar (US) Inc. (Trina). SCE entered into 1

these MSAs to ensure a competitive price for these modules and ensure timely delivery for the SCE 2

SPVP program installation schedule. 3

The MSA with SunPower covered deliveries of up to an equivalent of 200 MW 4

(DC) of modules. As explained in the MSA, the dollar per watt pricing for all deliveries was to be fixed 5

assuming that a certain volume of panels were ultimately ordered and delivered.150 The MSA included 6

provisions for an additional fee (i.e., a termination fee) to be paid by SCE if it purchased lower volumes 7

(i.e. the lower the purchase volume, the higher the termination fee). The MSA thereby afforded SCE a 8

volume discount, subject to adjustment (via the termination fee) depending on actual purchases. When 9

the market price for panels continued to decrease, SCE eventually stopped orders from SunPower such 10

that a $10.100 million termination fee was triggered under the SunPower MSA. 11

SCE initially chose SunPower as the primary supplier for the SPVP module 12

deliveries in order to maximize the amount of energy production per square foot of roof space. SCE 13

selection of SunPower as a key supplier was reasonable, as SunPower modules are some of the most 14

efficient modules on the market and were therefore at that time the best value for the money based on 15

module costs, installation costs and roof lease costs. Less efficient modules, for example, require a 16

larger area to produce the same rated capacity as more efficient modules. The increased roof area 17

required to reach the SPVP rated capacity goal would have resulted in additional roof leases and 18

additional cost to the customer. 19

However, the Trina MSA, which was also a volume-based contract, was 20

subsequently revised to substantially reduce its dollar per watt pricing, such that Trina panels became 21

more economic than the SunPower panels. SCE negotiated these price reductions when the market price 22

for panels continued to decrease. ORA asserts that SCE should have anticipated continued market price 23

decreases and not have entered into the SunPower MSA. 24

ORA relies on 20/20 perfect hindsight analysis in 2014 to pass judgment 25

regarding the actions SCE should have taken four years earlier without the benefit of that perfect 26

hindsight knowledge.151 ORA refers to a figure in its testimony (Figure VIII-7) that shows a 27

twenty-five year trend of declining prices. ORA reasons that SCE should have assumed that the price of 28

150 The MSA with Trina had similar volume discount provisions. 151 ORA-7C, p. 53, line 5.

81

solar panels would never increase, and that SCE should never have entered into a fixed-price, volume 1

contract. But this reasoning does not appropriately recognize observable market dynamics, which create 2

price increases that could result in harm to customers. SCE could not predict future panel prices and had 3

no reason to believe that prices would continue to decrease, without risk of potential increases during the 4

period SCE planned to purchase panels. The figure relied by ORA also shows numerous price increases, 5

as well as valleys where module $/W pricing was at its lowest prior to a sharp rise in price. There are 6

two valleys observable on the figure cited by ORA, for example, where prices had flattened before a 7

sudden shift to rapidly rising prices. These instances were in 1987 and 2003. SCE’s decision to enter 8

into the volume contracts with SunPower and Trina was to obtain lower prices by purchasing in bulk 9

and to protect customers from the potential unexpected steep rise in module prices that occurs from time 10

to time in the market, as evidenced by ORA’s figure. 11

82

Figure VIII-7 SPV Panel Pricing Trends

(Provided by ORA)152

Later in 2010, module prices continued to drop when the market was flooded with 1

less expensive, less efficient, modules from China. Following this unforeseen event, it became evident 2

that competition from China would force a further downward trend in prices, well below the SCE 3

contracted price with SunPower. SCE negotiated with both SunPower and Trina for lower rates on their 4

modules. SunPower would not lower their rates. At this point, SCE determined that it would be more 5

beneficial to pay a contract termination fee agreed to between SunPower and SCE rather than continue 6

the contract.153 SCE maintained its contract with Trina, who agreed to lower rates. 7

152 ORA-7C, p. 53, Graph 7-10. 153 In addition, ORA is wrong in claiming that SCE either committed a “breach of contract” or acted to “break a

contract” when SCE exercised terms of the Agreement to terminate further purchase of PV modules from SunPower. See DRA-291, Q. 02.b (Appendix G, p. G-25); and ORA-7C, p. 50, line 16. SCE did not breach or break its contract as ORA suggests. Termination clauses are specifically included in large contracts or agreements to permit either Party to terminate the Agreement.

83

It should also be noted that by ORA’s reasoning, SCE should also have not 1

entered into the Trina fixed-price, volume contract either. This reasoning is flawed. Doing so would not 2

have provided the volume discounts afforded by the Trina contract. 3

The termination agreement with SunPower required that SCE pay the amount of 4

$11,100,000, if the termination occurs after Delivery of Supply in the aggregate greater than 50 MW, 5

but less than 150 MW.”154 The decision to terminate the SunPower agreement was purely economic as 6

continued purchase of modules could have cost the customer hundreds of millions of dollars versus 7

purchase of modules from other suppliers, once prices dipped below $2 per Watt (DC). Below, are two 8

tables155 comparing savings to the customer resulting from the termination of the SunPower Agreement. 9

Table VIII-21 provides the saving that would have been realized based on the 2011 program size of 10

250 MW (which was the size of the program when SCE terminated the SunPower MSA). 11

Table VIII-21 Contract Termination Savings Based on 2011 Program Size of 250 MW

Line�#� Supplier�

Remaining�Capacity�on�SunPower�

MSA�

Total�Estimated�Cost�per�

Agreement�(Nominal�$)�

1� SunPower�2� Alternate�Supplier�

3� Termination�Savings 203,668,190�

154 “Master Supply Agreement for The Purchase of Photovoltaic Modules by and between Southern California

Edison and SunPower Corporation,” March 1, 2010, pp. 19-20 of 110, Article 11.0, “Termination.” Copies of the MSA, amendments and Notice of Termination, were provided in response to DRA-291-PM1, Q. 4. Only the relevant pages are provided in the Appendix G, pp. G-26 to G-31.

155 Calculation spreadsheet is provided in Appendix G (Tables 4 & 5 CONFIDENTIAL-Sun Power Termination Cost Comparison), beginning on p. G-43, along with copies of Agreement Amendments containing module rates.

84

In May 2013, the CPUC approved the reduction of the SCE SPV program to 1

91MW (DC).156 Based on contracted module pricing and the final SPV program size of 91.4MW (DC), 2

Table VIII-22 provides the realized gross savings to the customer of $12.6 million. 3

Table VIII-22 Realized Savings Based on Final Program Size of 91.4 MW

Line�#� Supplier�

Remaining�Capacity�Following�Contract�

Termination�(MW)�

Total�Estimated�Cost�per�

Agreement�(Nominal�$)�

1� SunPower�2� Alternate�Supplier�

3� Termination�Savings 12,549,900�

SCE prudently entered into the SunPower and Trina agreements to obtain volume 4

discounts by purchasing in bulk and to guard against potential price increases. SCE prudently exercised 5

its option to terminate the SunPower agreement when module prices dropped due to increased 6

competition from China. SCE’s actions were reasonable based on the expected overall savings. Even in 7

hindsight (based on the size of the program now known) by terminating the agreement, SCE realized a 8

gross savings of $12.6 million. In the process, SCE negotiated the termination fee down from $11.1 9

million to $10.1 million, saving the customer an additional $1 million dollars. 10

For these reasons, the Commission should approve full recovery of all SPVP 2008 11

to 2012 recorded O&M expenses, totaling $25.960 million (nominal), as reasonable. 12

156 D.13-05-033, p. 19.

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IX. 1

FUEL CELL PROGRAM 2

A. SCE’s Application 3

SCE forecasted $0.669 million for the Test Year 2015 O&M expense for the Fuel Cell Project. 4

This funding consists of both forecast labor and non-labor expenses at both installations. The labor 5

expense of $0.113 million is for the funding of Full Time Equivalent (FTE) who will provide program 6

oversight and project management to support the ongoing safe, compliant, and reliable operation of the 7

fuel cells. The forecast non-labor expenses of $0.556 million include the Long-Term Service 8

Agreements (LTSA) with the fuel cell manufacturers along with telecommunication and data services, 9

interconnection charges, water treatment system service agreement, site maintenance service 10

agreements, and air quality permit charges.157 In addition, SCE forecast capital expenditures of $0.711 11

million in 2013. 12

B. ORA’s And TURN’s Positions 13

ORA recommends reducing SCE’s request for O&M expenses for the Fuel Cell program from 14

$0.669 million to $0.544 million; a difference of $0.143 million.158 The ORA proposed adjustments are 15

comprised of a $0.086 million reduction in the non-labor expense associated with the LTSA for the 16

installation at California State University, San Bernardino (CSUSB) and a $0.057 million reduction in 17

labor expense associated with the forecast of one FTE for the Fuel Cell Program. TURN recommends 18

reducing SCE’s labor expense by $0.037 million.159 Table IX-23 below summarizes SCE, ORA and 19

TURN O&M forecasts.160 20

157 SCE-10, Vol. 1, pp. 30-61. 158 ORA-07C, pp. 55-56 159 TURN-05, Marcus, p. 23. 160 Table IX-23 reflects: (a) SCE's application forecast in SCE-02, Vol. 10 as well as Errata-SCE-02-A, Vol. 10;

(b) ORA's proposed adjustments in ORA-07; (c) TURN's proposed adjustments in TURN-05; Marcus; and (d) SCE’s rebuttal position as presented in this exhibit.

86

Table IX-23 TY 2015 O&M Position Comparison

($000) ($2012)

C. SCE’s Rebuttal 1

SCE calculated the $0.669 million O&M expense for the Fuel Cell Program by utilizing the 2

itemized forecast method which, as explained above, includes all of the anticipated O&M expenses for 3

the Fuel Cell Program. 4

1. CSUSB Fuel Cell LTSA O&M Expense 5

ORA does not disagree that the LTSA for the fuel cell at CSUSB is a reasonable O&M 6

expense. Instead, ORA asserts that SCE’s forecast for that expense is above what the LTSA stipulates. 7

ORA is wrong, and fails to include an additional amount that will be required, as explained below. 8

SCE’s forecast for the fuel cell LTSA for CSUSB was calculated according to 9

10

11

12

13

14

15

16

161 SCE response to ORA data request DRA-036-PM1, Q.3, Attachment 1 of 8, p. 13, (CONFIDENTIAL). See

Appendix H, pp. 1- 5. 162 Id. 163 ORA-07C, p. 57.

87

1

2 3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

2. Fuel Cell Program Labor Expense 18

Both ORA and TURN argue for a reduction in SCE’s labor expense forecast, asserting 19

that SCE does not need a full-time program/contract manager for the SCE Fuel Cell Program. As ORA 20

and TURN apparently see it, SCE’s responsibilities as owner are not sufficient to require one FTE. Both 21

parties are incorrect, as it is very reasonable for SCE to have one FTE to manage a program of this 22

scope. The Commission agreed with SCE in D. 10-04-028, that one FTE is necessary for the safe and 23

reliable operation of the fuel cell installations and the overall management of the Fuel Cell Program. 24

Contrary to ORA’s characterization that the work necessary to oversee the Fuel Cell Program is simple 25

and does not warrant an FTE, the work required is complex, and consists much beyond simply 26

scheduling fuel cell vendors to perform the requirements of their respective LTSAs. Rather, the 27

oversight of the Fuel Cell Program involves the operation and maintenance of two geographically distant 28

164 ORA-07C, p. 57. 165 SCE response to data request DRA-217-PM, Q.1, Attachment, (CONFIDENTIAL). See Appendix H, p. 6-7.

88

distributed energy resource assets. In addition to the expected responsibilities concerning operating and 1

maintaining the equipment associated with project linears, such as water, gas, sewage, air quality 2

permitting, and electrical interconnections, both of the installations are located at California state owned 3

universities that expect SCE to be responsible tenants. As neither host university requested financial 4

consideration for SCE’s use of their land for either of these projects, it is incumbent upon SCE to 5

provide the host universities with the comfort that the respective fuel cell systems, including the 6

aforementioned linears, are being operated and maintained in an adequate manner consistent with SCE’s 7

obligation to maintain other system assets in a safe and reliable condition. These responsibilities will 8

include regular contact with university staff, direct sharing of operational data and ensuring the quality 9

of the data, specific focus on the upkeep of the visual appearance of the installations, and any other 10

emergent issues that may be brought to our attention. For these reasons, SCE stands by its original 11

forecast of one FTE for the oversight of the Fuel Cell Program, and the Commission should reject ORA 12

and TURN’s recommendations to reduce funding for this position. 13

89

X. 1

CATALINA 2

A. SCE’S Application 3

SCE forecast O&M expenses of $4.594 million in 2015 for all costs related to Catalina’s 4

generation assets. FERC Account 549.140 includes the expenses related to operating, maintaining, and 5

repairing SCE’s Catalina Generation assets, the auxiliary apparatus and systems, and various 6

miscellaneous expenses. Because expenses in this account significantly fluctuate from year to year, 7

SCE based its forecast on a five-year average of recorded O&M expenses. 8

SCE forecast capital expenditures for the PBGS Generation Automation (Automation) project, 9

which was approved in SCE’s 2012 GRC, but was slightly delayed. In addition, SCE included capital 10

expenditures for various projects under $1million. Together, these projects were forecast to be $2.480 11

million for 2013, $5.465 million for 2014, and $0.420 million for 2015. 12

B. ORA And TURN’s Recommendations On O&M Expense 13

ORA recommends Test Year 2015 O&M expenses of $4.194 million, which is based on using 14

2012 last recorded year (LRY) for both labor and non-labor.166 ORA’s proposal results in a $0.4 million 15

decrease to SCE’s forecast. TURN recommends Test Year 2015 O&M expenses of $4.360 million, 16

making adjustments to SCE’s forecast to remove certain costs that are known to be non-recurring going 17

forward.167 SCE stipulates to TURN’s O&M forecast. Table X-24 below summarizes SCE, ORA and 18

TURN O&M forecasts.168 19

166 ORA-07, p. 62. 167 TURN-05, Marcus, p. 24. 168 Table X-24 reflects: (a) SCE's application forecast in SCE-02, Vol. 10 as well as Errata-SCE-02-A, Vol. 10;

(b) ORA's proposed adjustments in ORA-07; (c) TURN's proposed adjustments in TURN-05, Marcus; and (d) SCE’s rebuttal position as presented in this exhibit.

90

Table X-24

TY 2015 O&M Position Comparison

($000) ($2012)

SCE

Application ORA

Adjustments TURN

Adjustments SCE Rebuttal

Position

FERC 549.140 Labor $ 1,915 $ 315 $ 17 $ 1,932 Non Labor $ 2,679 $ (715) $ (251) $ 2,428 Other $ - $ - $ - $ - Total $ 4,594 $ (400) $ (234) $ 4,360

C. SCE’s Rebuttal On ORA’s Proposed Reductions To O&M Expense 1

ORA’s proposal to use recorded 2012 O&M expenses as the basis for its 2015 forecast is not 2

persuasive and should be rejected. In D.89-12-057, the CPUC stated that for those sub-accounts that 3

have significant fluctuations in recorded year expenses from year to year, an average of recorded 4

expenses is appropriate. SCE’s use of a five-year average for Account 549.140 is appropriate because, 5

as SCE described in opening testimony, expenses in this account fluctuate significantly from year to 6

year based on the extent of maintenance and repair work required for the generation assets and related 7

equipment.169 Catalina presents unique circumstances not existing elsewhere in SCE service territory as 8

all three SCE utilities on the island – gas, water, and electricity – share staff and expenses. As a result, 9

electric O&M costs may be down in one year, while costs recorded to gas and water O&M may 10

increase. 11

ORA asserts that 2012 recorded expenses should be the basis for the Catalina forecast due to 12

SCE’s underspending of authorized O&M expenses in 2012. SCE described in its opening testimony the 13

factors that led to underspending of its 2012 authorized O&M, which discussed the variability of 14

Catalina operations rather than a result of a trend of decreasing O&M costs. ORA also cites six-year old 15

testimony from SCE’s 2009 GRC, which states that the Automation project will improve a labor-16

intensive process for providing power on the island. ORA incorrectly assumes that there are cost-17

savings that should be removed from SCE’s forecast. SCE has not identified any quantifiable O&M 18

169 SCE-02, Vol. 10, p. 34.

91

cost benefits/avoidances related to implementation of the automation project, although it improves the 1

prior processes and arguably has kept costs from increasing. 2

D. ORA And TURN’s Recommendations On Capital Expenditures 3

ORA recommends using SCE’s 2013 recorded capital expenditures of $1.0 million, which is a 4

reduction to SCE’s 2013 forecast of $1.5 million. ORA does not dispute SCE’s 2014 and 2015 forecast 5

for Catalina capital expenditures.170 TURN has a primary and alternative recommendation for its 6

forecast for the Automation project’s capital expenditures. TURN’s primary recommendation allows 7

SCE to recover only the $5.076 million in expenditures expended through 2013, with no accrual of 8

Allowance for Funds Used During Construction (AFUDC) or capitalized property taxes from 2012 to 9

September 2014. TURN’s alternative recommendation is to allow SCE to recover $8.841 million in 10

capital expenditures, which removes $1.095 million in costs. In addition, TURN recommends removing 11

AFUDC and capitalized property taxes of $1.226 million for the time of project suspension. 12

E. SCE’s Rebuttal To TURN 13

SCE disagrees with TURN’s primary recommendation, as SCE is restarting the project and 14

requires the funding forecast for 2013 and 2014 to complete it. SCE supports TURN’s alternative 15

recommendation, which adjusts for SCE’s recorded 2013 expenditures and spreads the remaining 16

forecast over 2014 and 2015, with the exception of TURN’s proposed removal of AFUDC and 17

capitalized property taxes. As discussed below, SCE followed correct accounting for AFUDC and 18

property taxes. 19

1. SCE Provided Valid Explanations For Project Delays 20

As discussed in direct testimony and in a data request response to TURN, SCE has valid 21

explanations for the delay in completing the Automation project. “SCE suspended work on the 22

Automation project in mid-2012 as a result of concerns with availability of funding due to the late 2012 23

GRC decision and as a result of the increased costs being incurred with the redesign of the project and 24

the coordination and implementation with the SCAQMD settlement and associated facilities.”171 The 25

project was later delayed in 2013 due to the sequencing of other projects. SCE could not restart work on 26

the Automation project until the building betterment projects were completed on Catalina Island, as the 27

automation equipment would be housed in the building. Lastly, the project was further delayed as 28

170 ORA-07, p. 63. 171 TURN-SCE-098, Q. 5.a. See Appendix I, p.1.

92

emergent projects for Catalina’s gas and water utilities took precedence, and project managers with the 1

specific skills to manage the Automation project were assigned to more urgent gas and water projects. 2

In August 2014, SCE assigned a dedicated project manager to begin work on completing the 3

Automation project, with an estimated completion date in 2015. 4

2. SCE Followed Correct Accounting For AFUDC And Property Tax 5

TURN recommends, due to the project’s suspension, that SCE should write-off AFUDC 6

and property taxes capitalized to the Automation project from July 2012 through the end of the 7

constructions suspension.172 TURN incorrectly asserts that the accrual of AFUDC violates accounting 8

principles and SCE’s internal accounting policies. Neither contention is accurate. TURN (1) incorrectly 9

applies accounting standards that SCE has complied with; (2) provides external references that are not 10

applicable to SCE in this situation; and (3) mischaracterizes SCE’s accounting practices. 11

3. SCE’s Accounting For AFUDC Is Compliant And Appropriate 12

TURN’s conclusion that AFUDC should not be accrued on project suspension based on 13

accounting principles is incorrect. TURN refers to a quote from an inapplicable real estate accounting 14

guide that cites Financial Accounting Standards (FAS) 34 and FERC order regarding a gas pipeline.173 15

TURN admits that language for electric utilities is less clear, but mentions that FERC address 16

abandonment, which does not apply to this situation.174 Finally, TURN cites a Mississippi Commission 17

practice that addresses circumstances not present in this GRC.175 18

The Commission’s ratemaking policy is not dictated by financial accounting standards. 19

The outstanding investment in Construction Work in Progress (CWIP) for this project still requires 20

construction financing, which is a cost. It is fair and appropriate to permit SCE to record AFUDC to 21

capture the cost of financing capital projects. When authorizing a revenue requirement for energy 22

utilities such as SCE, this Commission follows cost-of-service principles that permit the utility to 23

recover all of its reasonable costs.176 24

172 TURN-05, Marcus, p 31. 173 TURN-05, Marcus, p.29. 174 Id. 175 Id. 176 See D. 03-02-035, p. 6.

93

TURN’s citation to FAS No. 34177 ignores Accounting Standards Codification (ASC) 1

980, which governs regulatory operations under Generally Accepted Accounting Principles (GAAP). In 2

the case where the regulatory agency (as with the CPUC) requires utilities to capitalize the cost of 3

construction financing, “the amounts capitalized for rate-making purposes as part of the cost of 4

acquiring the assets shall be capitalized for financial reporting purposes instead of the amount of interest 5

that would be capitalized in accordance with 835-20.”178 6

The FERC order cited by TURN provides: “if a natural gas pipeline suspend substantially 7

all activities related to the construction of pipeline facilities, AFUDC accruals must cease unless the 8

company can justify the interruption as being reasonable under the circumstances.”179 As discussed in 9

direct testimony,180 in response to TURN’s DR 98-05a, and in prior sections of this rebuttal, the reasons 10

for the suspension are reasonable. 11

Finally, TURN claims that some state commissions forbid AFUDC accrual during 12

periods of construction suspension. The Mississippi Rule of Practice and Procedure referenced by 13

TURN is predicated on a utility’s failure to adhere to the rules or an order of the Commission and only 14

applies in limited situations, as follows: 15

The Commission may, by incorporating a provision in its order granting a Facilities 16 Certificate, suspend Commission authority for the construction or acquisition of a 17 facility, plant or other capital item, whether previously certificated or not, upon 18 failure by a utility to adhere to the provisions of this rule or an order of the 19 Commission, or for its failure to timely provide the Commission, Commission staff or 20 the Staff with any reasonable information requested concerning the cost, purpose or 21 construction of the facility, plant or other capital item. Except as specifically allowed 22 by order of the Commission, the related capital expenditures made during the period 23 of suspension on the suspended construction or acquisition shall not be allowed in 24 rate base during the period of such suspension nor shall Allowance for Funds Used 25 During Construction (AFUDC) accrue on any such funds during any period of 26 suspension.181 27

177 ASC 835-20 supersedes FAS 34. 178 ASC 980-835-30-1; ASC 835-20 referenced in the quote refers to GAAP for the recognition of capitalized

interest and supersedes FAS 34. 179 No. CP09-36-002 et al., 130 FERC ¶ 61,193, 61854, at ¶ 38. 180 SCE-02, Vol. 10, p.36. 181 Miss. Pub. Serv. Comm’n and Pub. Util. Staff Rules of Practice and Proc. Chap. 7, Sect. 104, p. 45.

94

The rule provides no support for TURN’s recommendation. The Commission has not 1

ruled that SCE has failed to “adhere to the provisions” of any rule or order or failed to “timely 2

provide....reasonable information requested concerning the cost, purpose or construction of the facility, 3

plant or other capital item.” TURN’s reliance on the Mississippi Rule is unfounded. 4

TURN’s argument also erroneously characterizes SCE’s internal accounting policies, 5

asserting that SCE supposedly “recognizes the principle that AFUDC should not be recovered during a 6

period of project suspension.”182 TURN bases this entirely from SCE’s response to a data request.183 7

TURN’s conclusion is wrong. SCE’s response in the referenced data request made no indication that a 8

notification from the field always resulted in a manual shutoff of AFUDC accrual–only that it can be 9

done.184 10

The data request response also references SCE’s automatic system shut-off for AFUDC 11

after a work order has a period of inactivity for six months, which TURN claims supports its principle 12

that suspended projects should not accrue AFUDC. The purpose of the shutoff is to conservatively 13

account for SCE’s capital activity. SCE follows ASC guidance which requires that if project 14

abandonment is probable, the utility should cease capitalizing AFUDC.185 The system shutoff is to cease 15

AFUDC automatically rather than manually assessing each order for probability of abandonment. SCE 16

also employs other accounting processes to proactively address capital orders that should be canceled, 17

including reviewing orders with past estimated completion dates and three-months of inactivity. These 18

processes are all to address the potential cancellation of a capital project, not suspension. 19

In summary, SCE correctly accounts for AFUDC accruals. There is still financing cost 20

even if a project has been delayed, which is a proper cost of service. TURN’s assertion that suspended 21

projects should not accrue AFUDC based on accounting principles is unsubstantiated. 22

4. Recovery Of Property Tax Is Appropriate 23

During its discussion on AFUDC accrual, TURN also raises the capitalization of property 24

tax as an issue. There is no accounting reference or rationale provided for why the accounting for 25

AFUDC also applies to property tax. Additionally, TURN provides no basis for why SCE should not 26

182 TURN-05, Marcus, p. 29. 183 TURN-05, Marcus, p. 30, footnote 75. 184 SCE response to data request TURN-SCE-098, Q.05.b (05.b). See Appendix I p. 2. 185 ASC 980-835-25-1.

95

capitalize property taxes that are assessed on CWIP. Indeed, the California State Board of Equalization 1

includes CWIP in the property tax basis. Capitalizing property tax on construction occurs during the 2

normal course of business.186 3

186 Property taxes related to Construction Work in Progress (CWIP) are capitalized and collected through the

work order system as part of overheads. The amount charged to capital is based upon the Historical Cost Less Depreciation (HCLD) method adopted in D. 92549 in our Test Year 1981 GRC (A.59351).

Appendix A

Power Procurement

Exhibit SCE-18 – Generation

Chapter II - Power Procurement

Appendix A – Index

Document Page

Standard Capital Testimony, SCE-02, Vol. 4, p. 43 A-1

Standard Capital Workpaper, SCE-02, Vol. 4, p. 27 A-2

Standard Capital Workpaper, SCE-02, Vol. 4, p. 35 A-3

SCE’s Data Request Response to DRA-004-GSD Question 1 A-4

SCE’s Data Request Response to DRA-004-GSD Question 3 A-6

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A-3

Southern California Edison2015 GRC A.13-11-XXX

DATA REQUEST SET DRA-004-GSD

To: DRAPrepared by: Teresa Chang

Title: Financial AnalystDated: 10/03/2013

Received Date: 10/03/2013

Question 01:

Originator: Galen Dunham

Reference: SCE-02, Volume 04, page 42, 43

Subject: Power Procurement Department

Please provide the following:

1. On page 42, line 20, SCE states: “Cost of equipment per facility is estimated at $75,000 and cost associated with the addition tasks required at $75,000 per facility.” Please provide a reference in the SCE Workpapers for a justification for both $75,000 figures or other justification for these amounts.

Response to Question 01:

SCE estimates the cost of installing specialized communication equipment at $150,000 perrenewable facility, which generally comprises $75,000 for the cost of the equipment and $75,000 for additional tasks including installation, configuration, testing, and commissioning. As shown in the table below, the actual historical cost was an average of approximately $200,000 perfacility. For forecasting purposes, SCE estimates an average cost of $150,000 per facility due to cost efficiencies from resource aggregation and improved technology. SCE assumes the overall costs are split equally between the equipment and other tasks.

A-4


DATA REQUEST SET DRA-004-GSD

To: DRAPrepared by: Teresa Chang

Title: Financial AnalystDated: 10/03/2013


Question 03:

Originator: Galen Dunham

Reference: SCE-02, Volume 04, page 42, 43

Subject: Power Procurement Department


3. On page 43, line 10-11, SCE states: “Power Procurement needs $3.45 million in 2013, $1.78 million in 2014, $1.85 million in 2015, $1.55 million in 2016, and $1.55 million in 2017…” On page 46 of SCE-2 Annotated testimony states: “WP: SEC-02, Vol. 4, pp. 27 and 35 (for each year, take the amount on p. 27 and subtract the savings on p. 35). Please provide a summary table showing the items from page 27 and 35.


Please see attached spreadsheet for the summary table

A-6

DRA�Da

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DRA�004�GSD

SCE�02,�V

olum

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Item

Testim

ony�De

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2013

2014

2015

2016

2017

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1,478

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300

��

350

��

350

��

350

��

2,828

��

2Specialized

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1,500

��

1,500

��

1,200

��

1,200

��

7,638

��

Total�(A)

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1,800

��

1,850

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1,550

��

1,550

��

10,466

��

Page

�35

WBS

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tion

2013

2014

2015

2016

2017

Total

CSB�OP�EX�PP�GRC

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Ope

ratio

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�18

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Summary�of�Pag

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Commun

ication�Eq

uipm

ent

2013

2014

2015

2016

2017

Total

Total�Pow

er�Procuremen

t�Cap

ital�(A+

B)3,452

��

1,782

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1,845

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1,550

��

1,550

��

10,179

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Forecast�Capita

l�Expen

ditures

Que

stion�3.�On�page�43,�line

�10�11,�SCE

�states:��“Pow

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n�p.�35).��Please�provide

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mmary�table�show

ing�the�ite

ms�from�page�27

�and

�35.

A-7

Appendix B

Power Production Generation Policy


Chapter III - Power Production Generation Policy

Appendix B – Index

Document Page

SCE Response to DRA-054-PM1 Question 04 Revised B-1

SCE Response to DRA-106-PM1 Question 05.a-c B-5

Southern California Edison2015 GRC A.13-11-003

DATA REQUEST SET DRA-054-PM1

To: DRAPrepared by: Timothy G Condit

Title: Manager Project/Product IIDated: 12/03/2013


Question 04 Revised:

Originator: Peter Morse

Exhibit Reference: SCE-02, Vols. 5-10

Subject: Global Non-Nuclear Generation


4. Provide yearly average headcount and yearly hours charged to generation lines of business listed on Table I-I (SCE-02, Vol. 05 plus Catalina) 2008-2012 and year-to-date 2013.

Response to Question 04 Revised:

Updated Data Request Response: Note that in SCE's original response to this Data Request, thestaffing levels for "Peakers (incl McGrath & Solar)" for 2008 and 2009 was shown as zero. Thisis because during 2008 and 2009 Peaker staffing was tracked as part of, and was included in, thestaff levels shown for "Power Production Staff." To avoid any potential confusion, SCE hereinprovides a revised table that shows staffing levels for "Peakers (incl McGrath & Solar)" for 2008and 2009 separate from "Power Production Staff." Note that the PPD total staffing counts for2008 through 2013 remain unchanged from the earlier response.

The table below provides the end-of-year staffing levels of active SCE employees (personnel on leave are not included) during 2008 through 2012, as well as staffing levels recorded November 2013, for SCE's Power Production Department (PPD). Note that the 2008-2012 annual averages provided are simply the average of the staffing levels recorded at the start and end of each year (e.g., the 2009 average staff count is the average of the December 31, 2008 and December 31, 2009 recorded staffing levels). SCE's accounting system does not allow all SCE employee work hours charged to each generation area for each year to be directly pulled. It would require an extensive study for SCE to compute that data. Also note that work performed at SCE power plants, and therefore charged to the O&M and capital accounts for these plants, includes work performed by Supplemental Employees and by Contractors. The staffing level data provided

B-1

herein does not include Supplemental Employees and Contractors.

As noted in SCE-02 Volume 05 section I, PPD is responsible for the operations, maintenance and capital project implementation for SCE's gas-fueled, solar and hydroelectric generating assets. PPD also managed the decommissioning of the co-owned Mohave plant and oversees the plant site's ongoing maintenance. PPD also provides oversight of SCE's ownership interest in the co-owned Four Corners plant (i.e., note that Arizona Public Service is the operating agent for Four Corners, and as such, the plant is operated by APS employees rather than SCE employees). Also note that:

PPD employees who oversaw construction of the SCE Solar Photovoltaic (SPV) plants, and who �

provide ongoing operations and maintenance of those plants, are combined together with the Peaker staffing count. This is because many of the employees who operate and maintain the Peakers plants also operate and maintain the SPV plants (i.e., a portion of their time is spent on and records to Peakers and the remainder of their time is spent on and records to SPV work).

Personnel in other SCE departments (i.e., outside of PPD) also support the operations, �

maintenance and capital expenditures for PPD plants. Therefore, portions of the labor costs for these non-PPD employees are included in the 2008-2012 recorded costs for Hydro, Mountainview, Peakers and SPV, and Mohave and Four Corners oversight. Likewise, to the extent certain PPD employees support other SCE work that is not for the PPD-managed power plants, a portion of the labor costs for these PPD employees records to other SCE accounts (i.e., to accounts other than the Hydro, Mountainview, Peakers and SPV, and Mohave and Four Corners oversight cost accounts). Similarly, during 2008-2013 certain PPD employees spent a portion of their time supporting non-SCE facilities, and that work generated other operating revenue. The labor costs for these employees incurred while conducting that work were appropriately charged to that work, rather than to the O&M or capital accounts for the PPD-managed SCE power plants.

PPD Staff includes PPD employees who provide engineering, technical services and other �

support functions for all of the PPD plants (i.e., various portions of their time is spent on and records to Hydro, Mountainview, Peakers and SPV, and Mohave and Four Corners oversight).

Certain functions that were performed by PPD Staff during 2008 through 2012 were transferred �

to other SCE departments in late-2012. These other departments continue to provide support services to the PPD plants, and as such, the costs associated with these services continued to record to Hydro, Mountainview, Peakers and SPV, and Mohave and Four Corners oversight through 2013. This transfer of work and personnel to other departments accounts for a large portion of the PPD staffing level reduction, 112 to 74, experienced between 2012 and 2013.

REVISED TABLE showing 2008 and 2009 Peaker staffing broken out separately from PowerProduction Staff

B-2

Catalina staffing levels are provided below, and this data does not include personnel who support Catalina, but work in PPD or in other SCE organizations. These Catalina staffing levels are for all employees working at Catalina, which includes the gas, electric and water distribution operations in addition to the power generating operations, as certain employees at Catalina work in multiple areas.

B-3

Dep

artm

ent

12/3

1/08

Avg

07'

-08'

12/3

1/09

Avg

08'

-09'

12/3

1/10

Avg

09'

-10'

12/3

1/11

Avg

10'

-11'

12/3

1/12

Avg

11'

-12'

11/3

0/13

Avg

12'

-13'

Hyd

ro23

823

424

224

025

124

725

425

325

125

321

923

5M

ount

ainv

iew

4644

4847

5250

5051

4447

4143

Peak

ers (

incl

McG

rath

and

Sol

ar)

2926

2728

3230

3333

4037

3337

Moh

ave

3233

2026

1719

09

00

00

Four

Cor

ners

00

00

00

00

00

00

Pow

er P

rodu

ctio

n St

aff

115

102

109

112

120

115

106

113

112

109

7493

Tota

l46

043

744

645

347

245

944

345

7.5

447

445

367

407

Dep

artm

ent

12/3

1/08

Avg

07'

-08'

12/3

1/09

Avg

08'

-09'

12/3

1/10

Avg

09'

-10'

12/3

1/11

Avg

10'

-11'

12/3

1/12

Avg

11'

-12'

11/3

0/13

Avg

12'

-13'

Cat

alin

a44

4643

4443

4339

4139

3940

40To

tal

4446

4344

4343

3941

3939

4040

Pow

er P

rodu

ctio

n - Y

ear

End

and

Cal

cula

ted

Ave

rage

Sta

ffin

g L

evel

s20

0820

0920

1020

1120

1220

13

Cat

alin

a - Y

ear

End

and

Cal

cula

ted

Ave

rage

Sta

ffin

g L

evel

s20

0820

0920

1020

1120

1220

13

B-4




Title: Manager Project Product IIDated: 01/14/2014


Question 05.a-c:



Subject: Non-Nuclear Generation Global


5. (Global) As a follow-up to SCE’s response to DRA-054, Q.04, provide the amount of hours charged yearly, 2010-2013, (delineated separately) to Hydro, Mountainview, Peakers, Solar, Mohave, Four Corners, Power Production Staff and Catalina for the following:

a. Supplemental employees

b. Contractors

c. SCE employees (ORA understands that SCE stated “It would require an extensive study for SCE to compute that data,” yet ORA re-requests the information omitting 2008 and 2009 data).

Response to Question 05.a-c:

As stated in DRA-054 Q04 Revised.

"SCE's accounting system does not allow all SCE employee work hours charged to each generation area for each year to be directly pulled. It would require an extensive study for SCE to compute that data."

Additionally,

"Personnel in other SCE departments (i.e., outside of PPD) also support the operations,

B-5

maintenance and capital expenditures for PPD plants. Therefore, portions of the labor costs for these non-PPD employees are included in the 2008-2012 recorded costs for Hydro, Mountainview, Peakers and SPV, and Mohave and Four Corners oversight. Likewise, to the extent certain PPD employees support other SCE work that is not for the PPD-managed power plants, a portion of the labor costs for these PPD employees records to other SCE accounts (i.e., to accounts other than the Hydro, Mountainview, Peakers and SPV, and Mohave and Four Corners oversight cost accounts). Similarly, during 2008-2013 certain PPD employees spent a portion of their time supporting non-SCE facilities, and that work generated other operating revenue. The labor costs for these employees incurred while conducting that work were appropriately charged to that work, rather than to the O&M or capital accounts for the PPD-managed SCE power plants."

The hours charged to perform work are transferred internally via a single transaction that does not provide "hours charged" but instead provides a single dollar amount. Additionally Contract Workers and Supplemental Employees are paid via invoices submitted from their respective companies and are paid in a single transaction. It would require a study to compute the hours charged to each generation area by these contract and supplemental employees during 2010-2013.

SCE does not believe this information to be relevant because employee "work hours" were not directly utilized in the development of SCE's Hydro, Mountainview, Peakers, Solar, Mohave or Four Corners capital expenditure or O&M expense forecasts. The methods utilized to forecast future Labor and NonLabor costs, such as using last recorded year or an average of multiple years of recorded costs, would take into account all expenses incurred by Supplemental Employees, Contract Workers, and SCE employees performing work within a specific generation area.

B-6

Appendix C

Mohave


Chapter IV - Mohave

Appendix C – Index

Document Page

SCE Response to DRA-041-PM1 Question 10.b. C-1



To: DRAPrepared by: Karl GieszlTitle: Project Manager

Dated: 11/20/2013

Question 10.b:


Exhibit Reference: SCE-02, V. 6, Pt. 01.

Subject: Coal O&M


10. Provide the following regarding the Mohave Steam Power Generation O&M and Capital Expenditures:

b. SCE’s share of (including calculations derived from total Capital Expenditures) of total Capital Expenditures 2008-2012, year to date 2013 and total 2013 (when available).

Response to Question 10.b:

As explained in testimony (SCE-02, Vol. 6, Part 1, Chapter IX), SCE owns 56% of the Mohave Generating Station and plant site, and as such, is responsible for 56% of capital costs incurred. SCE's share of Mohave 2008-2012 recorded capital expenditures were provided in testimony (SCE02, Volume 6, Part 2, page 49, Figure VIII-2) and in supporting workpapers (Workpapers SCE-02 Volume 06, Part 02 page 121). The large majority of these SCE capital expenditures were for Mohave plant decommissioning. These amounts were not "calculated" from the plant's total capital expenditures per se (i.e., from the 100% ownership costs amounts), but rather reflect SCE's actual recorded costs.

SCE is the operating agent for Mohave. Each month the other Mohave plant owners reimburse SCE for the costs associated with their respective shares of capital expenditures and O&M expenses. SCE's actual recorded capital expenditures therefore already reflect the 100% ownership share of the costs incurred minus the revenue received from the other owners for their respective ownership shares. As shown in the table below, due to the normal billing cycle lag time, SCE's recorded expenditures each year vary slightly above or below SCE's 56% ownership share amount of the 100% ownership share costs. Also, the plant decommissioning project also required modifications to the plant switchyard. These modifications included SCE performing work on behalf of plant owner Nevada Power, related to a Nevada Power local substation that is

C-1

co-located with the plant switchyard. This substation work was 100% funded by Nevada Power, which accounts for a portion of the variance between SCE's actual recorded percentage share (i.e., as a percentage of plant's total 100% ownership share capital expenditures) as compared to SCE's 56% plant ownership percentage.

Also note that SCE's share of 2013 year-to-date recorded capital expenditures (i.e, through October 2013) is a net credit of approximately $315 thousand dollars. This net credit reflects the normal billing cycle lag, as well as reimbursements (i.e., credits) associated with revenue generated by the salvaging of plant equipment as part of the decommissioning project (i.e., salvage proceeds were credited to the decommissioning work order). Lastly, note that the 2013 data is preliminary, subject to revision and will not be considered final until SCE’s books are closed in the first quarter of 2014. It can be requested at that time.

C-2

Appendix D

Hydro


Chapter V - Hydro

Appendix D – Index

Document Page

Workpapers, SCE-02, Vol. 7, Part 1, p. 22 and 48 D-1

SCE Response to DRA-054-PM1 Question 1 D-3

TURN-070 Question 01.a D-4

TURN Original “Hydro 536 539 and 545 Workpapers – hydro 2013 data” D-6


ORA Response to SCE-DRA-046-PM1 Question 1 D-11

SCE Response to DRA-220-PM1 Question 3.a-z D-13


SCE Response to DRA-106-PM1 Question 22.a-c D-20

AACE International – Skills & Knowledge of Cost Engineering D-21

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D-2



To: DRAPrepared by: Timothy G. Condit



Question 01:



Subject: Global Non-Nuclear Generation


1. Has SCE conducted (or is in the process of conducting) any benchmarking studies from 2010 to present on the Power Production Department as a whole or for any of the generation lines of business listed on Table I-I (SCE-02, Vol. 05, plus Catalina)? If the answer is yes, provide the following for each benchmarking study: (a) purpose, (b) timeframe, (d) scope, (e) specific area studied, (f) results of studies, (g) SCE’s ranking when compared to other similar size US utilities.


Yes. During the first half of 2012, SCE conducted a benchmarking study of the SCE hydroelectric generating fleet recorded operations and maintenance costs that SCE incurred during 2009 through 2011. These recorded costs also included routine equipment refurbishment costs, which included a portion (but not all) of SCE's recorded hydro capital costs during those years. SCE engaged PA Consulting Group to assist in this effort, which included use of PA Consulting Group's proprietary hydro fleet "cost per weighted maintenance object" benchmarking metric. The study results are provided in the attached file titled "SCE Hydro Benchmarking Report July 2012."

SCE is the first North American hydroelectric fleet operator to engage PA Consulting Group to conduct hydro fleet cost benchmarking using the "cost per weighted maintenance object metric." However, the study also included a supplemental analysis, which consisted of a comparison of SCE Hydro recorded costs with other US utilities using FERC Form 1 data (see pages 69 through 72 of the study).

D-3


DATA REQUEST SET TURN-SCE-070

To: TURNPrepared by: Timothy G. Condit



Question 01.a:

Originator: Bob Finkelstein

SCE-02, Volume 7, Parts 1 & 2 (Generation – Hydro O&M and Capital)

1. Following up on TURN DR 25-13 Attachment 1:

a. Please explain the reason for payment of $1,502,000 for Bishop Creek Unit 2 rents in Final Cost Center F200632 in 2011. If any costs are for a prior period, please identify the costs paid in 2011 for each period prior to 2011. Either refer to the specific invoice or other document supporting this amount if already provided or provide an invoice, voucher, accounting, entry or other document to support these costs.

Response to Question 01.a:

SCE utilizes an accrual-based accounting system. Therefore adjustments are necessary to correct accruals (for additional information regarding the necessity for these large accrual adjustments please refer to DRA-019 Question 1) so that the final recorded/adjusted numbers will reflect the actual bills received. When these adjustments were made for the 2011 recorded they were incorrectly debited to the Bishop Creek Unit 2 FCC F200632. Nonetheless this error has no effect on SCE’s 2015 TY forecast because the forecast was not made at the FCC level but at the FERC level and the total (sum of FERC accounts 536 and 540) of the actual bills received matches that in testimony. The following table provides a summary of the 2011 Invoiced Fees for reference and comparison to testimony (Figure III-6 page 13).

D-4

638639

640

641

642

643

644

645

646

647

648

649

650

651

652

653

654

655

656657658659660

A B C D E F G H I

2013 9536000 Water�for�Power P0068Northern�Hydro F200986 Big�Creek�Comm��536�Water�for�Power L ��39.18�

2013 9536000 Water�for�Power P0068Northern�Hydro F201095 Eastwood�Ph��536�Water�for�Power L ��215.88�

2013 9536000 Water�for�Power P0068Northern�Hydro F528265 Big�Creek�Comm�536�Cloudseeding L ��2,261.18�

2013 9536000 Water�for�Power P0069 Eastern�Hydro F200965 Kern�River�3��536�Water�for�Power L ��40,954.35�

2013 9536000 Water�for�Power P0068Northern�Hydro F200986 Big�Creek�Comm��536�Water�for�Power NL 2,483,255.79�

2013 9536000 Water�for�Power P0068Northern�Hydro F201108 Edison�Lake�536�Water�for�Power NL ��206.98�

2013 9536000 Water�for�Power P0068Northern�Hydro F528265 Big�Creek�Comm�536�Cloudseeding NL ��984,048.79�

2013 9536000 Water�for�Power P0069 Eastern�Hydro F200632 Bishop�Creek�2��536�Water�for�Power NL ��(11,093.80)

2013 9536000 Water�for�Power P0069 Eastern�Hydro F200705 Poole�Ph��536�Water�for�Power NL ��19.73�

2013 9536000 Water�for�Power P0069 Eastern�Hydro F200885 East�Region�Com��536�Water�for�Power NL ��374,384.88�

2013 9536000 Water�for�Power P0069 Eastern�Hydro F200943 Borel�Pwrhouse��536�Water�for�Power NL ��17,002.00�

2013 9536000 Water�for�Power P0069 Eastern�Hydro F200954 Kern�River�1��536�Water�for�Power NL ��17,002.00�

2013 9540000 Rents P0068Northern�Hydro F201110 Edison�Lake��540�Rents L ��(1.50)

2013 9540000 Rents P0069 Eastern�Hydro F200656 Bishop�Creek�4��540�Rents L ��499.34�

2013 9540000 Rents P0068Northern�Hydro F200990 Big�Creek�Comm��540�Rents NL ��335,912.40�

2013 9540000 Rents P0068Northern�Hydro F201110 Edison�Lake��540�Rents NL ��185.27�

2013 9540000 Rents P0069 Eastern�Hydro F200888 East�Region�Com��540�Rents NL ��108,592.60�

water�for�power 4,353,485

2012�$ 4,346,965$��

For�Printing�Purposes,�SCE�Modifies�this�Line�of�Text�(and�column�widths):TURN�Original�Hydro�536�539�and�545�Workpapers��hydro�2013�data

D-6

Labor is included in TURN'sTotal.

TURN fails to capture F200929 which containsthe yearly Kaweah 3 Special Use Permit andincorrectly charged to FERC Account 539.

These two errors equate to approximately:

Note: SCE did not attempt to identify anyadditional required adjustments that willmost likely be required when the 2018 GRCreview process beings.






Question 05:


Exhibit Reference: SCE-2, Volume 7

Subject: Hydro Generation


5. Identify each hydro capital project that is complete, as of 4/3/2014. For those projects with costs in 2014 provide the total 2014 capital expenditures. If the above information is not currently available provide the information when it becomes available.


SCE interprets this question to pertain to Capital projects completed between Jan 1, 2013 and April 3, 2014. See the attached spreadsheet for a listing of the information as requested for the 91 completed projects. Please note that the capital expenditure amounts are preliminary and subject to revision.

D-7

REF WBS Element Project 2014 YTD Expenses ($000) ($Nominal)

Project Status as of 4/3/2014

11 CG0-00-PP-HE-000074 Mt. Tom Substation - Complete25 CG0-00-PP-HN-000010 Big Creek 3 Replace 12 KV Substation 1 Complete28 CG0-00-PP-HE-000104 Kern River - Automation Upgrade (31) Complete40 CG0-00-PP-HE-000067 Poole - Replace Unit Breaker/ Station Light & Power 145 Complete49 CG0-00-PP-HE-000075 Ontario 1 Replace Circuit Breakers (4) Complete54 CG0-00-PP-HE-000081 Bishop - Communication Fiber - Complete74 CG0-00-PP-HE-000105 Kern River 1 Unit 2 - Turbine Refurbishment 11 Complete98 CG0-00-PP-HN-000063 Mammoth Pool Unit 1 Rewind & Field Poles 1,729 Complete101 CG0-00-PP-HE-000103 Borel - Install Solid State Exciters Units 1 & 2 76 Complete105 CG0-00-PP-HN-000024 Big Creek 1 Unit 1 - Solid State Excitation - Complete106 CG0-00-PP-HN-000024 Big Creek 1 Unit 2 - Solid State Excitation - Complete107 CG0-00-PP-HE-000108 Kern River 3 - Replace TSO Bypass Valves - Complete128 CG0-00-PP-HE-000085 Sabrina - Replace Gate Operator 13 Complete146 CG0-00-PP-HN-000041 Camp 62 Replace Valve Actuator - Complete150 CG0-00-PP-HE-000064 Saddlebag Dam - Wood Spillway Modification 0 Complete158 CG0-00-PP-HN-000066 Huntington Lake Dam Geomembrane Liner - Complete162 CG0-00-PP-HE-000111 Kaweah 2 - Gunite Canals - Complete165 CG0-00-PP-HE-000113 Tule Flowline - Rebuild 500' of Flume - Complete174 CG0-00-PP-HE-000037 Kaweah 1 - Flowline Rehabilitation 307 Complete179 CG0-00-PP-HE-000050 Bishop 6 - Replace Flowline/Install AVM - Complete185 CG0-00-PP-HE-000102 Borel Forebay Install Crane 3 Complete216 CG0-00-PP-HE-000062 Kern River 3 - Flowline Road Work 16 Complete217 CG0-00-PP-HE-000110 Kern River3 - Replace Adit 19-20 Bridge with Culvert - Complete221 CG0-00-PP-HE-000093 Bishop 4 - Replace Fuel System - Complete224 CG0-00-PP-HN-000086 Big Creek 1 Camp Cottage Renovations (0) Complete226 CG0-00-PP-HN-000087 Big Creek 1 Construct Admininistration/Dispatch Office 103 Complete242 CG0-00-PP-HN-000090 Florence Lake Replace Camp Domestic Water Line - CompleteN/A CG0-00-PP-HE-000005 MC3 Install Conduit for Ground Grid - CompleteN/A CG0-00-PP-HE-000005 Bridgeport Replace 16 KV AR Strosnider - CompleteN/A CG0-00-PP-HE-000006 Kaw 1 Replace Governor - CompleteN/A CG0-00-PP-HE-000007 KR3 Calibrated Flume 8 CompleteN/A CG0-00-PP-HE-000007 Install AVM below Intake 4 - CompleteN/A CG0-00-PP-HE-000007 SAR1 Intake Fish Release AVM Replacement - CompleteN/A CG0-00-PP-HE-000007 Fontana PH AVM Replacement - CompleteN/A CG0-00-PP-HE-000007 SAR3 PH AVM Replacement - CompleteN/A CG0-00-PP-HE-000007 SAR3 Headbreaker AVM Replacement - CompleteN/A CG0-00-PP-HE-000007 San Gorgonio 2 Flowline AVM Replacement - CompleteN/A CG0-00-PP-HE-000007 MC3 Penstock AVM Replacement - CompleteN/A CG0-00-PP-HE-000007 Tule PH Penstock AVM Replacement - CompleteN/A CG0-00-PP-HE-000007 Kaw3 Marble Fork Sandbox Fish Rel AVM Replacement - CompleteN/A CG0-00-PP-HE-000007 Borel Canal Pioneer Siphon AVM Replacement - CompleteN/A CG0-00-PP-HE-000007 KR1 Sandbox Minimum Release AVM Replacement - CompleteN/A CG0-00-PP-HE-000007 KR3 Penstock #1 AVM Replacement - CompleteN/A CG0-00-PP-HE-000007 KR3 Penstock #2 AVM Replacement - CompleteN/A CG0-00-PP-HE-000019 Minaret Sub Replace Slope 12KV Breaker - CompleteN/A CG0-00-PP-HE-000023 Ontario 2 Main Transformer Replacement 5 CompleteN/A CG0-00-PP-HE-000023 Skiland Replace SL&P Transformer Bank - CompleteN/A CG0-00-PP-HE-000029 KR1 Install PH Access Roads - CompleteN/A CG0-00-PP-HE-000029 Rush Creek Replace Access Bridge 2 CompleteN/A CG0-00-PP-HE-000038 KR1 Replace Release Gate Actuator Valve (11) CompleteN/A CG0-00-PP-HE-000040 Saddlebag Replace Cabin Roof - CompleteN/A CG0-00-PP-HE-000040 Control HVAC Replacements - CompleteN/A CG0-00-PP-HE-000040 KR3 PH Control Room HVAC Replacement - CompleteN/A CG0-00-PP-HE-000041 Bishop Plant 4 Unit 4 Rewind Rotor 1 CompleteN/A CG0-00-PP-HE-000041 Bishop Plant 4 Unit 4 Rewind Stator 1 CompleteN/A CG0-00-PP-HE-000042 Lundy Unit 1 Turbine Replacement - CompleteN/A CG0-00-PP-HE-000042 Bishop Plant 4 Unit 4 Replace Waterwheel - CompleteN/A CG0-00-PP-HE-000042 Bishop Plant 2 Unit 3 Replace Waterwheel - CompleteN/A CG0-00-PP-HE-000046 Agnew Tram Retaining Wall - CompleteN/A CG0-00-PP-HE-000054 Kaweah 2 Intake Structure 34 Complete

2014 SCE Hydro Capital Completed Project Expenses

D-8

REF WBS Element Project 2014 YTD Expenses ($000) ($Nominal)

Project Status as of 4/3/2014

2014 SCE Hydro Capital Completed Project Expenses

N/A CG0-00-PP-HE-000063 Agnew Dam Geomembrane/Replace Intake Grids 0 CompleteN/A CG0-00-PP-HE-000070 June Lake Sub IR-12kv Regulator - CompleteN/A CG0-00-PP-HE-000077 Kaweah 3 - Reline Forebay 0 CompleteN/A CG0-00-PP-HE-000081 Bishop/Mono Basin Telecom Upgrade - CompleteN/A CG0-00-PP-HE-000103 Borel Unit 1 Solid State Exciter (8) CompleteN/A CG0-00-PP-HE-000103 Borel Unit 2 Solid State Exciter 84 CompleteN/A CG0-00-PP-HE-000104 Kern 1 Automation (31) CompleteN/A CG0-00-PP-HN-000023 BC3 Install Rig Router - CompleteN/A CG0-00-PP-HN-000023 BC3 Bank 3 Replace Bushings - CompleteN/A CG0-00-PP-HN-000025 BC2 800# Reducing Station - CompleteN/A CG0-00-PP-HN-000025 BC2A 800# Reducing Station - CompleteN/A CG0-00-PP-HN-000025 BC8U1 RPC TEMP monitoring - CompleteN/A CG0-00-PP-HN-000025 BC8U2 RPC TEMP monitoring - CompleteN/A CG0-00-PP-HN-000025 BC4 Generator Fire Suppression 2 CompleteN/A CG0-00-PP-HN-000031 PPH Replace Septic System - CompleteN/A CG0-00-PP-HN-000031 EPS Elevator Upgrade (2) CompleteN/A CG0-00-PP-HN-000031 EPS Security Gate - CompleteN/A CG0-00-PP-HN-000031 Pitman Install Building at station - CompleteN/A CG0-00-PP-HN-000044 HL Dam 2 Gatehouse Roof - CompleteN/A CG0-00-PP-HN-000044 SL Gatehouse Roof 1 CompleteN/A CG0-00-PP-HN-000044 BC1 Wellness Center - CompleteN/A CG0-00-PP-HN-000044 BC2 Install Covered Storage - CompleteN/A CG0-00-PP-HN-000046 Dowville Campground - CompleteN/A CG0-00-PP-HN-000046 College Campground - CompleteN/A CG0-00-PP-HN-000046 Rancheria Campground - CompleteN/A CG0-00-PP-HN-000046 Railroad Grade Rehabilitation 72 CompleteN/A CG0-00-PP-HN-000051 SL Dam Geomembrane - CompleteN/A CG0-00-PP-HN-000055 Horseshoe Bend Trail - CompleteN/A CG0-00-PP-HN-000067 Dam 7 Install Piezo's - CompleteN/A CG0-00-PP-HN-000080 BC3 Million Dollar Mile - CompleteN/A CG0-00-PP-HN-000088 BC1 Remodel Front Office - Complete

D-9

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Ratepayer Advocates in the Gas, Electric, Telecommunications and Water Industries

ORA Response to SCE Data Request Southern California Edison Company Test Year 2015 General Rate Case

A.13-11-003

Origination Date: August 12, 2014 Due Date: August 28, 2014 Response Date: August 28, 2014

To: Mike Marelli Sue DiBernardo [email protected] [email protected](626) 302-3408 (626) 302-4353

From: Truman Burns, Project Coordinator Donna-Fay Bower, Assistant Project Coordinator Division of Ratepayer Advocates 505 Van Ness Avenue, Room 4205 San Francisco, CA 94102

Response by: Peter Morse Phone: 415.703.2740 Email: [email protected]

Data Request No: SCE-DRA-046-PM1Exhibit Reference: ORA-7 Subject: Hydro Capital

The following is ORA’s response to SCE’s data request. If you have any questions, please contact the responder at the phone number and/or email address shown above.

Q.1: Please identify, and provide an example of the method(s) ORA utilized to determine, based on 2013 and 2014 recorded expenditures, that the projects it references on page 22 of its testimony, and provided in DRA-220-PM1 Q3, are “off” schedule as compared to the projected in-service date contained within SCE’s workpapers.

A.1: ORA makes adjustments based on three scenarios rather than one as identified in ORA-7 pp. 22-23 which are listed below.

� Project had no spending in 2013; therefore ORA shifted the schedule of the forecast spending of the project to one year later.

o Ex. Northern Hydro Automation Upgrades

D-11

2

� The project spending in 2013 was significantly lower than forecast by SCE, therefore ORA shifted the schedule of the forecast spending of the project to one year later.

o Agnew – Replace 4KV Transformers and Transmission Line

� The project had significant spending in 2013 which was not forecast by SCE, therefore ORA shifted the schedule of the forecast spending of the project to one year earlier.

o Big Creek 8 High Pressure Piping

For additional detail see Ex. ORA-7, WP pp. 7-5.

It is ORA’s position that the differences in spending for Hydro capital projects from forecast 2013 to actual 2013 will affect SCE’s forecast in service date.

This response prepared by Peter Morse.

END OF RESPONSE ________________________________________________________________________

D-12



To: DRAPrepared by: Timothy G. ConditTitle: Manger Project/Product II

Dated: 03/12/2014


Question 03.a-z:


Exhibit Reference: SCE-2, Vol. 7

Subject: Hydro


1. Create a spreadsheet answering yes or no to the below criteria for each Hydro capital project(s) listed on workpapers pp. 6-8 (SCE-02, Vol. 07, Pt. 2) with capital expenditures forecast for 2013-2015.

a. Work at the site has not commencedb. Work at the site has commencedc. Project is completed. SCE has obtained all necessary permits to conduct the work forecast in the 2015 GRC

applicatione. SCE does not need any permits to conduct the work forecast in the 2015 GRC

applicationf. SCE has not determined if it needs permits to conduct the work forecast in the 2015

GRC applicationg. SCE requires local government approvalh. SCE has received local government approvali. SCE has not determined if it needs local government approvalj. SCE has been denied local government approval (local government includes, city

and/or county)k. Easements requiredl. Easements approved m. Easements deniedn. The forecast is based on expert experience/judgment of field personnel and/or a local

contractor

D-13

o. The forecast is based on historical experience (include which historical project(s) forecast is based on)

p. Finalized engineering designq. Received FERC approvalr. Not received FERC approval s. Not determined if FERC approval is necessaryt. Received bids for contract worku. Submitted to FERC for reviewv. Conducted a preliminary California Environmental Quality Act assessment (for any

applicable projects, enter NA if not applicable)w. Identified need for environmental assessments (if any required assessments have been

identified, list all required) x. Percent contingency built into TY 2015 GRC application forecast is known (if the

percent contingency is known, include the contingency percentage)y. SCE is no longer pursuing this project in the 2013-2015 timeframez. Project is on a different schedule than listed on workpapers pp. 6-8 (SCE-02, Vol. 07,

Pt. 2) (if applicable provide the latest schedule for forecasted capital expenditures)

Response to Question 03.a-z:

Per conversation with ORA (Peter Morse) SCE is providing the requested information only for projects that have forecast costs greater than $5 million. For those projects less than $5 million SCE is responding only to Questions X through Z.

The response to Questions A through Z for all projects greater than $5 million (with the exception of the Mammoth Pool Fishwater Generator project and the Mammoth Pool HB Valve project) are provided in the attached table. Responses to Questions Y through Z for the Mammoth Pool Fishwater Generator and the Mammoth Pool HB Valve projects are provided in the response for all projects less than $5 million below.

The response to Question X (each projects' cost forecast percent contingency) is summarized in the table below for all projects.

D-14

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(1) See the attached pdf for an itemized listing of the percent contingency of each project with a forecast cost of greater than $5 million. Note that the weighted average for these projects is 25% as shown in the table above.

(2) Projects are complete and therefore, by definition, the cost estimate contingency is zero.

(3) See response to DRA-106-PM1 Question 22 a-c where SCE explained that amount of contingency is not separately itemized for small projects that have only limited engineering work completed to date. Therein, SCE explained that the typical contingency embedded in the cost estimates for these projects was approximately 10-15% (based on a representative sample of those projects in the 2015 GRC forecast)

(4) Dollar amount was arrived at through the summation of the 2015 GRC forecasted costs for the six projects that are off schedule as compared to the forecasted in-service date shown in workpapers. (see response to Y and Z for a listing of those six projects)

In response to questions Y and Z for all projects less than $5 million and the Mammoth Pool Fishwater Generator and Mammoth Pool HB Valve Replacement projects (which are greater than $5 million): As of March 25, 2014, all Hydro GRC forecasted projects (with the exception of the following six) are on schedule to be completed by their projected in-service date as compared to the forecasted in-service date shown in workpapers.

D-16






Question 01:



Subject: Hydro Generation


1. In response to DRA-220-PM1, Question 3, SCE identified five hydro capital projects as “Off schedule projects not currently forecast to be in-service by December 2017.” Provide updated yearly 2014-2017 forecast capital expenditures for all hydro capital projects identified by SCE’s response. Also include the current schedule of the projects identified.


Subsequent to SCE's response to DRA-220-PM1 Question 3 revisions have been made to three of the five previously identified off-schedule projects. The Big Creek 3 Replace Domestic Water Service and Huntington Lake Dam Geomembrane Projects have been expedited and are now forecasted to be in-service by the end of 2016 and the Mammoth Pool HB Valve project is being assessed for a possible schedule acceleration. The following table depicts the current 2014-2017 forecast capital expenditures for those five previously projects identified in DRA-220-PM1 Question 3. Please note that the total expenditures now being forecast for these projects exceed the GRC Application forecast amount by $4.75 million dollars.

D-18






Question 22.a-c:





22. (Hydro Capital) Provide the average amount (in $ and percentage of total, include all calculations in Excel format with active cells) of contingency built into the forecasts for the following areas:

a. Electrical Equipment Programs and Projects (Table III-4), excluding Northern Hydro Miscellaneous Electrical

b. Dams and Waterways Major Programs and Projects (Table V-19), excluding Northern Hydro Misc. Dams and Waterways (Table V-25)

c. Structures and Grounds Major Programs and Projects (Table VI-26), excluding Northern Hydro Misc. Structures and Grounds Projects (Table VI-30).

Response to Question 22.a-c:

As explained in testimony SCE-02, Vol. 7, Pt. 2, p. 4-6, the level of detail contained in the forecast for each individual project generally increases as the start date for the project approaches. The cost forecasts for the numerous projects included in the three areas in question (Electrical Equipment Programs and Projects, Dams and Waterways Major Programs and Projects, and Structures and Grounds Major Programs and Projects) cannot be averaged as contingencies may be built into individual components of projects, particularly in the conceptual estimate phase. The typical contingency embedded in each project cost forecast during the final engineering phase is in the range of 10% to 15%.

D-20

D-22

5 of 6 projects were identified as being asClass 4 (Conceptual Engineering) asreported in DRA-220-PM1 Q3.

D-24

Class Level 4 Accuracy Range

�

D-25

With an expected accuracy range of 3 to 12 for a Class 4 project:

Using footnote (a) an acceptable contingency range falls between:+30/-15% and +120/-60%. (i.e. 3 and 12 times the values of +10/-5%)

Appendix E

Mountainview


Chapter VI - Mountainview

Appendix E – Index

Document Page

SCE Response to DRA-Verbal-057 E-1

Mountainview 549 Operations Forecasts E-4

ORA Response to SCE-DRA-065-PM1 Question 1. a-f. E-5

TURN Original Workpapers MOUNTAINVIEW CSA E-10


DATA REQUEST SET DRA-Verbal-057

To: DRAPrepared by: June BoteTitle: Financial Analyst

Dated: 05/13/2014


Question 01:

Originator: Truman Burns

1. Please provide the unadjusted final cost center data for 2013 recorded expense.


Please see the attached excel file that has the unadjusted final cost center raw data for the 2013 recorded expense. FERC accounts tie to pages 320-323 of the 2013 FERC Form 1 report. This file will also include FCCs that are not included in the 08-12 recorded-adjusted data used in the 2015 rate case because they have been created since the filing.

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E-3

MOUNTAINVIEW�549�OPERATIONS�FORECASTSSCE�AND�TURN

SCE�FORECAST Labor NonLabor Other Total2008 3,228 8,467 0 11,6952009 3,637 6,475 0 10,1122010 3,655 4,734 0 8,3892011 3,507 4,482 0 7,9892012 3,790 4,491 0 8,281

SCE�APPLICATION LRY 3,790 4,491 0 8,281Move�Added�Facilities�to�Other (72) 70 (2)

SCE�REBUTTAL�POSITION 3,790 4,419 70 8,279

TURN�FORECAST Labor NonLabor Other Total2008 3,228 8,467 0 11,6952009 3,637 6,475 0 10,1122010 3,655 4,734 0 8,3892011 3,507 4,482 0 7,9892012 3,790 4,491 0 8,2812013 3,762 3,775 0 7,537

Use�2010�2013�Average 4�Yr�Ave 3,678 4,371 0 8,049Move�Added�Facilities�to�Other (72) 70 (2)

TURN�RECOMMENDED 3,678 4,300 70 8,048

CORRECTED�TURN�FORECAST Labor NonLabor Other Total(as�corrected�by�SCE) 2008 3,228 8,467 0 11,695

2009 3,637 6,475 0 10,1122010 3,655 4,734 0 8,3892011 3,507 4,482 0 7,9892012 3,790 4,491 0 8,2812013 4,467 4,076 0 8,543

Use�2010�2013�Average 4�Yr�Ave 3,854 4,446 0 8,300Move�Added�Facilities�to�Other (72) 70 (2)

CORRECTED�RESULT 3,854 4,374 70 8,298

E-4

CONFIDENTIAL Protected Materials Pursuant to California Public Utilities Commission Decisions and

Applicable Law. -Public Disclosure Restricted-

Ratepayer Advocates in the Gas, Electric, Telecommunications and Water Industries

ORA Response to SCE Data Request Southern California Edison Company Test Year 2015 General Rate Case

A.13-11-003

Origination Date: August 22, 2014 Due Date: September 8, 2014 Response Date: September 9, 2014

To: Mike Marelli Sue DiBernardo [email protected] [email protected](626) 302-3408 (626) 302-4353

From: Truman Burns, Project Coordinator Donna-Fay Bower, Assistant Project Coordinator Division of Ratepayer Advocates 505 Van Ness Avenue, Room 4205 San Francisco, CA 94102

Response by: Peter Morse Phone: 415.703.2740 Email: [email protected]

Data Request No: SCE-DRA-065-PM1 Exhibit Reference: ORA-7C Subject: Mountainview

The following is ORA’s response to SCE’s data request. If you have any questions, please contact the responder at the phone number and/or email address shown above.

Q.1: Regarding ORA workpaper “A.13-11-003_SCE 2015 GRC - ORA-7C Non-Nuclear Generation Costs CONFIDENTIAL Workpaper_Peter Morse.xls” worksheet “WP 7-8C” which calculates the Variable Fee as explained in ORA testimony ORA-7 page 34, lines 4-17:

Per a conference call on 8/22/14 between ORA and SCE, SCE identified several formula and label errors in ORA workpaper “A.13-11-003_SCE 2015 GRC - ORA-7C Non-Nuclear Generation Costs CONFIDENTIAL Workpaper_Peter Morse.xls” worksheet “WP 7-8C”.

E-5

CONFIDENTIAL Protected Materials Pursuant to California Public Utilities Commission Decisions and Applicable Law.

-Public Disclosure Restricted-

2

a. Please confirm that the attached revised workpaper “(SCE REVISED) ORA WP 7-8C CONFIDENTIAL” corrects these errors. (Note that cells with the corrected formulas are highlighted in red and the corrected labels are red-lined.)

b. If ORA agrees to the corrected formulas in the revised workpaper “(SCE REVISED) ORA WP 7-8C CONFIDENTIAL”, does ORA agree that the “Annualized Final 2015 ORA Variable Fee Forecast” in Line. No. D-21 is and the “SCE Forecast Minus ORA Forecast” amount in Line No. D-23 is

c. If ORA agrees to the corrected formulas in the revised workpaper “(SCE REVISED) ORA WP 7-8C CONFIDENTIAL” does ORA agree that the revised workpaper would require a revision to ORA’s proposed TY 2015 forecast and adjustment for the Variable Fee as stated on ORA-7 page 34, line 16, that should read as follows:

“… to reach a TY 2015 forecast of which is a …”

d. If ORA agrees to the corrected formulas in the revised workpaper “(SCE REVISED) ORA WP 7-8C CONFIDENTIAL” does ORA agree that the revised workpaper would require a revision to ORA’s revised TY 2015 forecast for Mountainview (all FERC Accounts) is $47.727 million?

e. If ORA agrees to the corrected formulas in the revised workpaper “(SCE REVISED) ORA WP 7-8C CONFIDENTIAL” does ORA agree that the values as stated on ORA-7, page 29, Table 7-11 should read as follows ($000 2012):

CSA Annual Fees (Other) x ORA:

CSA Annual Fees (Other) x SCE-ORA:

Total x ORA: $47.727

Total x SCE-ORA: $2.536

E-6

CONFIDENTIAL Protected Materials Pursuant to California Public Utilities Commission Decisions and Applicable Law.

-Public Disclosure Restricted-

3

f. If ORA agrees to the corrected formulas in the revised workpaper “(SCE REVISED) ORA WP 7-8C CONFIDENTIAL” does ORA agree that the revised workpaper would require revisions to ORA’s testimony ORA-7 Table 7-2, Table 7-3, Table 7-4, Table 7-9, Table 7-11, Table 7-12, Graph 7-4 and Graph 7-6?Please identify, and provide an example of the method(s) ORA utilized to determine, based on 2013 and 2014 recorded expenditures, that the projects it references on page 22 of its testimony, and provided in DRA-220-PM1 Q3, are “off” schedule as compared to the projected in-service date contained within SCE’s workpapers.

A.1:

a. In part. SCE correctly made changes to reflect errors in ORA’s spreadsheet; However, per a phone call on 9/8/14 between ORA and SCE, SCE identified SCE “inadvertently” changed cells which were correct in ORA’s original spreadsheet. SCE did not note where the inadvertent changes were made. The changes SCE made to ORA’s spreadsheet overstated the Mountainview Variable forecast.

SCE’s version produced a Variable Fee forecast of while the correct version produced a forecast of See the attached spreadsheet, which correctly reflects O changes ORA made to spreadsheet supplied by SCE are highlighted in purple). ORA will update the affected text, tables, graphs and WPs in errata.

b. See ORA’s response to 1a.

c. See ORA’s response to 1a.

d. See ORA’s response to 1a.

e. See ORA’s response to 1a.

f. See ORA’s response to 1a.

Response prepared by Peter Morse.

END OF RESPONSE ________________________________________________________________________

E-7

CONFIDENTIALProtected�Materials�Pursuant�to�California�Public�Utilities�Commission�Decisions�and�Applicable�Law.

�Public�Disclosure�Restricted�

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E-8

CONFIDENTIALProtected�Materials�Pursuant�to�California�Public�Utilities�Commission�Decisions�and�Applicable�Law.


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E-9

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E-11

Appendix F

Peakers


Chapter VII - Peakers

Appendix F – Index

Document Page

SCE Response to DRA-067-PM1 Question 3 F-1

SCE Response to DRA-106-PM1 Question 13 F-3




Title: ManagerDated: 12/10/2013


Question 03:


Exhibit Reference: SCE-02, V. 09.

Subject: Peakers


3. Provide monthly recorded adjusted O&M expenses charged to the McGrath powerplant for 2012 and 2013 January-November, by FERC account (in nominal and base year 2012 $ with escalation rates) and further delineated by labor, non-labor, operation expense, maintenance expense and other.


Approximately half of Peakers Total Annual O&M expense records directly to the operational Peakers. The remaining, approximately half of the Peakers Total Annual O&M expense, is common (i.e., shared) for all Peakers and is not allocated out to the individual plants. Therefore, SCE can not directly pull from SCE's accounting system the total O&M expense that would logically be attributable to any single Peaker including the McGrath Peaker. Nevertheless, as explained in Testimony page 9 lines 20-30, SCE did analyze that portion of 2012 total Peaker O&M expense that was directly recorded to McGrath. That 2012 data is provided in the table below (by month, sub-divided by FERC account, Labor and NonLabor) and attached as an Excel file. Note that none the Peakers recorded any "Other" O&M expenses during 2012.

As indicated in Testimony, page 9 lines 16-17, the McGrath Peaker began generating electricity in September 2012. O&M recorded expenses shown in the table below for months January through August were largely related to construction, and subsequently adjusted out of the O&M recorded expenses and debited to the McGrath Peaker construction capital project work order. This transfer accounts for a portion of the negative O&M expenses recorded during September through December in various accounts.

F-1

As indicated in Testimony page 10 lines 1-2, SCE's 2015 Test Year O&M Expense forecast included a $1.206 million upward adjustment to account for a full year of McGrath O&M in 2015, given that McGrath only operated for approximately three months during 2012. This upward adjustment funds necessary work activities that directly record to McGrath, as well as an increase in the amount of work that is common to all Peakers caused by the addition of the McGrath Peaker.

SCE does not have recorded-adjusted O&M expenses for 2013. Pursuant to the Rate Case Plan, SCE has provided the most recent five years of historical data for each sub-account at the time the GRC Application was filed. Please refer to SCE's response to MDR.II.09. When 2013 recorded data is finalized in FERC FORM 1, approximately in March/April 2014, SCE will provide the recorded expense by FERC account, when requested. The data will not be recorded-adjusted data, and will not be by sub-account.

F-2






Question 13:





13. (Peakers) Regarding DATA REQUEST SET DRA-067-PM1, provide yearly recorded adjusted expenses for “the remaining approximately half of Peaker Total Annual O&M expense is common (i.e., shared) for all Peakers and is not allocated out to the individual plants” by year 2008-2012 delineated by labor, non-labor and other (in base year and nominal 2012$ with escalation rates).


As explained in DRA-067-PM1 Q4: Approximately half of Peaker Total Annual O&M expense records directly to each of the operational Peakers. The remaining approximately half of Peaker Total Annual O&M expense is common (i.e., shared) for all Peakers and is not allocated out to the individual plants.

Please see the attached spreadsheet showing the 2008-2012 common (i.e., shared) Peaker expenses as requested.

F-3

2008

2009

2010

2011

2012

2008

2009

2010

2011

2012

Labo

r2,

063

1,83

61,

960

2,05

01,

902

Labo

r1,

925

2,43

82,

852

3,03

62,

963

Non

-Lab

or3,

380

2,56

92,

382

2,31

12,

659

Non

-Lab

or1,

868

2,80

51,

724

1,71

51,

550

Oth

er0

00

00

Oth

er0

00

00

Tota

l5,

443

4,40

54,

342

4,36

04,

560

Tota

l3,

793

5,24

34,

576

4,75

24,

514

2008

2009

2010

2011

2012

2008

2009

2010

2011

2012

Labo

r1,

807

1,65

81,

832

1,98

51,

902

Labo

r1,

687

2,20

32,

665

2,94

02,

963

Non

-Lab

or3,

106

2,37

62,

238

2,25

32,

659

Non

-Lab

or1,

717

2,59

31,

620

1,67

31,

550

Oth

er0

00

00

Oth

er0

00

00

Tota

l4,

914

4,03

44,

070

4,23

84,

560

Tota

l3,

403

4,79

64,

285

4,61

34,

514

2008

2009

2010

2011

2012

Labo

r3,

988

4,27

44,

812

5,08

64,

865

Non

-Lab

or5,

248

5,37

44,

106

4,02

64,

209

Oth

er0

00

00

Tota

l9,

236

9,64

88,

918

9,11

29,

074

2008

2009

2010

2011

2012

Labo

r3,

494

3,86

14,

497

4,92

54,

865

Esca

latio

n20

0820

0920

1020

1120

12N

on-L

abor

4,82

34,

969

3,85

83,

926

4,20

9La

bor

1.14

141.

1070

1.07

011.

0327

1.00

00O

ther

00

00

0N

on-L

abor

1.08

811.

0814

1.06

421.

0254

1.00

00To

tal

8,31

78,

830

8,35

58,

851

9,07

4O

ther

1.00

001.

0000

1.00

001.

0000

1.00

00

($00

0 N

omin

al$)

($00

0 N

omin

al$)

($00

0 N

omin

al$)

Tot

al P

eake

rs O

pera

tions

and

Mai

nten

ance

Peak

ers D

irec

t Ope

ratio

ns a

nd M

aint

enan

cePe

aker

s Com

mon

Ope

ratio

ns a

nd M

aint

enan

ce($

000

Con

stan

t 201

2$)

($00

0 C

onst

ant 2

012$

)

($00

0 C

onst

ant 2

012$

)

F-4

Appendix G

Solar Photovoltaic Program (SPVP)


Chapter VIII - Solar Photovoltaic Program (SPVP)

Appendix G – Index

Document Page

SCE Response to TURN-SCE-077 Question 1a G-1

SCE Response to DRA-Verbal-010 Question C.01 G-3

SCE Response to DRA-Verbal-013 Question C.01 G-5

SCE Response to DRA-Verbal-018 Question A.01 G-7

& CONFIDENTIAL Worksheets

SCE Response to DRA-202-PM1 Question 7 & Table G-23

SCE Response to DRA-291-PM1 Question 02.b G-25

SCE Response to DRA-291-PM1 Question 4 G-26

& CONFIDENTIAL - SunPower MSA Termination Clause

SCE Response to DRA-309-PM1 Question 01.b G-32

SCE-2 Vol 10 Workpaper 18b G-33

SCE-2 Vol 10 Workpaper 35a G-34

Table 2 - Solar 2015 GRC O&M Forecast Detail G-35

TURN Response to SCE-TURN-002 082814 & Attachment G-36

Table 3 - Added Facility Costs and Data G-39

SCE-2 Vol 10 Workpaper 90 G-42

Tables 4 & 5 – CONFIDENTIAL-SunPower Termination Cost Comparison G-43

Southern California Edison

2015 GRC A.13-11-003


To: TURNPrepared by: Loring Fiske-Phillips



Question 01.a:


SCE-02, Volume 10 (Generation – Solar PV, Fuel Cell, and Catalina)

Solar Photovoltaic Program

1. Following up on TURN DR 52-06:

a. Please identify, with specific reference to Edison’s TDBU workpapers, where the SPVP money paid to TDBU has been properly credited against the O&M expenses to be paid by ratepayers in the current General Rate Case, given that the SPVP money is not recorded as Other Operating Revenue.


Intra-company transfers from the Solar Photovoltaic Program (SPVP) for ongoing maintenance expenses are credited to T&D final costs centers F501513, F501514, and F501524. These cost centers are shown in the workpapers for SCE-03, Volume 8 in FERC Account 592.150 (p 100) for F501513 and FERC Account 568.150 (p 80) for F501514 and F501524. The workpapers include the total amounts recorded to the final costs centers; therefore, to demonstrate the recorded transfers, the attached spreadsheet shows the 2012 calculations by project (basis amount and rate), ties out the credits to the final costs centers and includes a screenshot of the financial records in SAP.

G-1

To

tal 2

01

2 c

red

its t

o T&D

Intr

a-c

omp

an

y tr

an

sfe

rs f

rom

th

e S

ola

r P

ho

tovo

ltaic

Prog

ram

(S

PV

P) fo

r o

ng

oing

ma

inte

na

nce

exp

en

ses

TU

RN

-SCE

-07

7, Q

ue

stio

n 1

20

12

Proj

ect

Con

trac

tB

asis

Rat

e20

12m

onth

sM

onth

ly

amou

ntR

etro

activ

e ad

just

men

t *20

12as

sess

men

tSt

artin

g da

teEn

ding

da

teG

rapela

nd P

eake

rWDT

230

2,1

85,7

78.3

50.3

8%

12.0

08,3

05.9

699,6

71.5

27/5/0

7

Cent

er

Peake

rWDT

229

1,9

85,9

89.7

70.3

8%

12.0

07,5

46.7

790,5

61.2

47/1

1/0

7

Mira L

om

a P

eake

rWDT

231

1,7

76,7

04.6

40.3

8%

12.0

06,7

51.4

881,0

17.7

67/2/0

7

Barr

e P

eake

rWDT

236

1,7

28,0

68.3

10.3

8%

12.0

06,5

66.6

678,7

99.9

27/9/0

7

McG

rath

Peake

rWDT

233

1,7

34,0

00.0

00.3

8%

4.4

26,5

89.2

029,1

20.0

18/1

8/1

2

SP

VP

001 -

San

Bern

ard

ino

WDT

293

68,0

62.5

10.3

8%

6.7

7258.6

41,7

52.0

88/2

3/0

87/2

5/1

2

SP

VP

002 -

Chi

noWDT

327

74,6

45.4

90.3

8%

12.0

0283.6

53,4

03.8

010/2

9/0

9

SP

VP

003 -

Ria

ltoWDT

347

207,5

91.6

10.3

8%

12.0

0788.8

59,4

66.2

07/2

8/1

0

SP

VP

005 -

Redla

nds

WDT

351

37,4

82.1

00.3

8%

12.0

0142.4

31,7

50.5

43,4

59.7

012/2

3/1

0

SP

VP

006 -

Ont

ario

WDT

358

49,1

20.0

40.3

8%

12.0

0186.6

62,2

39.9

212/2

2/1

0

SP

VP

007 -

Redla

nds

WDT

352

39,8

23.2

60.3

8%

12.0

0151.3

31,8

15.9

612/2

3/1

0

SP

VP

008 -

Ont

ario

WDT

359

18,6

43.1

10.3

8%

12.0

070.8

4850.0

8

12/2

2/1

0

SP

VP

009 -

Chi

noWDT

356

115,6

38.6

10.3

8%

12.0

0439.4

35,2

73.1

612/2

2/1

0

SP

VP

010 -

Font

ana

WDT

360

75,0

00.0

00.3

8%

12.0

0285.0

03,4

20.0

04/2

2/1

1

SP

VP

011 -

Redla

nds

WDT

363

121,0

00.0

00.3

8%

12.0

0459.8

05,5

17.6

010/2

3/1

1

SP

VP

012 -

Ont

ario

WDT

364

57,1

36.1

50.3

8%

12.0

0217.1

22,6

05.4

412/2

2/1

0

SP

VP

013 -

Redla

nds

WDT

365

65,0

00.0

00.3

8%

12.0

0247.0

02,9

64.0

08/2

8/1

1

SP

VP

015 -

Font

ana

WDT

367

138,0

00.0

00.3

8%

12.0

0524.4

0456.7

46,7

49.5

412/4/1

1

SP

VP

016 -

Redla

nds

WDT

373

516,0

00.0

00.3

8%

12.0

01,9

60.8

014,6

74.3

738,2

03.9

75/1

6/1

1

SP

VP

017 -

Font

ana

WDT

374

119,0

00.0

00.3

8%

12.0

0452.2

05,4

26.4

011/2

3/1

1

SP

VP

018 -

Font

ana

WDT

375

83,2

65.5

70.3

8%

12.0

0316.4

1(2

,459.2

3)

1,3

37.6

95/1

5/1

1

SP

VP

022 -

Redla

nds

WDT

378

33,8

66.3

70.3

8%

12.0

0128.6

91,5

44.2

811/1

5/1

0

SP

VP

023 -

Font

ana

WDT

384

126,7

70.0

00.3

8%

11.0

3481.7

35,3

14.5

71/3

1/1

2

SP

VP

026 -

Ria

ltoWDT

387

85,0

00.0

00.3

8%

12.0

0323.0

03,8

76.0

08/2

7/1

1

SP

VP

028 -

San

Bern

ard

ino

WDT

389

112,0

00.0

00.3

8%

12.0

0425.6

0288.3

15,3

95.5

112/1

0/1

1

SP

VP

032 -

Ont

ario

WDT

450

122,0

00.0

00.3

8%

12.0

0463.6

05,5

63.2

012/1

0/1

1

SP

VP

033 -

Ont

ario

WDT

451

147,0

00.0

00.3

8%

12.0

0558.6

06,7

03.2

012/1

0/1

1

SP

VP

042 -

Port

erv

ille

WDT

461

159,0

00.0

00.3

8%

12.0

0604.2

07,2

50.4

012/2

8/1

0

SP

VP

044 -

Perr

isWDT

462

184,4

45.0

00.3

8%

3.6

3700.8

92,5

46.5

79/1

2/1

2

Moun

tain

view

added f

aci

litie

sT

OT

004

1,5

42,8

92.0

10.3

8%

12.0

05,8

62.9

970,3

55.8

87/9/0

7

Fue

l Cell

WDT

658

41,9

00.0

00.3

8%

5.4

2159.2

2862.8

7

7/1

9/1

2

Tota

l583,0

68.4

7

* R

etr

oact

ive a

dju

stm

ent

s fo

r 2011 a

nd p

rior

years

.

Min

or c

alcu

latio

n di

ffere

nce

of $

13.9

7

G-2



To: DRAPrepared by: Anthony Kurpakus



Question C.01:


Solar, SCE 02, Volume 10

C.1. Provide additional explanation for the derivation of $24,310/MW forecast shown in the column titled "Revised Allocation" in Table III.3. (confidential testimony, p 14)

Response to Question C.01:

In Table III-3, the $24,310/MW is based on the 2015 Test Year SPVP O&M, not including the Roof Lease costs. It is calculated by using the 2015 O&M forecast divided by the Solar AC Megawatt capacity. The calculation from the table is: $2.212 M, times 1 Million , divided by 91 MW, equals $24,308 /MW ($2.212M*1,000,000/91MW =$24,308/MW). The difference between the calculated $24,308/MW and the $24,310 from the table is due to rounding. Additional information has been provided to show the derivation of the 2015 test year expense forecast. See the attached file, "Solar 2015 GRC O&M Detail".

G-3

2012$

FERC

�Accou

ntDe

scrip

tion

2015�Expen

seForecast�Assum

ptions

FERC

�550

Leases

��2,187,800�Leases�increase�with

�GRC

�esc.

FERC

�549

Mainten

ance�Labor

��554,800�6.5�Em

p�FTE

FERC

�549

Equipm

ent/Spare�Parts/Co

nsum

ables

��506,000�Spares,�electrical�parts,�etc.

FERC

�549

Contract�Services

��186,000�2�Co

ntract�hire

s,�Inverter�M

aint.

FERC

�549

Investigations�and

�Rep

airs

��164,000�Ro

of�su

rveys�&

�Inspectio

n,�engineerin

g

FERC

�549

Testing

��265,000�Thermograph

y,�DGA

,�Meter�re

cert.

FERC

�549

Mon

itorin

g�and�Re

porting�

��50,000�

USM

�2013,�Emmerson�2014

FERC

�549

Adde

d�Facility�Co

sts

��25,00

0�T&

D�Intercon

nection

FERC

�549

Telecommun

ications

��46,000�

Telecom,�ISP�Emerson

FERC

�549

Equipm

ent�R

entals

��150

,000

�Manlifts,�toilets,�trailers

FERC

�549

Transportatio

n��60,00

0�SCE�trucks,�equ

ipmen

tFERC

�549

Training

��30,000�

training�fo

r�mainten

ance�

FERC

�549

Vegetatio

n�Managem

ent

��27,000�

Grou

nd�sy

stem

s,�permits

FERC

�549

Other�costs

��150,000�theft,�vand

alism

Total

��4,401,600�

2012$

Solar�F

orecast

2015

FERC

�549

Labo

r554,800

��

Non

�Labor

1,659,000

��

Sub�total

2,21

3,80

0��

�See�Figure�III�3,�Page�15�Testim

ony

FERC

�550

Leases

2,187,800

��


ony

Total

4,401,600

��

SOLA

R�FO

RECA

ST�O&M��2015�GRC

G-4



To: DRAPrepared by: Michele Farrell

Title: Project ManagerDated: 09/06/2013


Question C.01:


From Verbal-010-C.01, “Show the derivation of each individual estimate…..” Is the 2015 forecast based on 2012 recorded then escalated to 2015? If so provide 2012 recorded and escalation rates. If not, provide process for forecasts.

Response to Question C.01:

Per phone call with DRA on September 6, 2013, SCE is providing further information on the basis for the 2015 O&M forecast. Please see the attached Excel spreadsheet, "Solar 2015 GRC O&M Forecast Detail.xlsx". The 2015 forecast is based on 2012 recorded costs in part, but is substantially lower due to completion of the construction phase of the program in 2013. The forecast for 2015 reflects ongoing O&M for the installed equipment, as well as lease payments for the installation sites.

G-5

Costs�b

elow

�are�in�Con

stan

t�2012�Dollars�

FERC

�Accou

ntDe

scrip

tion

2015�Expen

seForecast�Assum

ptions

Cost�Basis

FERC

�550

Leases

��2,18

7,80

0�Leases�increase�with

�GRC

�escalation

Based�on

�existing�lease�agreem

ent s

FERC

�549

Mainten

ance�Labor

��55

4,80

0�6.5�Em

p�FTE

Based�on

�forecast�labo

r�req

uiremen

ts

FERC

�549

Equipm


nsum

ables

��50

6,00

0�Spares,�electrical�parts,�etc.

Estim

ate�of�SCE

�field�pe

rson

nel�based

�on�expe

rience,�

extrapolated

�to�fu

ll�nu

mbe

r�of�installatio

nsFERC

�549

Contract�Services

��18

6,00

0�2�Co

ntract�hire

s�for�Inverter�M

aint.

Based�on

�201

2�recorded

�costs

FERC

�549


�Rep

airs

��16

4,00

0�Ro

of�su

rveys�&

�Inspectio

n,�engineerin

gEstim

ate�of�SCE

�field�pe

rson

nel�based

�on�expe

rience,�

extrapolated

�to�fu

ll�nu

mbe


ns

FERC

�549

Testing

��26

5,00

0�Thermograph

y,�DGA

,�Meter�re

cert.

Estim

ate�of�SCE

�field�pe

rson

nel�based

�on�expe

rience,�

extrapolated

�to�fu

ll�nu

mbe


ns

FERC

�549

Mon

itorin

g�and�Re

porting�

��50,00

0�Em

erson�system

Based�on

�201

2�recorded

�costs,�extrapo

lated�to�fu

ll�nu

mbe

r�of�

installatio

nsFERC

�549

Adde

d�Facility�Co

sts

��25,00

0�T&

D�Intercon

nection

Based�on

�recorded

�cost s

FERC

�549

Telecommun

ications

��46,00

0�Telecom,�ISP�Emerson

Based�on

�201

2�recorded

�costs,�extrapo

lated�to�fu

ll�nu

mbe

r�of�

installatio

ns

FERC

�549

Equipm

ent�R

entals

��15

0,00

0�Manlifts,�toilets,�trailers

Based�on

�201

2�recorded

�costs,�extrapo

lated�to�fu

ll�nu

mbe

r�of�

installatio

ns

FERC

�549

Transportatio

n��60,00


ipmen

tBa

sed�on

�201

2�recorded

�costs,�extrapo

lated�to�fu

ll�nu

mbe

r�of�

installatio

ns

FERC

�549

Training

��30,00

0�Training�fo

r�mainten

ance�&�ope

ratio

nSCE�estim

ate�based�on

�experience,�adjusted�for�n

umbe

r�of�

mainten

ance�FTE

FERC

�549

Vegetatio

n�Managem

ent

��27,00

0�Grou

nd�sy

stem

s,�permits

Based�on

�201

2�recorded

�costs,�extrapo

lated�to�fu

ll�nu

mbe

r�of�

installatio

ns

FERC

�549

Other�costs

��15

0,00

0�Theft,�vand

alism

Estim

ate�of�SCE

�field�pe

rson

nel�based

�on�expe

rience,�

extrapolated

�to�fu

ll�nu

mbe


nsTo

tal

��4,40

1,60

0�

Costs�b

elow

�are�in�Con

stan

t�2012�Dollars�

Solar�F

orecast

2015

FERC

�549

Labo

r55

4,80

0��

Non

�Labor

1,65

9,00

0��

Sub�total

2,21

3,80

0��

�See�Figure�III�3,�Page�15

�Testim

ony

FERC

�550

Leases

2,18

7,80

0��

�See�Figure�III�4,�Page�17

�Testim

ony

Total

4,40

1,60

0��

G-6



To: DRAPrepared by: Anthony Kurpakus



Question A.01:


A.1. Regarding DRA-Verbal-10 Q.C.01 - and subsequent response Verbal 13-Q.C.01 - Provide additional information to support attachment 01 regarding the statements “Estimate of SCE field personnel based on experience, extrapolated to full number of installations,” “Based on existing lease agreements” and “Based on forecast labor requirements.” Per D. 07-07-004 the Standard requirement List of Documentation Supporting and NOI “Show the derivation of each individual estimate.” If SCE has already provided any of the above information direct DRA to where the information is contained.

Response to Question A.01:

Attached is an Excel spreadsheet that contains calculations for the individual forecast line items. Note that an error was discovered for the roof leases, which reduces our test year forecast for FERC Account 550 by $103,349. This reduction will be reflected in the Application testimony and Workpapers. The attached file will be included in the Application workpapers.

G-7

FERC

�Accou

ntDe

scrip

tion

2015�Forecast�E

xpen

seForecast�Assum

ptions

Cost�Basis

FERC

�550

Leases

��2,084,451�

Leases�increase�with

�GRC

�escalation

Based�on

�existing�lease�agreem

ents

FERC

�549

Mainten

ance�Labor

��554,800�

5.5�Em

ployee�FTE

Based�on

�forecast�labo

r�req

uiremen

ts

FERC

�549

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ll�nu

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Contract�Services

��186,000�

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Mainten

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�costs�and

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aterials

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�549


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��164,000�

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�549

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��265,000�

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ate�of�SCE

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ll�nu

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ns

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ate�of�SCE

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�549

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icles�a

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�549

Training

��5,000�

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r�mainten

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umbe

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FTE

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�549

Land

scaping�and�Security�Managem

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��27,00

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ber�o

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ns

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�549

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��150,000�

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,�etc.

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�forecasted

�costs�fo

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ns

Total

��4,298,251�

SPVP

�Forecast

2015

FERC

�549

Labo

r554,800

��

Non

�Labor

1,659,000

��

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2,21

3,800

��


ony

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�55 0

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2,084,451

��


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4,298,251

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��2015�GRC

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.Pu

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�ACC

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ENSES�FO

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Expe

nse�Ca

tegory

SPVP

�Num

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Cost�Elem

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001

6120085

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se611160

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6120085

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se611161

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6120085

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se611162

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6120085

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se611163

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6120085

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6120085

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se611165

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6120085

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se611166

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6120085

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se611167

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6120085

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se611168

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6120085

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se611240

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6120085

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se611169

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6120085

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g�Land

�&�Facilitie

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se611241

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6120085

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se611170

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6120085

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g�Land

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t�Expen

se611242

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6120085

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g�Land

�&�Facilitie

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t�Expen

se611171

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6120085

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g�Land

�&�Facilitie

s�Ren

t�Expen

se611172

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6120085

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g�Land

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t�Expen

se611173

026

6120085

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g�Land

�&�Facilitie

s�Ren

t�Expen

se611174

028

6120085

Ope

ratin

g�Land

�&�Facilitie

s�Ren

t�Expen

se611244

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6120085

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ratin

g�Land

�&�Facilitie

s�Ren

t�Expen

se611245

033

6120085

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g�Land

�&�Facilitie

s�Ren

t�Expen

se611246

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6120085

Ope

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g�Land

�&�Facilitie

s�Ren

t�Expen

se611175

044

6120085

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g�Land

�&�Facilitie

s�Ren

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se611192

045

6120085

Ope

ratin

g�Land

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s�Ren

t�Expen

se611193

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nse�no

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Lease�To

tal

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044

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611192

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611193

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Grand

�Total

Total�Recorde

dLess

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5Re

corded

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corded

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corded

�Expen

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ot�in�201

2

$2,084,451

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5�TY�Leases

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mission

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.

2015

#�of�Personn

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1Manager�Program

/Project�2

$140,000

$140,000

1Supe

rviso

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$100,000

2Instrumen

t�Con

trol�Electrician�Technician

$85,000

$170,000

1Ope

rator�M

echanic

$85,000

$85,000

0.5

Engine

ering�Supp

ort

$119,600

$59,800

5.5

$554,800

O&M�Staff�fo

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eration

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�$20

122015�LAB

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�2012�Expe

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$63,067

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$454,416

Site�M

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282

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W�in�2012

5,536

$��

2015�M

W91.42

Forecast�fo

r�2015

506,063

$��

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.

Recorded

�Inverter�Costs�from

�201

2Inverter�m

ainten

ance

$111,857

Add:�

Inverter�re

pair�parts�(forecast)

$55,000

Total

$166,857

Site�M

W�in�201

282

.09

Cost�per�M

W�in�2012

2,033

$��

2015�M

W91.42

Forecast�fo

r�2015

185,821

$��

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Roof�Survey/inspectio

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airs

$40,00

0Num

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f�roo

ftop

s3

$120,000

Forecast�fo

r�2015

$163,200

*��SCE

�has�25�sites,�but�one

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SOLA

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12

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�Testin

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$225,000

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Num

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f�site

s25

$30,000

Meter�Recertification

$500

Num

ber�o

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�transformers

25$12,500

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r�2015

$267,500

SOLA

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$3,000

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G-15

2012�Recorded�Added�Facility�Costs

Site Monthly�Charge MWSPVP001SGIA�Facilities�Charge $259 2.44

SPVP002SGIA�Facilities�Charge $284 1.22







SPVP010SGIA�Facilities�Charge $285 2.25SPVP011SGIA�Facilities�Charge $460 5.02��




SPVP016SGIA�Facilities�Charge $1,961 1.75












Total�Monthly�Charge $11,472 84.30��

Annual�Cost�per�MW�in�2012 1633.06Total�MW�in�2015 91.42

Forecast�for�2015 $149,294

SOLAR�PHOTOVOLTAIC�PROGRAM2015�ADDED�FACILITY�EXPENSE

ALL�COSTS�SHOWN�IN�$2012

G-16

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$41,226

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Cost�per�M

W�in�2012

502

$��

Site�M

W�in�201

591

.42

Forecast�fo

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45,912

$��

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stNum

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4$45,400

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er�year

$3,600

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f�veh

icles

4$14,400

Forecast�fo

r�2015

$59,800

SOLA

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G-19

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$1,000

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5Forecast�fo

r�2015

$5,000

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�and

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$1,000

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$25,000

Land

scaping�for�G

roun

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nt�Site

$2,000

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scaping��Costs

$2,000

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�and

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�Costs

$27,00

0

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xpected�expe

nses

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$6,000

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$150,000

SOLA

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12

G-22



To: DRAPrepared by: Serge Handschin

Title: Manager-Project/Product 2Dated: 02/27/2014


Question 07:



Subject: Solar


7. Provide the itemized forecast for “SCE’s forecast cost for the Inspection and Maintenance for items (1)-(5) below is $19,240 per MW DC ($2012), and was calculated based on an itemized forecast. (SCE-02, Vol. 10, p. 11)” Include the basis for each component of the itemized forecast.


The itemized forecast being referenced is not for the five categories discussed in Testimony pages 11-12 per se. Rather, the total combined cost of these five categories was estimated using the itemized forecast that is presented in the table on page 18b of workpapers. Specifically, the total of the second through the seventh items listed in WP18b provides the $19,240 per MW DC total cost for the five items discussed in Testimony pages 11-12. This is more clearly shown in the attached spreadsheet, which provides the forecast data for the second through seventh items (i.e., six items total) from WP18b, including the dollars per MW DC for these six items.

G-23

IAL

FERC

�Ac

coun

tDe

scrip

tion

2015

�Forecast�E

xpen

se$/MW�(b

ased

�on

�91�MW�DC)

Forecast�Assum

ptions

Cost�Basis

FERC

�549

Mainten

ance�Labor

��55

4,80

0��6,09

7�5.5�Em

ployee�FTE

Based�on

�forecast�labo

r�req

uiremen

ts

FERC

�549

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nsum

ables

��50

6,00

0��5,56

0�Spares,�electrical�parts,�etc.

Estim

ate�of�SCE

�field�pe

rson

nel�based

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�costs�

and�expe

rience,�extrapo

lated�to�fu

ll�nu

mbe

r�of�

installatio

ns

FERC

�549

Contract�Services

��18

6,00

0��2,04

4�2�Co

ntract�hire

s�and

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ainten

ance

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�costs�and

�forecast�of�m

aterials

FERC

�549


�Rep

airs

��16

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of�su

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�Inspectio

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ering

Estim

ate�of�SCE

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rience,�

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ll�nu

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FERC

�549

Testing

��26

5,00

0��2,91

2�Thermograph

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,�Meter�

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Estim

ate�of�SCE

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�549

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4�Ve

rizon

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stem

Based�on

�forecasted

�costs�fo

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f�installatio

ns

Total

��1,750

,800

��19

,240

�

SOLA

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MITEM

IZED

�INSPEC

TION�AND�MAINTENAN

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AST�BY

�ACT

IVITY��2

015�GRC

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STS�SH

OWN�IN

�$2012

G-24






Question 02.b:



Subject: Solar/Non-Nuclear Generation


2. In response to DRA-202-PM1 Q. 03 supplemental, SCE stated: “SCE incurred a $10.1 million termination fee, which recorded in 2011 to expense.” Regarding the $10.1 million paid provide the following:

b. Did SCE bring this to the attention of the Commission? If not, why not? If yes, provide copies of the communication informing the Commission about the breach of contract and the $10.1 million SCE would incur including dates.


There are no known requirements for SCE to formally communicate, to the Commission, SCE’s decision to exercise specific terms of its contract (Master Service Agreement) with SunPower. SCE terminated the Agreement, with respect to the unordered portion of the Supply, because it was no longer economical to customers to continue with this portion of the Agreement. The Agreement committed SCE to purchase panels at a unit price of over $2/Wp. Market prices for SunPower panels had dropped to below $2/Wp. Forecasted costs were expected to be $1/Wp or below by 2014.

A copy of the MSA is provided as part of the response to Q4.

G-25






Question 04:



Subject: Solar/Non-Nuclear Generation


4. In response to DRA-202-PM Q. 03 supplemental SCE stated: “SCE incurred a $10.1 million termination fee, which recorded in 2011 to expense, to reduce the contracted amount of solar panels to be provided by a panel supplier for the program,” Was the contract referred to above approved by the Commission? If not why not? If yes, provide an exact citation to where the Commission approved the contract (please also provide a copy of the contract itself, including any amendments to the contract).


The Commission authorized SCE to build the SPVP projects and recover the costs in rates in D.09-06-04. As in virtually all other utility managed projects, the Commission does not approve the actual individual contracts for materials and supplies and did not do so in this case.

SCE is assuming that ORA is requesting a copy of the contract regardless of Commission approval and has therefore provided a copy, with amendments, for ORA review.

See Attached MSA, Amendments 1 and 2, and Notice of Termination.

G-26

CONFIDENTIAL Protected Materials Pursuant to California Public Utilities Commission Decisions and Applicable Law. -Public Disclosure Restricted-

G-27


G-28


G-29


G-30


G-31






Question 01.b:



Subject: Non-Nuclear Global


1. In SCE’s response to DRA-202-PM1, Q 12a SCE states “The adjusted final figure of approximately $26.0 million (i.e., in nominal dollars) represents all 2008-2012 recorded expense including roof lease expense and a 2011, $10.1 million contract termination fee to reduce the contracted amount of solar panels to be provided by a panel supplier for the program.”

b. If SCE’s justification for recording the $10.1 million contract termination fee as an O&M expense is based on any specific statute, case, decision, rule, order or other authority, please identify what that authority is.


The determination above was based on GAAP guidelines as they relate to how an asset is defined per paragraph 25 of "Statement of Financial Accounting Concepts No 6-Elements of Financial Statements."

G-32

Line�# Description2015�Forecast�

ExpenseForecast�Assumptions Comment

1 Maintenance�Labor ��342,300� 3�Employee�FTEExpenses�borne�by�SCE:�1�Project�Manager;�1�Supervisor;�0.5�Operator�Mechanic;�and�0.5�Engineer

2Equipment/Spare�Parts/Consumables

�0�506,000� Spares,�electrical�parts,�etc.Estimate�based�on�SCE's�involvment�with�providing�equipment,�spare�parts�and�consumables

3 Investigations�and�Repairs �0�164,000�Roof�surveys�&�Inspection,�engineering

Estimate�based�on�SCE's�involvment�during�investigations�and�repairs

4 Testing �0�265,000� Meter�recert.Estimate�based�on�SCE's�involvment�regarding�meter�testing

5 Monitoring�and�Reporting� ��75,000� Verizon�telemetry�system Expenses�borne�by�SCE,�not�the�contractor

6 Added�Facility�Costs ��150,000� T&D�Interconnection Expenses�borne�by�SCE,�not�the�contractor

7 Telecommunications ��46,000� Telecom,�ISP� Expenses�borne�by�SCE,�not�the�contractor

8 Equipment�Rentals ��25,000� Manlifts,�toilets,�trailers Expenses�borne�by�SCE,�not�the�contractor

9 Transportation� ��60,000� SCE�trucks,�equipment Expenses�borne�by�SCE,�not�the�contractor

10 Training ��5,000�Training�for�maintenance�&�operation

Expenses�borne�by�SCE,�not�the�contractor

11Landscaping�and�Security�Management

��27,000� Ground�systems,�fencing Expenses�borne�by�SCE,�not�the�contractor

12 Other�costs ��150,000� Theft,�vandalism,�etc. Expenses�borne�by�SCE,�not�the�contractor

13Subtotal�

(Rows�2�4,�assuming�5%�SCE�Involvement)

��46,750�

14Subtotal�

(Excluding�Rows�2�4)��880,300�

15 Total ��927,050�

SPVP�Forecast 2015FERC�549

Labor 342,300��Non�Labor 538,000��Sub�total 880,300��

2015#�of�Personnel Annual Forecast

1 ger�Program/Project�2 $140,000 $140,0001 Supervisor�3 $100,000 $100,0000 Electrician�Technician $85,000 $00.5 Operator�Mechanic $85,000 $42,5000.5 Engineering�Support $119,600 $59,8003 $342,300

SOLAR�PHOTOVOLTAIC�PROGRAM

SCE's�FORECAST�O&M�EXPENSES�NOT�COVERED�IN�A�THIRD�PARTY�O&M�CONTRACTALL�COSTS�SHOWN�IN�$2012

G-35

DATA REQUEST SCE-TURN-002

Southern California Edison TY 2015 GRC

Date: August 19, 2014

Responses Due:

ResponsesProvided:

September 3, 2014

August 28, 2014

To: William B. Marcus

Originated by: Martin Collette General Rate Case Manager Southern California Edison Company 2244 Walnut Grove Avenue Rosemead, CA 91770 [email protected] (626) 302-3408

Data Request No: SCE-TURN-002

Please provide the following items:

Exhibit Ref: TURN-05

1. Regarding the testimony of William B. Marcus in TURN-05, please provide a workpaper supporting the calculation for TURN’s figure of $124,457 on Page 22, with specific cites to all data derived from SCE workpapers, data request responses, and/or other SCE documents.

Response:See Edison’s attachment to TURN DR 77-01a, with annualization calculations made by TURN. TURN inadvertently included $1,910 in fuel cell special facilities charges in the number cited in the request. The photovoltaic number is $122,547.

Provide electronic responses if possible, and set of hard copy responses with your submittal to the SCE Case Manager and the data request originator. All data responses need to have each page numbered, referenced, and indexed so worksheets can be followed. If any number is calculated, include a copy of all electronic files so the formula and their sources can be reviewed.

G-36

If you have any questions regarding this DR, please call originator at above phone #.

G-37

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G-41

Savings�Based�on�Remaining�SunPower�MSA�Capacity

Line�# Supplier

Remaining�Capacity�on�

SunPower�MSA

Total�Estimated�Cost

per�Agreement�(Nominal�$)

1 SunPower2 Alternate�Supplier3 Termination�Savings 203,688,190

Realized�Savings�Final�Program�Size�(91.4�MW�DC)

Line�# Supplier

Remaining�Capacity�Following�Contract�

Termination�(MW)

Total�Estimated�Cost

per�Agreement�(Nominal�$)

1 SunPower2 Alternate�Supplier3 Termination�Savings 12,549,900

CONFIDENTIAL Protected Materials Pursuant to California Public Utilities Commission Decisions and Applicable Law.-Public Disclosure Restricted-

G-43

Cost�savings�for�terminating�Sun�Power�purchase�agreement

MW�DCOriginal�Program�Size 250.0Original�SunPower�MSA�Capacity 200.0Final�Program�Size 91.4Total�commited�capacity�at�termination 82.0Committed�SunPower�Purchases 51.1Remaining�Committed�Capacity�Based�on�SunPower�MSA 148.9Remaining�Capacity�Based�on�Final�Program�Size 9.4

Savings�Based�on�Final�Program�Size�(91.4�MW�DC)

Supplier

Remaining�Capacity�(MW)

Module�Price�Per�Agreement

($/W)Total�Estimated�Costper�Agreement�($)

TrinaContracted�Module�Cost MW $/W Basis

Trina 1Q2013 Amendment�8Trina 4Q2012 Amendment�7Total�Trina 3Q2012 Amendment�7

3Q2011 Amendment�44Q2010 Amendment�1

SunPower 3Q2010 Amendment�12Q2010 Amendment�1

Savings�(91.4�MW�Program) 12,549,900

Supplier

Remaining�Capacity�

Module�Price�Per�Agreement Total�Estimated�Cost

TrinaTrinaTrina Assumption:�Module�price�for�remaining�139.5�MW�would�be�Total�Trina ��the�same�as�last�negotiated�price.

SunPower

Savings�(Cancelled�SunPower�Deliveries) 203,688,190

Savings�Based�on�Program�Size�at�the�Time�Agreement�was�Terminated�(250�MW�DC)


G-44


G-45


G-46


G-47


G-48


G-49


G-50


G-51


G-52


G-53


G-54


G-55

SunPower Corporation


G-56


G-57

Appendix H

Fuel Cell Program


Chapter IX – Fuel Cell Program

Appendix H – Index

Document Page

SCE Response to DRA-036-PM1, Question 3 – CONFIDENTIAL H-1

Attachment 1 to DRA-036-PM1, Q. 3, Pages 1 and 13 – CONFIDENTIAL H-4

SCE Response to DRA-217-PM1, Question 1 H-6

Attachment to DRA-217-PM1, Question 1 – CONFIDENTIAL H-7



To: DRAPrepared by: Deanne K Nelsen



Question 03:


Exhibit Reference: SCE-02, V. 10

Subject: Fuel Cell


3. Identify all contracts, terms of contracts and signed contracts themselves, SCE has entered into for long-term (or short-term if applicable) maintenance of its fuel cell facilities.


CONFIDENTIALProtected Materials Pursuant to California Public Utilities Commission Decisions and

Applicable Law. -Public Disclosure Restricted-

H-1

2.

H-3

�� !"�

# ��$��#�

H-4

�� !"�

# ��$��#�

H-5



To: DRAPrepared by: Deanne K. Nelsen



Question 01:



Subject: Fuel Cell


1. Provide a breakdown of the costs listed on Table V-6 (SCE-02, Vol. 10, p. 31) for each component (with UCSB and CSUSB delineated separately and a line for each item below where SCE forecasts expenses in 2015) SCE forecasts to pay in 2015, including but not limited to the following: long term service agreements, landscaping, telecommunications, data services interconnection facilities charges, water treatment system service agreement, site maintenance service agreements, and air quality permit certification and renewal. For each component, provide calculations of how SCE determined forecast expense levels, including citations to the exact wording from contracts (pages, paragraphs, lines) where calculations are defined. If the sum of all above components is not equal to the totals listed on Table V-6 (SCE-02, Vol. 10, p.31), identify additional items (including forecast 2015 expenses).


See the attached spreadsheet: DRA_217_PM1_Q1_Response Table (Confidential).xlsx.

H-6

CONFIDENTIALProtected�Materials�Pursuant�to�California�Public�Utilities�Commission�Decisions�and�Applicable�Law.��


Fuel Cell Location Cost Category Data Source and Forecast Details 2015 Forecast

DRA��217��PM1�Q1�Response

2015�Fuel�Cell�O&M�Forecast�Details�

H-7

Appendix I

Catalina


Chapter X – Catalina

Appendix I – Index

Document Page

SCE Response to TURN-098, Question 5(a) I-1

SCE Response to TURN-098, Question 5(b) I-2



To: TURNPrepared by: Martin Collette

Title: Regulatory ManagerDated: 06/18/2014


Question 05.a:


SCE-02, Volume 10 (Generation – Solar PV, Fuel Cell, and Catalina) Catalina

5. Following up on TURN DR 52-16 regarding the Pebbly Beach Generating Station Automation Project:

a. Please explain when the decision was made to suspend work on the project and provide a more detailed explanation of why the decision was made to suspend work.


SCE suspended work on the Automation project in mid-2012 as a result of concerns with availability of funding due to the late 2012 GRC decision and as a result of the increased costs being incurred with the redesign of the project and the coordination and implementation with the SCAQMD settlement and associated facilities. As discussed in the testimony and the response to Question 6.e, the project was later delayed to allow for completion of other projects which impacted the scope, sequencing and implementation of the Automation Project. During this year, project managers that normally would have been assigned to this project have been dedicated to other high priority projects on Catalina Island.

I-1



To: TURNPrepared by: Kevin Shimmel



Question 05.b:


SCE-02, Volume 10 (Generation – Solar PV, Fuel Cell, and Catalina) Catalina

5. Following up on TURN DR 52-16 regarding the Pebbly Beach Generating Station Automation Project:

b. What is Edison’s policy regarding the suspension of AFUDC when work is suspended on a project?


SCE's plant accounting system can manually turn off AFUDC accruals with notification from Field Accountants of a suspended work order. Additionally, SCE's plant accounting system will automatically turn off AFUDC accruals after a work order remains idle for six months (i.e., no charges in the work order for a continuous six months). On the seventh month AFUDC accruals are turned off and no additional AFUDC will be charged until work order activity resumes. For example, if all work order charges stop in January, AFUDC accruals will continue until July when the AFUDC automatic shutoff will be triggered.

I-2

document in exhibit...s. handschin j. rumble j. tran t. ware (u 338-e) 2015 general rate case...

Documents